Canetic Resources Trust announces strong year-end operating and financial results and reserves for 2006



    CALGARY, March 8 /CNW/ - (CNE.UN - TSX; CNE - NYSE) - Canetic Resources
Trust ("Canetic" or the "Trust"), is pleased to announce its operating and
financial results for the fourth quarter and year ended December 31, 2006 as
well as selected information from Canetic's independent engineering reserve
report effective December 31, 2006. The year 2006 marked another pronounced
period of growth and change for Canetic with the successful closing of two
significant acquisitions totaling $3.5 billion and its listing on the New York
Stock Exchange on February 15, 2006. These targeted acquisitions served to
more than double production and reserves of Acclaim Energy Trust (Acclaim),
Canetic's predecessor, on a stand-alone basis, while also significantly
increasing the undeveloped land base and inventory of exploitation
opportunities that will fuel Canetic's development and growth in the coming
years.

    
    HIGHLIGHTS OF CANETIC'S YEAR INCLUDE:

    -   Annual production averaged approximately 74,409 barrels of oil
        equivalent (boe) per day for 2006, an increase of 84 percent from
        40,460 boe per day in 2005. Production in the fourth quarter totaled
        80,276 boe per day compared to 74,475 boe per day in the third
        quarter of 2006. Canetic exited 2006 with production of more than
        82,000 boe per day which is in line with previous guidance.

    -   Completion of the largest and most active exploitation and
        development program in Canetic history at $351.3 million. Canetic's
        2006 development program resulted in the drilling of 378 gross
        (174.4 net) wells with an overall success rate of 98 percent.

    -   Canetic's total capital program, including the Samson Canada Ltd.
        (Samson) acquisition, replaced 237 percent of 2006 production on a
        proved plus probable basis at a finding, development and acquisition
        (FD&A) cost of $20.41 per boe, excluding future development capital
        and $23.30 per boe including future development capital.

    -   Canetic's internal development program replaced 76 percent of 2006
        production on a proved plus probable basis at a finding and
        development (F&D) cost of $16.93 per boe, excluding future
        development capital and $19.21 per boe including future development
        capital while spending less than 50 percent of funds flow from
        operations. The StarPoint Energy Trust (StarPoint) assets performed
        particularly well, resulting in replacement of 124 percent and
        106 percent of 2006 related production on a proved producing and
        proved plus probable basis, respectively.

    -   Canetic replaced 2006 production at an efficiency rate of $20,300 per
        boe per day based on 2006 exit rates. These very strong efficiencies
        were achieved during a period when the Trust was very active
        integrating the two large acquisitions completed in 2006.

    -   Proved plus probable reserves increased 16 percent to 275.6 million
        boe from 238.4 million boe (including StarPoint). Proved reserves
        increased 12 percent to 192.2 million boe. Proved producing reserves
        increased 15 percent to 157.1 million boe.

    -   Canetic's Reserve Life Index (RLI) increased 1.0 years to 9.7 years
        on a proved plus probable basis and 0.5 years to 6.8 years on a total
        proved basis.

    -   Canetic closed the previously announced acquisition of StarPoint
        effective January 5, 2006 forming one of Canada's largest oil and gas
        royalty trusts. The StarPoint acquisition served to significantly
        increase both production and reserves and create a portfolio of high
        quality assets characterized by large oil and gas in place, an
        extensive undeveloped land and opportunity base offering a dominant
        operating position and key exposure to some of the most notable plays
        in Canada, including coal bed methane (CBM) in central Alberta, tight
        gas in northern BC, shallow tight gas in southern Alberta, waterflood
        and tertiary recovery enhancement in Alberta and Saskatchewan and
        horizontal infill optimization.

    -   On August 31, 2006, Canetic closed the acquisition of primarily
        natural gas interests in central Alberta and northeastern British
        Columbia from Samson. The acquisition included production at closing
        of approximately 13,500 boe per day, comprised of 70.0 million cubic
        feet (mmcf) per day of natural gas and 1,600 barrels (bbls) per day
        of crude oil and natural gas liquids. At the time, the acquisition
        increased Canetic's overall production to more than of 80,000 boe per
        day and balanced Canetic's asset portfolio to 53 percent crude oil
        and natural gas liquids and 47 percent natural gas. The assets
        acquired were complementary to Canetic's existing properties and
        served to further expand Canetic's undeveloped land position by a
        considerable 230,000 net acres, to nearly 1 million net undeveloped
        acres.

    -   Canetic commissioned construction of a 20 mmcf per day gas processing
        plant at Willisden Green, which has been completed and will be
        brought on at full capacity late in the first quarter of 2007. The
        new gas plant is expected to alleviate capacity constraints and allow
        Canetic to further pursue its previously successful drilling
        activities in the surrounding area.

    -   Canetic generated funds flow from operations of $750.1 million
        ($3.64 per basic unit) in 2006 compared to $360.5 million
        ($4.04 per basic unit) in 2005. During the fourth quarter, funds flow
        from operations totaled $170.1 million ($0.76 per basic unit) an
        increase of 60 percent from $106.5 million ($1.16 per basic unit)
        realized in the same period last year. Funds flow reported for the
        third quarter of 2006 totaled $200.3 million ($0.95 per basic unit).
        The decrease in per unit fourth quarter and full year 2006 funds
        flow from operations compared with prior comparable periods was
        largely attributable to decreases in either crude oil or natural
        gas prices during the comparable period.

    -   Net earnings increased 239 percent to $223.1 million in 2006 compared
        to $65.8 million in 2005. On a per trust unit basis net earnings
        increased 46 percent to $1.08 per basic unit compared to $0.74 per
        basic unit in 2005.

    -   Cash distributions totaled $583.5 million in 2006 compared to
        $208.5 million in 2005, an increase of 180 percent. On a per unit
        basis cash distributions totaled $2.76 per unit ($0.23 per unit per
        month) in 2006 compared with $2.34 per unit ($0.195 per unit per
        month) in 2005. Canetic's payout ratio (defined as cash distributions
        to unitholders divided by funds flow from operations) averaged
        78 percent in 2006.

    -   Canetic's average realized price in 2006 was $51.52 per boe,
        including hedging, compared to an average price of 48.76 per boe,
        including hedging, in 2005. A decrease in natural gas prices was more
        than offset by higher prices for crude oil and natural gas liquids
        and lower hedging losses.

    -   Canetic listed its trust units for trading on the New York Stock
        Exchange and began trading under the symbol CNE on February 15, 2006.
    

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    A conference call to discuss these results will be hosted at 9 a.m. MST
    (11 a.m. EST) on Friday, March 9, 2007. The call will also be available
    via audio webcast from Canetic Resources Trust's website
    (www.canetictrust.com). To participate Toll-Free across North America
    call: 1-800-769-8320 or within Toronto and area call: 416-695-5259. A
    recorded playback of the call will also be made available until March 31,
    by calling toll-free across North America: 1-888-509-0081 or within
    Toronto and area call: 416-695-5275.

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    All references are to Canadian dollars unless otherwise indicated.
Natural gas volumes recorded in thousand cubic feet ("mcf") are converted to
barrels of oil equivalent ("boe") using the ratio of six (6) thousand cubic
feet to one (1) barrel of oil ("bbl"). BOE's may be misleading, particularly
if used in isolation. A BOE conversion ratio of 6 mcf: one (1) bbl is based on
an energy equivalent conversion method primarily applicable at the burner tip
and does not represent a value equivalent at the wellhead.

    FORWARD-LOOKING STATEMENTS
    --------------------------

    Certain statements contained in this news release constitute
forward-looking statements or information (collectively "forward-looking
statements") within the meaning of applicable securities laws. All statements
other than statements of historical fact may be forward looking statements.
Statements relating to "reserves" or "resources" are deemed to be
forward-looking statements as they involve the implied assessment, based on
certain estimates and assumptions, that the reserves and resources described
can be profitably produced in the future.
    The use of any of the words "anticipate", "continue", "estimate",
"expect", "may", "will", "project", "could", "should", "believe", "intend",
"propose", "budget" and similar expressions are intended to identify
forward-looking statements. These statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking statements.
We believe the expectations reflected in the forward-looking statements are
reasonable but no assurance can be given that these expectations will prove to
be correct and such forward-looking statements are not guarantees of future
performance and should not be unduly relied upon. These statements speak only
as of the date of this news release.
    In particular, this news release contains forward-looking statements
pertaining to the following: business strategies; production volumes and
capacity, processing capacity; reserves volumes, operating and other costs,
drilling plans; commodity prices; future cash distribution levels and
taxability; payout ratios; capital spending including timing, allocation and
amounts of capital expenditures and the sources of funding thereof; regulatory
changes; hedging and other risk management programs; anticipated tax
obligations; supply and demand for oil and natural gas; ability to raise
capital; ability to add to reserves through acquisitions and development;
treatment under governmental regulatory regimes; acquisition plans; the impact
of acquisitions and the timing for achieving such impact; future tax treatment
of income trusts such as the Trust; the benefits of the Trust's size and the
size of its inventory; and  liquidity and financial capacity.
    The forward-looking statements contained in this news release are based
on a number of expectations and assumptions that may prove to be incorrect. In
addition to other assumptions identified in this news release, assumptions
have been made regarding, among other things: that the Trust will continue to
conduct its operations in a manner consistent with past operations; the
continuance of existing (and in certain circumstances, proposed) tax and
royalty regimes; the general continuance of current industry conditions; the
accuracy of the estimates of the Trust's reserve volumes; the ability of
Canetic to obtain equipment, services and supplies in a timely manner to carry
out its activities; the ability of Canetic to market oil and natural gas
successfully; the timely receipt of required regulatory approvals; the ability
of Canetic to obtain financing on acceptable terms; currency, exchange and
interest rates; future oil and gas prices and future cost assumptions. No
assurance can be given that these factors, expectations and assumptions will
prove to be correct.
    The actual results could differ materially from those anticipated in
these forward-looking statements as a result of the risk factors set forth
below and elsewhere in this news release: volatility in market prices for oil
and natural gas; risks and liabilities inherent in oil and natural gas
including operations, exploration, development, exploitation, production,
marketing and transportation risks; uncertainties associated with estimating
oil and natural gas reserves; competition for, among other things, capital,
acquisitions of reserves, undeveloped lands and skilled personnel; incorrect
assessments of the value of acquisitions; inability to complete acquisitions
on commercially acceptable terms; inability to raise necessary capital on
commercially acceptable terms or at all; geological, technical, drilling and
processing problems; risks and uncertainties involving geology of oil and gas
deposits; unanticipated operating results or production declines; fluctuations
in foreign exchange, currency or interest rates and stock market volatility;
changes in laws and regulations changes including but not limited to those
pertaining to income tax, environmental and regulatory matters; failure to
realize the anticipated benefits of acquisitions; health, safety and
environmental risks; and the other factors described in Canetic's public
filings from time to time (including under "Risk Management" in the
Management's Discussion & Analysis (MD&A) included in this news release and
under "Risk Factors" in its Annual Information Form) available in Canada at
www.sedar.com and in the United States at www.sec.gov. Readers are cautioned
that this list of risk factors should not be construed as exhaustive.
    The forward-looking statements contained in this news release are
expressly qualified by this cautionary statement. Canetic undertakes no
obligation to publicly update or revise any forward-looking statements except
as expressly required by applicable securities law.

    Non-GAAP Measures
    -----------------

    This MD&A refers to certain financial measures that are not determined in
accordance with GAAP. These measures as presented do not have any standardized
meaning prescribed by Canadian GAAP and therefore they may not be comparable
with calculations of similar measures for other companies or trusts.
    Management uses funds flow from operations, which we define as net
earnings plus non-cash items before deducting non-cash working capital and
asset retirement costs incurred to analyze operating performance and leverage.
Readers should refer to the "Funds Flow from Operations" section of the MD&A
included in this news release for a reconciliation of funds flow from
operations.
    We use the term net debt, which we define as long-term debt and working
capital, to analyze liquidity and capital resources. Readers should refer to
the "Liquidity and Capital Resources" section of the MD&A for a reconciliation
of net debt.
    We use the term payout ratio, which we define as cash distributions to
unitholders divided by funds flow from operations, to analyze financial and
operating performance. Readers should refer to the "Cash Distributions"
section of the MD&A for the calculation of payout ratio.
    We use the terms operating and cash netbacks to analyze margin and cash
flow on each boe production. Operating and cash netbacks should not be viewed
as an alternative to cash flow from operating activities, net earnings per
trust unit or other measures of financial performance calculated in accordance
with GAAP. Readers should refer to the "Netbacks" section of the MD&A for a
reconciliation of operating and cash netbacks.
    We use the term total capitalization, which we define as net debt
including convertible debentures plus unitholders' equity, to analyze
leverage. Total capitalization is not intended to represent the total funds
from equity and debt received by the Trust. Readers should refer to the
"Liquidity and Capital Resources" section of the MD&A for a reconciliation of
total capitalization.
    Management believes that, in conjunction with results presented in
accordance with GAAP, these measures assist in providing a more complete
understanding of certain aspects of the Trust's results of operations and
financial performance. Investors are cautioned however, that these measures
should not be construed as an alternative to measures determined in accordance
with GAAP as an indication of our performance.

    
    2006 HIGHLIGHTS
                                 Three Months Ended          Year ended
                                     December 31             December 31
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    ($millions except per
     unit amounts)              2006     2005     %    2006(1)    2005     %
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    FINANCIAL
    Gross revenue              347.7    234.1    49%  1,407.8    800.2    76%
    Funds flow from
     operations(3)             170.1    106.5    60%    750.1    360.5   108%
      Per unit - basic(2)       0.10     1.16   -34%     3.64     4.04   -10%
      Per unit - diluted(2)     0.75     1.15   -35%     3.57     3.98   -10%
    Net earnings (loss)        (21.6)    48.7  -144%    223.1     65.8   239%
      Per unit - basic(2)      (0.10)    0.53  -119%     1.08     0.74    46%
      Per unit - diluted(2)    (0.10)    0.52  -119%     1.06     0.73    45%
    Cash distributions
     declared                  155.5     53.3   192%    583.5    208.5   180%
      Per unit(2)             0.6900   0.5850    18%   2.7600   2.3401    18%
    Payout ratio(3)              91%      50%    82%      78%      58%    34%
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    Capital expenditures
      Development
       expenditures            106.0     72.0    47%    351.3    172.2   104%
      Net capital
       expenditures (net
       of StarPoint)            85.5     75.6    13%  1,315.0    181.2   626%
    Total assets             5,831.0  1,571.1   271%  5,831.0  1,571.1   271%
    Long-term debt           1,289.7    309.1   317%  1,289.7    309.1   317%
    Net debt (excluding
     financial
     derivatives)(3)         1,318.3    331.8   297%  1,318.3    331.8   297%
    Unitholders' equity      3,506.9    764.6   359%  3,506.9    764.6   359%
    -------------------------------------------------------------------------
    Weighted average trust
     units outstanding
     (000s)(2)               225,192   91,489   146%  206,081   89,331   131%
    Trust units outstanding
     at period end
     (000s)(2)               225,796   91,583   147%  225,796   91,583   147%
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    OPERATING
    Production(3)
      Natural gas (mmcf/d)     221.2    105.8   109%    186.3    104.5    78%
      Crude oil (bbl/d)       36,713   16,945   117%   37,500   17,779   111%
      Crude oil and NGL's
       (bbl/d)                43,402   21,915    98%   43,358   23,046    88%
      Barrel of oil
       equivalent
       (boe/d, 6:1)           80,276   39,541   103%   74,409   40,460    84%
    -------------------------------------------------------------------------
    Average Prices(3)
      Natural gas ($/mcf)       6.90    12.29   -44%     7.01     9.08   -23%
      Natural gas ($/mcf)
       (including financial
       instruments)             7.34    11.74   -37%     7.62     8.84   -14%
      Crude oil ($/bbl)        53.23    59.37   -10%    60.61    57.78     5%
      Crude oil ($/bbl)
       (including financial
       instruments)            51.88    46.35    12%    56.97    46.83    22%
      Natural gas liquids
       ($/bbl)                 45.44    44.97     1%    47.84    40.44    18%
    -------------------------------------------------------------------------
    Total ($/boe)              47.08    64.35   -27%    51.83    54.19    -4%
    Total ($/boe)(including
     financial instruments)    47.67    57.29   -17%    51.52    48.76     6%
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    Drilling activity (gross)
      Natural gas                 55       40     -       205       81     -
      Oil                         60       41     -       161       87     -
      Other                        -        -     -         5        2     -
      Dry and abandoned            -        1     -         7        2     -
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    Total gross wells            115       82     -       378      172     -
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    Total net wells             48.8     52.4     -     174.4    106.6     -
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    Success rate (%)            100%      99%     -       98%      99%     -
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    (1) Includes the financial and operating results of StarPoint Energy
        Trust from the date of the merger, January 5, 2006 and the property
        acquisition from the date of closing August 31, 2006.
    (2) The merger of Acclaim Energy Trust ("Acclaim") and StarPoint Energy
        Trust ("StarPoint") has been accounted for as a purchase of StarPoint
        by Acclaim. Accordingly, the financial and operating results of
        StarPoint have been included from the date of acquisition, January 5,
        2006. The comparative results for 2005 are those of Acclaim only. All
        disclosures of units and per unit amounts of Acclaim up to the merger
        on January 5, 2006 have been restated using the exchange ratio of
        0.8333 of a Canetic unit for each Acclaim unit.
    (3) Please refer to the Advisory section at the end of this report for
        definitions of Non-GAAP terms and frequently recurring terms and
        abbreviations. The payout ratio is based on cash distributions
        divided by funds flow from operations.
    

    MESSAGE TO UNITHOLDERS

    The year 2006 was the first full year of operations for Canetic following
the merger of Acclaim with StarPoint in early January. It was a dynamic year
for Canetic, and for the entire trust sector, highlighted by continued growth,
an expanded investment reach with the listing of Canetic units on the New York
Stock Exchange and the successful completion of the largest capital program in
the Trust's history. Canetic rose to the challenge and marked another solid
year of performance, a year in which the team executed on our business
strategies to extend and enhance the Trust's long-term opportunity base
through acquisition while continuing to deliver solid results from our ongoing
exploitation and development activities.
    A significant component of Canetic's business strategy is to be
operationally focused and create value internally. Following on its strong
performance in 2005, the team continued to demonstrate its ability to derive
value from Canetic's large asset portfolio through its focused exploitation
and development activity. During 2006, Canetic completed the largest
development program in its history at $351.3 million, operating or
participating in the drilling of 378 wells with a success rate of 98 percent.
Through its development activities Canetic successfully replaced 76 percent of
its production on a proved plus probable basis at an F&D cost of $16.93 per
boe excluding future development capital. Canetic's recycle ratio, defined as
operating netback divided by F&D cost, was 1.9 times on a proved plus probable
basis. In addition, Canetic replaced production through drilling at an
efficiency rate of $20,300 per boe per day. These are very strong results that
are indicative of the quality of our reserve and opportunity base and
underscore Canetic's relentless commitment to deliver long-term value to its
unitholders.
    In addition to our demonstrated technical expertise, one of Canetic's key
strengths lies in our ability to complete acquisitions and to integrate people
and assets. Our approach to integration has been developed over several years
and over many transactions and we believe we have created an effective
template for smoothly integrating people, systems and properties. With the
closing of the StarPoint merger in January and the Samson acquisition in
August, the Canetic team once again demonstrated its aptitude for completing
and integrating large, complex, value adding acquisitions that enhance the
Trust's opportunity base. Through these acquisitions Canetic more than doubled
its production and reserves and enhanced its opportunity base while also
increasing its inventory of undeveloped acreage and exposure to key areas
expected to fuel the Trust's continued long-term growth and development.
    Our experience tells us that there is an increase in knowledge and
understanding that follows any acquisition and that acquired properties tend
to have the greatest impact two to three years following their integration. We
also find that the more complex properties hold some of the greatest
opportunity for us over the long-term, however it takes time to understand and
extract that value. Having now integrated the StarPoint and Samson assets in
2006 and with work ongoing to understand and build a growing inventory of
related development opportunities, we look excitedly at 2007 and beyond as
years in which we can enjoy the benefits of our work and begin to extract
long-term value from these assets.
    With the recent growth of the Trust, Canetic also undertook to
restructure itself operationally in late 2006 to better meet its needs as a
large producer. We set out to hire and secure the necessary talent and
resources and restructured into newly formed business units, integrating
geotechnical and commercial skills, to ensure each team can collectively work
to maximize the extraction of value from Canetic's assets. The year also
marked a transition in the focus of our development from a program targeting
the maintenance of production rate to a program that places growing emphasis
on increasing the ultimate value of Canetic's assets over the long-term.
Canetic's asset base offers significant untapped potential and as a result of
these changes Canetic now has the teams, expertise and structure in place to
optimize that potential. Given our size we are also well positioned to spread
risk across a much broader portfolio of opportunity and pursue deeper, higher
reward prospects without exposing our unitholders to significant risk. In
addition, Canetic created a team of reservoir specialists in 2006 to look at
ways to mitigate overall declines through an increased focus on the
implementation or refinement of reservoir management and enhanced recovery
strategies in respect of our large oil in place pools and the development of
strategies for the exploitation of our significant inventory of longer term
resource plays.
    The year 2006 was also punctuated by the announcement of the Canadian
Government's Tax Fairness Plan on October 31, 2006, a key component of which
was a proposed change to taxation rules governing publicly traded income
trusts in Canada. The creation of this new tax regime for publicly listed
flow-through entities reflects a fundamental shift in the tax system which
could have a significant impact on the strategic direction of the income trust
model. Existing publicly traded income trusts, such as Canetic, would be
subject to the proposed changes beginning in the 2011 taxation year, providing
the trust complies with subsequently announced guidelines for "normal growth"
in the intervening period.
    As a result of these proposals there have been significant implications
to the Trust and our unitholders. Shortly after the announcement of the new
rules, the valuation of Canetic and other trusts was significantly reduced to
reflect the loss of our current tax advantage.
    Canetic is currently working with the Canadian Association of Income
Funds and the Coalition of Canadian Energy Trusts to effect changes to the
legislation as proposed. A main focus is ensuring that the facts related to
income trusts are understood and that all data is made available by the
Minister of Finance to the investing public and other members of Parliament.
    We have initiated a review of our business and potential alternatives
available to the Trust in context of the current Canadian Government
proposals, but it is premature at this time to determine what Canetic's course
of action will be as 2011 approaches. Until the legislation is enacted, the
rules fully understood and all options have been assessed, we are not prepared
to commit to any strategic changes. In the short-term, we believe we are in a
strong competitive position and are not compelled to make any significant
changes with respect to our strategic direction, preferring to remain focused
on our business and execute on our planned capital program.
    As one of the largest conventional oil and gas trusts in North America,
Canetic is well positioned to create long-term value for unitholders. We
believe that our current size provides the Trust with sufficient room to grow
within the safe harbour guidance announced by the Canadian Government and will
improve our competitive position with respect to large acquisitions,
consolidation and our ability to expand outside of western Canada, as well as
allowing us to undertake or participate in longer term more capital intensive
projects. We have successfully built an asset base that is rich with
opportunity. Our focus moving forward is to manage through the current
uncertainty and deliver on our promise to create long-term value for our
unitholders.

    REVIEW OF OPERATIONS

    Over recent years the oil and gas sector has increased its focus on
unconventional and resource plays, but Canetic continues to believe its
considerable inventory of conventional oil and natural gas development
opportunities will remain the engine for growth and fuel the Trust's
development activity over the coming years. The year 2006 was no exception,
with Canetic's operated development activity almost exclusively focused on
exploitation of Canetic's significant inventory of conventional opportunities.
As demonstrated once again in 2006, our continued focus in this area continues
to drive our industry competitive finding and development costs while also
providing strong economic returns, regardless of the pricing environment.
    During 2006, Canetic had exploration and development expenditures of
$351.3 million as compared to $172.2 million in 2005 (2004 - $91.8 million). A
total of 378 gross (174.4 net) wells were drilled during the year, including
115 gross (48.8 net) wells in the fourth quarter, compared to 82 gross
(52.4 net) wells during the fourth quarter 2005. The increase in drilling
activity reflects the larger opportunity base associated with our assets as a
result of the acquisitions made in 2006. This level of activity is expected to
continue into the first quarter of 2007 with the drilling of an estimated 50
operated wells. Of the total wells drilled in 2006, 102 gross (90.6 net) were
operated by Canetic resulting in 64 gross (58.0 net) oil wells and 32 gross
(26.9 net) natural gas wells, 2 gross (2 net) service wells and 4 gross (3.8
net) abandoned wells. The overall program resulted in 161 gross (81.9 net) oil
wells and 205 gross (85.4 net) natural gas wells, 5 gross (2.2 net) service
wells and 7 gross (4.0 net) abandoned wells.
    In 2006, Canetic focused 62 percent of its operated capital program on
conventional oil and big oil in place pools. Primary areas of activity
included the newly acquired StarPoint assets in Williston Basin in southeast
Saskatchewan and the Countess - Suffield - Alderson assets of Southern
Alberta. We were also active in the Acheson field located near the western
city limits of Edmonton. Although most of the pools have been producing for a
considerable time and are in various stages of maturity, Canetic continues to
identify numerous opportunities for infill drilling, pool extensions and
downspacing. Canetic has been highly successful at finding incremental
reserves and production through infill drilling and pool extensions in major
pools such as Queensdale, Alida West and Ingoldsby. In the Williston Basin,
other pools such as Bryant, Tatagwa, and Handsworth, offer further development
potential through a combination of pressure support and infill drilling.
    In Southern Alberta, Canetic initiated a 14 well program in four Sunburst
pools in the Countess and Alderson East area. This program was the initial
phase of a 3 phase project targeting increased recovery factors in the pool.
Phase 2 of the project is currently underway and includes conversion of
producers to injectors to increase pressure to the pools and improve recovery
factors. Phase 3 of the project will encompass further infill drilling
activity once simulation has been completed and flood response is observed.
    Canetic's 2006 natural gas development largely focused on higher rate
conventional opportunities and resulted in significant discoveries and
conversions associated with the Rock Creek, Belly River, Ellerslie and
Doig/Halfway formations in the Peace River Arch and West Central Alberta.
    The Acheson field in Central Alberta was also an important area of
activity for Canetic in 2006. As anticipated the Leduc (D3a) pool at Acheson
entered its final blow down stage in late 2005, but depleted more rapidly than
expected, and as a result Canetic experienced a loss of nearly 6,000 boe per
day of production over a short period of time. In response to this setback,
the Acheson technical team initiated an aggressive multi year up-hole
re-completion and drilling program to backfill lost production associated with
the D3a pool. The team achieved significant success from the program during
2006 and had backfilled most of the lost production by year end, however, due
to timing of the new production coming on stream the initial loss still had
considerable impact on our average production for the year.
    Canetic was also active on the optimization front in 2006 with a
continued emphasis on the completion of new zones in existing well bores and
the optimization of our existing producing assets. The focus in this area
through 2006 was on the identification of opportunities that added new
production as well as new reserves.
    During the year Canetic committed to the construction of our new
Willesden Green gas processing plant in response to capacity constraints
impacting production in the area. The start-up of the 20 mmcf per day plant
late in the first quarter of 2007 will help to alleviate previous capacity
constraints in the area and will allow Canetic to resume its successful
drilling activities which will be ongoing and timed to keep the new facility
near capacity in the coming years.
    During the second half of 2006, Canetic undertook to review and high
grade plans for the future development of its shallow gas resources after
considerably increasing its portfolio of opportunities earlier in the year as
a result of the StarPoint and Samson acquisitions.
    At Canetic we believe have successfully built an asset base rich with
years of ongoing development opportunity and our focus moving forward is to
effectively manage the development and exploitation of this considerable
resource base.
    Given the diversity of Canetic's conventional oil pools the strategy for
growth and development of the assets is quite dynamic. Over the near term,
Canetic will continue to drill its existing inventory of conventional oil
opportunities at an expected rate of 60 to 70 wells per year, largely
targeting opportunities for pool extensions and infill drilling to further
enhance its production base. Canetic also expects it will identify further
follow-up or contingent locations that will expand the current inventory of
opportunities associated with its existing assets. Over the coming years,
Canetic's primary focus will shift more towards opportunities for improved
pressure maintenance and sweep efficiencies as well as identification of
enhanced recovery opportunities in relation to its larger oil and gas
reservoirs. Work being completed by Canetic's newly formed team of reservoirs
specialists will support these plans moving forward. Longer term, these
initiatives are expected to aid in the mitigation of natural declines by
lowering Canetic's overall base decline rate while also contributing
positively to Canetic's reserve life index and the ultimate recovery of
resources from Canetic's large oil and natural gas reservoirs.
    Canetic's existing portfolio of properties provide important exposure to
a variety of large, high quality, long life natural gas reservoirs with
considerable conventional gas development potential in the coming years. Over
the near term, Canetic expects to operate a 20 to 30 well per year
conventional natural gas program and continue to expand its inventory of
opportunities through additional land purchase and identification of further
opportunities on existing lands. As part of a broader strategy for the
development of its significant natural gas resources, Canetic plans to direct
a portion of its ongoing near and medium-term development capital towards
higher impact, liquids rich conventional natural gas plays that, if
successful, offer significant potential for substantial production and reserve
additions. Longer term, the Trust's recent acquisition of properties from
Samson provides significantly expanded access to lands in northeast British
Columbia that offer considerable deep and multi-zone conventional development
potential. Canetic currently expects to move forward with an aggressive
drilling program in the fourth quarter of 2007 targeting multi zone horizons
including the Dunlevy, Halfway, Doig and Baldonnel. Canetic expects this area
to yield strong drilling programs which will comprise a significant portion of
Canetic's ongoing conventional natural gas development activity for years to
come.
    Tight and shallow gas opportunities remain a key element of Canetic's
longer term development plans due to their generally long-life, low risk
nature and a relatively low associated cost of production. Looking ahead,
Canetic has identified a significant inventory of shallow gas prospects which
will provide considerable development opportunity over the next few years with
emphasis placed on drilling into favourable and more stabilized natural gas
pricing environments.
    Historically, Canetic has spent limited capital on development of its
shallow gas assets. With the addition of the Hoadley properties in Central
Alberta, which were acquired as part of the Samson acquisition, Canetic added
a significant inventory of drilling opportunities providing the critical mass
necessary to drive efficient programs. As a result, Canetic is now moving
forward plans for the development of its considerable shallow gas resources.
In the near term, Canetic has plans to proceed with its previously deferred 20
well program in the Countess - Leckie area in expectation of a more stabilized
natural gas price environment. Going forward, Canetic has identified an
abundance of new shallow gas drilling and downspacing opportunities,
particularly in the Countess - Leckie block of southern Alberta for Medicine
Hat and Milk River related production. Canetic could expand its current
inventory of drilling opportunities by as much as 250 to 600 additional
drilling locations should it elect to pursue potential downspacing from
current plans of eight wells per section to 12 or 16 wells per section, as
some competitors have done. In the Hoadley area, Canetic has identified
numerous opportunities targeting the Edmonton sands with downspacing potential
of five to eight wells per section. In the longer term, Canetic will develop
these opportunities.
    Coalbed Methane production is expected to provide further long-term
growth potential as Canetic begins development of its Mannville play in
Corbett Creek and North Central Alberta as well as further development of its
coalbed methane resources in Wyoming's Powder River Basin at Big Bend and Coal
Gulch. Further potential may exist in respect of Horseshoe Canyon and Ardley
coals in Southern Alberta on lands recently acquired from Samson. To date,
Canetic has participated in several non-operated Mannville drilling
opportunities in the Corbett Creek area and has identified several operated
and further non-operated drilling opportunities on its growing land base in
the area. Over the near term, Canetic will continue to participate with
partners in Corbett Creek with the drilling of 9 to 12 multi-leg Mannville
horizontal wells where Canetic has an approximate 40 percent working interest.
Up to 3 billion cubic feet per section is recoverable in this area and Canetic
holds positions in twenty four undeveloped sections. In addition, Canetic has
further plans to drill two operated multi lateral wells and one water disposal
well in the Corbett Creek area in 2007.
    In Wyoming, Canetic will complete phase 1 of a 50 well program in the Big
Bend area which is expected to be followed by a period of dewatering of the
coals. Analogies from offsetting production in the area indicate dewatering
periods of four to twelve months are required to achieve commercial production
of natural gas. Once commercial production is established Canetic plans to
proceed with phases two and three of the drilling program.
    Over the longer term, Canetic will continue to pursue economic
development opportunities associated with its growing exposure to Mannville,
Horseshoe Canyon and Ardley coals in and around the Corbett Creek, Horsehoe
Canyon, Willesden Green, and Gilby areas. Plans also remain in place to
proceed with the further development of its Big Bend and Coal Gulch coalbed
methane plays in Wyoming.

    FINANCIAL RESULTS

    For the year ended December 31, 2006 Canetic achieved record financial
and operating results. Significantly increased production volumes combined
with a higher combined average realized price, after hedging, contributed to
the strong performance. The production increases resulted primarily from the
addition of production volumes associated with the StarPoint acquisition as
well as four months of production attributable to the properties acquired from
Samson. Further discussion on Canetic's 2006 financial and operating
performance can be found in the Management's Discussion and Analysis contained
in this news release or available on SEDAR at www.sedar.com.

    TAXABILITY OF UNITHOLDER DISTRIBUTIONS

    On February 28, 2007, Canetic issued 2006 distribution tax information
for Canetic unitholders and to former unitholders of Acclaim and StarPoint
resident in Canada. Further, on January 15, 2007, and March 6, 2007, Canetic
issued separate news releases outlining relevant tax information with respect
to distributions received by United States resident unitholders. For
information on the taxability of distributions paid or payable for 2006 please
refer to information contained in the above noted news releases available on
Canetic's website at www.canetictrust.com or on SEDAR as www.sedar.com.

    CANETIC RE

SOURCES ANNUAL GENERAL MEETING The Annual General Meeting of Unitholders of Canetic Resources Trust will be held on Wednesday, May 9, 2007 at 3:00 p.m. local time at the Hyatt Regency Hotel, 700 Centre Street S.E. Calgary, Alberta. All Unitholders and interested parties are invited to attend. RESERVES SUMMARY 2006 reserve highlights were dominated by successful development activities and continued positive technical revisions which are indicative of our quality reserve and opportunity base. Canetic continues to provide consistent and stable reserve growth with a three (3) year average proved plus probable F&D cost of $13.50 per boe, excluding future development capital and a three (3) year proved plus probable FD&A cost of $16.59 per boe, excluding future development capital. HIGHLIGHTS FOR 2006 INCLUDE: - Canetic's development program replaced 96 percent of its 2006 production on a proved producing basis at an F&D cost of $13.49 per boe, excluding future development capital and $14.72 per boe including future development capital. These results included positive technical revisions of 6.7 percent which is a reflection of the performance and quality of the reserve base. - Canetic's internal development program delivered 20.8 million boe of proved plus probable reserves, replacing 76 percent of production at an F&D cost of $16.93 per boe, excluding future development capital and $19.21 per boe including future development capital. Canetic achieved this result spending 47 percent of its Funds from Operations. These reserve additions were realized from various play types including Corbett Creek CBM development, Acheson uphole oil and gas development, Willesden Green gas development and South Eastern Saskatchewan infill and step-out drilling. - Canetic's total capital program including acquisitions replaced 237 percent of its 2006 production on a proved plus probable basis at an FD&A cost of $20.41 per boe, excluding future development capital and $23.30 per boe including future development capital. - Canetic's reserves as at December 31, 2006 totaled 192.2 million boe of total proved reserves and 275.6 million boe of proved plus probable reserves. This represents an increase of 12% and 16% respectively to reserves reported as at December 31, 2005. - Canetic's Reserve Life Index increased by 1.0 years to 9.7 years on a proved plus probable basis. Reserves included herein are stated on a company interest basis (before royalty burdens and including royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. This summary contains several cautionary statements that are specifically required by NI 51-101. In addition to the detailed information disclosed in this news release more detailed information on a net interest basis) after royalty burdens and including royalty interests) and on a gross interest basis (before royalty burdens and excluding royalty interests) will be included in Canetic's Annual Information Form ("AIF") which will be filed on SEDAR at www.sedar.com on or before March 30, 2007. Canetic's oil and gas reserves as at December 31, 2006 were evaluated by the independent engineering firms of GLJ Petroleum Consultants Ltd.("GLJ") and Sproule Associates Limited ("Sproule") in compliance with National Instrument 51-101. Under NI 51-101 guidelines, proved reserves are defined as those reserves that have at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimates. Proved plus probable reserves are defined as those reserves that have at least a 50 percent probability of being exceeded at the reported level. They are the best estimate, or the most realistic case. It is equally likely that the actual reserves will be higher or lower than the estimate. It should not be assumed that the estimates of net present values of reserves presented in the tables below represent the fair market value of the reserves. All evaluations of future net production revenues set forth in the tables are stated after the provision for income taxes and exclude abandonment costs on wells and facilities where reserves are not assigned or associated general and administrative costs. This information has been prepared on the basis that Canetic will not pay cash income taxes in Canada in the future due to Canetic's current structure as an income trust and Canadian tax laws currently in effect. The Canadian federal government has announced a proposal designed to effectively tax income trusts such as Canetic at the same level as Canadian corporations, effective for the 2011 tax year. Such proposal has not yet been approved or put in force and it is uncertain as what form, if any, changes in Canadian income tax laws will take as a result of such proposal. Any changes in Canadian income tax laws that may result from such proposal could adversely affect the estimated future net revenues associated with Canetic's oil and gas reserves. For additional information, investors should refer to disclosure that will be contained in Canetic's Annual Information Form. Summary of Oil and Gas Reserves - Company Interest(1) Forecasted Prices and Costs Light and Natural Medium Gas Natural Crude Oil Heavy Oil Liquids Gas BOE ------------------------------------------------------ (mbbls) (mbbls) (mbbls) (mmcf) (mboe) Proved Developed producing 68,315 15,417 372,979 11,173 157,068 Developed non- producing 2,958 1,542 29,387 937 10,336 Undeveloped 11,662 1,527 63,979 922 24,775 ------------------------------------------------------------------------- Total proved 82,936 18,487 466,345 13,032 192,179 Probable 34,392 5,796 228,173 5,247 83,464 ------------------------------------------------------------------------- Total proved plus probable 117,327 24,283 694,518 18,279 275,642 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Note: May not add due to rounding (1) "Company Interest" means in relation to Canetic's interest in reserves, its "Corporation gross reserves", which are Canetic's working interest (operating and non-operating) share before deduction of royalties, plus Canetic's royalty interests in reserves. "Company Interest" reserves is not a measure defined in NI 51- and does not have a standardized meaning under NI 51-101. Accordingly, Canetic's Company Interest reserves may not be comparable to reserves presented or disclosed by other issuers. Canetic's reserves statement, which includes complete disclosure of its oil and gas reserves and other oil and gas information in accordance with NI 51-101 will be contained within its Annual Information Form which will be available on our website at www.canetictrust.com and on our SEDAR profile at www.sedar.com. Additionally, the Annual Information form is part of our Form 40-F that will be filed with the SEC and available on www.sec.gov. Before Income Tax Net Present Value of Reserves Forecasted Prices and Costs Undis- Discounted Discounted Discounted Discounted counted at 5% at 10% at 15% at 20% ------------------------------------------------------------------------- ($M) ($M) ($M) ($M) ($M) Proved ------------------------------------------------------------------------- Developed producing 4,662,073 3,515,069 2,892,706 2,493,224 2,210,722 Developed non- producing 285,053 212,000 170,885 143,402 123,449 Undeveloped 475,959 329,570 237,133 174,204 129,143 ------------------------------------------------------------------------- Total proved 5,423,084 4,056,639 3,300,724 2,810,830 2,463,314 Probable 2,494,025 1,411,019 949,810 701,204 546,933 ------------------------------------------------------------------------- Total proved plus probable 7,917,110 5,467,658 4,250,534 3,512,034 3,010,247 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Note: May not add due to rounding. Estimates of net present values do not represent fair market value. Pricing Assumptions Forecasted Prices and Costs The first six years of the GLJ/Sproule January 1, 2007 price forecast are presented below. These prices have been utilized in determining the reserves and cash flow forecasts above. Bank of Canada Average Crude Oil Natural Noon Crude Oil Edmonton Gas Exchange Year WTI Light AECO Rate ------------------------------------------------------------------------- ($US/bbl) ($CDN/bbl) ($CDN/ ($US/ MMBtu) $CDN) 2007 63.87 72.17 7.46 0.8700 2008 64.41 72.81 8.02 0.8700 2009 60.21 68.00 7.74 0.8700 2010 57.68 65.03 7.67 0.8700 2011 56.10 63.20 7.79 0.8700 2012 56.90 64.07 8.00 0.8700 ------------------------------------------------------------------------- Summary of Oil and Gas Reserves - Company Interest(1) Constant Prices and Costs Light and Natural Medium Gas Natural Crude Oil Heavy Oil Liquids Gas BOE ------------------------------------------------------- (mbbls) (mbbls) (mbbls) (mmcf) (mboe) Proved Developed producing 69,781 15,589 368,661 11,220 158,033 Developed non- producing 2,863 1,575 28,888 922 10,175 Undeveloped 11,827 1,550 63,663 930 24,917 ------------------------------------------------------------------------- Total proved 84,470 18,715 461,212 13,072 193,126 Probable 35,037 5,922 224,245 5,238 83,571 ------------------------------------------------------------------------- Total proved plus probable 119,507 24,637 685,457 18,310 276,697 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Note: May not add due to rounding (1) "Company Interest" means in relation to Canetic's interest in reserves, its "Corporation gross reserves", which are Canetic's working interest (operating and non-operating) share before deduction of royalties, plus Canetic's royalty interests in reserves. "Company Interest" reserves is not a measure defined in NI 51- and does not have a standardized meaning under NI 51-101. Accordingly, Canetic's Company Interest reserves may not be comparable to reserves presented or disclosed by other issuers. Canetic's reserves statement, which includes complete disclosure of its oil and gas reserves and other oil and gas information in accordance with NI 51-101 will be contained within its Annual Information Form which will be available on our website at www.canetictrust.com and on our SEDAR profile at www.sedar.com. Additionally, the Annual Information form is part of our Form 40-F that will be filed with the SEC and available on www.sec.gov. Before Income Tax Net Present Value of Reserves Constant Prices and Costs Undis- Discounted Discounted Discounted Discounted counted at 5% at 10% at 15% at 20% ------------------------------------------------------------------------- ($M) ($M) ($M) ($M) ($M) Proved Developed producing 4,244,546 3,226,467 2,653,161 2,279,373 2,013,531 Developed non- producing 250,679 190,227 153,731 128,771 110,518 Undeveloped 425,003 288,516 202,373 143,887 102,162 ------------------------------------------------------------------------- Total proved 4,920,229 3,705,209 3,009,265 2,552,031 2,226,211 Probable 2,051,904 1,210,674 828,942 615,367 480,060 ------------------------------------------------------------------------- Total proved plus probable 6,972,133 4,915,884 3,838,207 3,167,398 2,706,271 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Note: May not add due to rounding Pricing Assumptions Constant Prices and Costs Natural Crude Oil Edmonton Gas Exchange Year WTI Light AECO Rate ------------------------------------------------------------------------- ($US/bbl) ($CDN/bbl) ($CDN/ ($US/ MMBtu) $CDN) (Year End) 2007 60.95 67.59 6.10 0.8580 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NET ASSET VALUE The following net asset value ("NAV") calculation utilizes what is generally referred to as the "produce-out" net present value of Canetic's oil and natural gas reserves based on forecast prices as provided by the independent engineering firms. This calculation can vary significantly depending on the oil and natural gas price assumptions used. It does not take into account the development and growth in additional reserves in its existing properties beyond those included in the 2006 yearend report. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that will vary over time. Net Asset Value - Discounted at 5 and 10 percent Jan 1, 2007 Jan 1, 2007 Jan 1, 2007 Constant Forecasted Strip Pricing Prices Pricing(e) 5% 10% 5% 10% 10% ------------------------ ------------------ ------------------ ---------- $Millions Proved Plus Probable(a) 4,915.9 3,838.2 5,467.7 4,250.5 4,920.7 Undeveloped Lands + Seismic(b) 248.3 248.3 248.3 248.3 248.3 Debentures and Long-term Debt, net of Working Capital(c) (1,577.3) (1,577.3) (1,577.3) (1,577.3) (1,577.3) ------------------------ ------------------ ------------------ ---------- Net Asset Value 3,586.9 2,509.2 4,138.6 2,921.5 3,591.6 Units Outstanding (000's)(d) 225,796 225,796 225,796 225,796 225,796 NAV/Unit 15.89 11.11 18.33 12.94 15.91 ------------------------ ------------------ ------------------ ---------- (a) As evaluated by GLJ and Sproule. (b) Internal Estimate. (c) Excludes commodity and foreign currency contracts. (d) Represents total trust units outstanding and trust units issuable for exchangeable shares. (e) Strip Pricing at February 28, 2007 In the absence of reserve additions by the Trust, the NAV per unit will decline as the reserves are produced out. The cash flow generated by the production relates directly to the cash distributions paid to unitholders. Canetic works continuously to add value, improve profitability and increase reserves to enhance the Trust's NAV. 2006 Finding and Development (F&D), Net Acquisition, and Finding, Development and Net Acquisition Costs (FD&A) 2006 ------------------------------------ Change to Company Capital Interest Reserve Expenditures Reserves Costs ------------------------------------------------------------------------- ($thousands) (mboe) ($/boe) Total Proven F&D Including change in FDC 385,212 20,016 19.25 Excluding change in FDC 351,288 20,016 17.55 ------------------------------------------------------------------------- Including change in FDC 1,434,405 47,304 30.32 Excluding change in FDC 1,315,041 47,304 27.80 Proven Plus Probable F&D Including change in FDC 398,669 20,752 19.21 Excluding change in FDC 351,288 20,752 16.93 FD&A Including change in FDC 1,500,942 64,419 23.30 Excluding change in FDC 1,315,041 64,419 20.41 3 Year Average ------------------------------------ Change to Company Capital Interest Reserve Expenditures Reserves Costs ------------------------------------------------------------------------- ($thousands) (mboe) ($/boe) Total Proven F&D Including change in FDC 685,977 41,165 16.66 Excluding change in FDC 615,279 41,165 14.95 ------------------------------------------------------------------------- Including change in FDC 2,208,182 94,279 23.42 Excluding change in FDC 2,022,304 94,279 21.45 Proven Plus Probable F&D Including change in FDC 728,723 45,592 15.98 Excluding change in FDC 615,279 45,592 13.50 FD&A Including change in FDC 2,320,955 121,887 19.04 Excluding change in FDC 2,022,304 121,887 16.59 RESERVE RECONCILIATION Reconciliation of Company Interest(1) Reserves by Principal Product Type Forecast Prices and Costs Natural Light and Heavy Natural Gas Medium Crude Oil Gas Liquids BOE ------------------------------------------------------------------------- (mbbl) (mbbl) (mmcf) (mbbl) (mboe) Proved Producing Opening Balance 66,797 16,564 268,785 8,707 136,866 Acquisitions 850 - 110,484 2,399 21,662 Dispositions - - (1,205) (132) (332) Discoveries 9 - 840 74 224 Extentions 1,479 270 24,405 1,344 7,160 Infill Drilling 3,205 887 8,444 111 5,610 Improved Recovery 1,264 613 8,615 398 3,711 Economic Factors 100 25 403 13 205 Technical Revisions 5,792 (434) 20,209 396 9,121 Production (11,180) (2,507) (68,001) (2,138) (27,159) ------------------------------------------------------------------------- Closing Balance 68,315 15,417 372,979 11,173 157,068 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total Proved Opening Balance 82,527 19,852 355,599 10,388 172,034 Acquisitions 1,081 - 142,305 2,822 27,620 Dispositions - - (1,205) (132) (332) Discoveries 347 - 1,094 74 604 Extentions 1,502 336 22,362 1,115 6,680 Infill Drilling 2,634 769 6,721 70 4,594 Improved Recovery - 2,533 6,867 257 3,935 Economic Factors 124 30 533 16 258 Technical Revisions 5,901 (2,526) 70 560 3,946 Production (11,180) (2,507) (68,001) (2,138) (27,159) ------------------------------------------------------------------------- Closing Balance 82,936 18,487 466,345 13,032 192,179 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Proved Plus Probable Opening Balance 116,071 26,354 491,494 14,041 238,382 Acquisitions 1,627 - 228,120 4,415 44,062 Dispositions - - (1,432) (156) (395) Discoveries 417 - 1,271 85 715 Extentions 1,838 700 33,539 1,428 9,555 Infill Drilling 3,511 516 8,387 132 5,557 Improved Recovery 1,872 951 7,959 309 4,458 Economic Factors 174 40 737 21 358 Technical Revisions 2,998 (1,772) (7,556) 142 110 Production (11,180) (2,507) (68,001) (2,138) (27,159) ------------------------------------------------------------------------- Closing Balance 117,327 24,283 694,518 18,279 275,642 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Note: May not add due to rounding (1) "Company Interest" means in relation to Canetic's interest in reserves, its "Corporation gross reserves", which are Canetic's working interest (operating and non-operating) share before deduction of royalties, plus Canetic's royalty interests in reserves. Royalty interest volumes are as follows: PP 1,079 mboe; TP 1,194 mboe; and P+P 1,631 mboe. Canetic's Land Position As at December 31, Developed Undeveloped 2006 (acres) Gross Net Gross Net ------------------------------------------------------------------------- Alberta 1,666,860 762,821 1,050,353 584,843 British Columbia 233,024 101,675 262,088 148,144 Saskatchewan 263,398 149,210 273,895 145,798 Manitoba 36,510 13,143 7,943 2,627 Wyoming 9,652 3,821 26,785 14,962 Montana 1,520 937 2,275 811 North Dakota 7,506 3,731 31,148 24,851 ------------------------------------------------------------------------- Total 2,218,470 1,035,338 1,654,487 922,036 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, Total 2006 (acres) Gross Net --------------------------------------------------- Alberta 2,717,213 1,347,665 British Columbia 495,112 249,819 Saskatchewan 537,293 295,008 Manitoba 44,453 15,770 Wyoming 36,436 18,783 Montana 3,796 1,748 North Dakota 38,654 28,582 --------------------------------------------------- Total 3,872,957 1,957,375 --------------------------------------------------- --------------------------------------------------- OUTLOOK Our long-term strategy has always been to build a significant asset base and a team of people that could generate long-term value for our stakeholders. We have pursued our objectives aggressively over the past four years and today, with the merger of Acclaim and StarPoint and the recent addition of the Samson assets we believe we have created a trust with substantial financial strength and a great asset and opportunity base capable of delivering that value. With the growth of Canetic and expansion of the opportunity base, exploitation has become a significant component of our business strategy. In 2006, we reported solid results from Canetic's development program delivering what we believe will be top quartile finding, development and acquisition costs and strong production efficiencies. In 2007, we will continue to actively exploit our asset base. We have budgeted approximately $350 million for development related expenditures in 2007. More than 80 percent of that amount will be allocated to drilling and new completion or optimization related activity directly impacting production and reserves performance. The 2007 operated drilling program is weighted modestly to oil prone plays with substantial development targeting many of the former StarPoint properties which performed very strongly throughout 2006. We continue to target new completions in areas such as Acheson, where we have had significant success identifying and exploiting multiple zones in the large inventory of well bores we acquired through the ChevronTexaco transaction. In the early part of 2007, our focus has been to tie in production from our successful fourth quarter 2006 drilling program, while also pursuing an aggressive drilling and optimization program on our producing properties. During the fourth quarter of 2006, Canetic continued its strong performance of efficiently adding reserves and production. We exited the year with approximately 1,400 boe per day behind pipe, led by successful Q4 programs in the Acheson area, Southern and Northwest Alberta. Following on the strength of the 2006 program and depth of opportunities Canetic kicked off the largest first quarter development program in its history in 2007. Canetic operated five to seven drilling rigs throughout the first quarter of 2007 and to date we have drilled 37 wells. Canetic's focus in 2007 will be on gas development in the Willesden Green area where our new 20 mmcf per day gas plant is now on stream, Northeast BC where we are excited about the prospect of a Slave Point test and follow-ups, and continued programs in Border Plains and our Southern business unit. In addition, we have an aggressive drilling, new completion and facility de-bottlenecking program underway in the Acheson area. This program is in follow-up to a large and successful fourth quarter program, where we added incremental reserves and production. We anticipate drilling a total of approximately 50 operated wells by the end of the first quarter of 2007, depending on seasonal impacts, such as the start of break-up. Results to date from both our drilling and new completion and optimization programs are meeting our expectations, and in areas such as Acheson, we continue to be excited by both the results we are seeing and the inventory that we have in front of us. For the year, we continue to target annual average production of approximately 75,500 to 80,000 boe per day. Given current commodity prices, this production target should result in a payout ration of 65 to 75 percent at current distribution levels of $0.19 per unit per month. The balance of cash flow available should be sufficient to finance the majority of our capital expenditure program. In recent years the oil and natural gas industry has experienced significant increases in costs including labour, both in the field and head office, and all services, including power, pipe and drilling. We believe this trend may change following the Canadian Government's announcement on the taxation of trusts but more importantly in response to the recent weakness and volatility in commodity prices, which is expected to result in cutbacks in overall industry drilling activity. We currently intend to hold operating costs largely flat in 2007 at approximately $9.00 per boe and G&A costs at between $1.30 and $1.40 per boe. As we look forward, we intend to continue executing our business strategy, which involves a balanced approach to acquisitions and effective asset exploitation and management programs. Having completed over $4 billion in acquisitions since our inception, Canetic has accumulated an extensive inventory of development opportunities, including nearly one million net undeveloped acres. As a result we do not feel it is necessary to complete any significant acquisitions in the near term though we will continue to monitor both asset and corporate acquisition opportunities which may arise as a result of the changing environment for trusts in Canada, including potential consolidation opportunities within the sector, unconventional opportunities, or expansion opportunities outside of Canada, particularly in the U.S. In the meantime, Canetic will continue to focus on the development and exploitation of its significant resource base. We look forward to an exciting and successful 2007. Jack C. Lee J. Paul Charron Chairman President & Chief Executive Officer March 8, 2006 MANAGEMENT'S DISCUSSION AND ANALYSIS This Management's Discussion and Analysis ("MD&A") should be read in conjunction with the Consolidated Financial Statements and Notes thereto of Canetic Resources Trust ("Canetic" or the "Trust") for the year ended December 31, 2006. This MD&A is dated March 8, 2007. The Consolidated Financial Statements have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). This discussion provides Management's analysis of Canetic's historical financial and operating results and provides estimates of Canetic's future financial and operating performance based on information currently available. Actual results will vary from estimates and the variances may be material. You should be aware that historical results are not necessarily indicative of future performance. Readers are referred to the legal advisories regarding forward-looking information contained in this news release. FEDERAL GOVERNMENT'S PROPOSED TAXATION OF INCOME TRUSTS On October 31, 2006, the Federal Minister of Finance announced a Tax Fairness Plan for Canadians. A principal component of the government's plan involved changing the taxation rules governing publicly-listed income trusts and other public "flow-through entities". The creation of this new tax regime for publicly listed flow-through entities reflects a fundamental shift in the tax system which will significantly impact the strategic direction of the income trust model. Existing income trusts, such as Canetic, would be subject to the new rules starting in 2011. Under the proposed rules, distributions paid or payable to unitholders would no longer be deductible at the Trust level, and would be subject to the new tax at a rate of 31.5 percent. The effect would essentially tax income in the trust structure in a similar manner and at similar rates to public corporations. It is expected that this tax would apply to all of the Trust's income in excess of available tax shelter. At the investor level, distributions will be considered taxable dividends and eligible for the dividend tax credit mechanism. As such, the after-tax yield to taxable Canadian resident investors in 2011 will remain approximately the same. The after-tax distribution yield for tax-deferred investors will be reduced significantly and be dependent upon the tax shelter available in the Trust. On December 15, 2006, the Federal Government announced safe harbour guidance with respect to "normal growth" for flow-through entities. Existing income trusts, are provided an exemption from the new tax until 2011, provided these guidelines are respected and the Trust does not experience "undue expansion" in the interim period. The guidelines are measured by reference to a trust's market capitalization on October 31, 2006 and allow cumulative increases in equity capital of 40 percent in 2007 and 20 percent each of the subsequent three years providing for a doubling of equity capital to the end of 2010. Growth in excess of these limits will be considered "undue expansion" and subject the Trust to the new tax regime prior to the end of the four year grace period. We do not believe these guidelines will materially limit our near-term growth opportunities as the Trust could issue approximately $4.5 billion in additional equity under these guidelines prior to the end of 2010. On December 21, 2006, the Government released detailed draft legislation with respect to the new tax proposals and has requested comments from interested stakeholders. Recently, these tax proposals have been the subject of special hearings before the House of Commons Standing Committee on Finance. The Committee has subsequently released their findings and has recommended substantial changes to the legislation as currently proposed including a reduction of the rate from 31.5% to 10% and an extension of the grace period for existing trusts from 4 years to 10 years. It is unclear what effect, if any, these recommendations will have on the final form of the legislation to be tabled in the House of Commons. We are also presently unable to predict when these proposals may become enacted into law. These proposals have had significant implications for the Trust and our investors. Shortly after the announcement of the new rules, the valuation of Canetic and other trusts was significantly reduced to reflect the loss of our tax advantage. In 2011, when the rules are effective, distributions will be reduced to reflect the tax. Although most taxable Canadian investors should be indifferent, the reduced distributions will be a sunk cost to investors such as pension funds, registered retirement savings plans and non-resident investors who may not be able to utilize the dividend tax credit. Canetic is currently working with the Canadian Association of Income Funds (CAIF) and the Coalition of Canadian Energy Trusts to effect change to the legislation as proposed. A main focus is ensuring that the facts related to income trusts are understood and that all data is made available by the Minister to the investing public and other members of Parliament. It is premature at this time to determine what Canetic's course of action will be as 2011 approaches. Until the legislation is enacted, the rules fully understood and all options have been assessed, we are not in a position to commit to any strategic changes. In the short-term, we are focused on our business and executing on our capital program. SELECTED CONSOLIDATED FINANCIAL AND OPERATING INFORMATION The results of operations in 2006 in comparison to 2005 and 2004 are outlined under the section, "Results of Operations". A) ANNUAL FINANCIAL INFORMATION ($000s except per unit amounts) Year ended December 31 2006 2005 2004 ------------------------------------------------------------------------- Petroleum and natural gas sales 1,407,754 800,249 521,514 ------------------------------------------------------------------------- Funds flow from operations 750,146 360,475 233,473 Per unit - basic(1)(2) 3.64 4.04 3.13 Per unit - diluted(1)(2) 3.57 3.98 3.09 ------------------------------------------------------------------------- Net earnings 223,101 65,848 31,263 Per unit - basic(1)(2) 1.08 0.74 0.42 Per unit - diluted(1)(2) 1.06 0.73 0.42 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Balance Sheet Information Total distributions 583,528 208,477 176,741 Distributions per unit 2.76 2.34 2.34 Total assets 5,830,976 1,571,097 1,559,201 Working capital deficiency 29,794 45,630 27,800 Long-term debt 1,289,678 309,146 283,845 Unitholders' equity 3,506,915 764,583 780,980 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted average trust units outstanding (thousands) 206,081 89,331 74,650 Trust units outstanding at year end (thousands) 225,796 91,583 86,313 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) When calculating the weighted average number of units at the end of a quarter, all units outstanding from the previous quarter are deemed to be outstanding for the entire period, whereas in the year to date calculation those units are weighted according to the date of issue. Consequently, the addition of the quarterly per unit results, will not add to the annual earnings per unit. (2) All units of Acclaim up to the merger on January 5, 2006, have been restated using the exchange ratio of 0.8333 of a Canetic trust unit for each Acclaim trust unit. ($000s except per unit amounts) 2006 ------------------------------------------------------------------------- Earnings Information Dec. 31 Sept. 30 Jun. 30 Mar. 31 ------------------------------------------------------------------------- Production Oil and NGLs (bbl/d) 43,402 44,239 42,391 43,388 Natural gas (mmcf/d) 221.2 181.4 166.0 176.1 Boe/d 80,276 74,475 70,061 72,737 Petroleum and natural gas sales 347,701 368,502 341,205 350,346 Funds flow from operations 170,082 200,268 185,053 194,741 Per unit - basic(1)(2) 0.76 0.95 0.92 0.97 Per unit - diluted(1)(2) 0.75 0.93 0.89 0.96 Net earnings (loss) (21,632) 102,663 82,875 59,195 Per unit - basic(1)(2) (0.10) 0.49 0.41 0.29 Per unit - diluted(1)(2) (0.10) 0.48 0.40 0.29 Distributions declared Per unit 0.69 0.69 0.69 0.69 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2005 ------------------------------------------------------------------------- Earnings Information Dec. 31 Sept. 30 Jun. 30 Mar. 31 ------------------------------------------------------------------------- Production Oil and NGLs (bbl/d) 21,915 22,323 23,249 24,741 Natural gas (mmcf/d) 105.8 107.4 100.6 104.1 Boe/d 39,541 40,227 40,017 42,089 Petroleum and natural gas sales 234,098 217,449 177,501 171,201 Funds flow from operations 106,477 92,679 80,516 80,803 Per unit - basic(1)(2) 1.16 1.03 0.92 0.92 Per unit - diluted(1)(2) 1.14 1.02 0.91 0.91 Net earnings (loss) 48,662 6,538 27,473 (16,825) Per unit - basic(1)(2) 0.53 0.07 0.31 (0.19) Per unit - diluted(1)(2) 0.53 0.07 0.31 (0.19) Distributions declared Per unit 0.5850 0.5850 0.5850 0.5850 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) When calculating the weighted average number of units at the end of a quarter, all units outstanding from the previous quarter are deemed to be outstanding for the entire period, whereas in the year to date calculation those units are weighted according to the date of issue. Consequently, the addition of the quarterly per unit results, will not add to the annual earnings per unit. (2) All units of Acclaim up to the merger on January 5, 2006, have been restated using the exchange ratio of 0.8333 of a Canetic trust unit for each Acclaim trust unit. Production volumes averaged 80,276 boe/d during the three months ended December 31, 2006, an increase of 8 percent from 74,475 boe/d reported for the third quarter of 2006. Crude oil prices weakened with the West Texas Intermediate ("WTI") price averaging US$60.22 per barrel in the fourth quarter, as compared to US$70.55 per barrel in the third quarter of 2006. The AECO Daily Spot price for natural gas however, averaged $6.69/mcf in the fourth quarter as compared to $5.55/mcf during the third quarter of 2006. The results of operations during the fourth quarter include the Samson acquisition from the date of closing, August 31, 2006. The transaction with StarPoint was accounted for as a purchase of StarPoint by Acclaim. Accordingly, the financial and operating results for the year ended December 31, 2006, include those of the StarPoint assets from the date of acquisition, January 5, 2006. Comparative results are those of Acclaim only. Quarter over quarter petroleum and natural gas sales are influenced by increases in production volumes and changes in commodity prices. Although commodity prices have increased significantly since the fourth quarter of 2004, some of the gains in oil prices were taken back during this quarter. In combination with increased production volumes from the ChevronTexaco property acquisition in June 2004, the StarPoint merger in January 2006 and the most recent acquisition which closed August 31, 2006, petroleum and natural gas sales have increased. The variation of net earnings, quarter over quarter, is primarily a result of changes in depletion rates, the provision for future income taxes and accounting for unrealized gains and losses on financial derivatives. Net earnings in the fourth quarter reflects a $95.4 million unrealized hedging gain based on the mark-to-market price of crude oil and natural gas at December 31, 2006 RESULTS OF OPERATIONS PRODUCTION Production volumes averaged 74,409 boe/d in 2006, compared to 40,460 boe/d in 2005 (2004 - 33,421 boe/d). The 84 percent increase in average 2006 production results from the StarPoint and Samson acquisitions which closed on January 5 and August 31, 2006 respectively. At the time of acquisition, the StarPoint assets were producing approximately 35,000 boe/d and the Samson assets approximately 13,500 boe/d. Production By Product 2006 2005 2004 ------------------------------------------------------------------------- Natural gas (mmcf/d) 186.3 104.5 94.2 Crude oil (bbl/d) 37,500 17,779 13,731 Natural gas liquids (bbl/d) 5,858 5,267 3,988 Barrels of oil equivalent (boe/d) 74,409 40,460 33,421 ------------------------------------------------------------------------- Percentage natural gas 42% 43% 47% Percentage crude oil and natural gas liquids 58% 57% 53% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Natural gas sales averaged 186.3 mmcf/d in 2006, 78 percent higher than the 104.5 mmcf/d reported for the same period in 2005 (2004 - 94.2 mmcf/d). Crude oil and NGLs production averaged 43,358 bbl/d, an increase of 88 percent from 23,046 bbl/d reported in the prior year (2004 - 17,719 bbl/d). Production By United Jurisdiction States B.C. Alberta Sask. Manitoba Total ------------------------------------------------------------------------- Natural gas (mmcf/d) 1.9 21.6 155.0 7.8 - 186.3 Crude oil (bbl/d) 268 201 19,073 16,765 1,193 37,500 Natural gas liquids (bbl/d) - 200 5,621 37 - 5,858 ------------------------------------------------------------------------- Total (boe/d) 585 4,001 50,527 18,102 1,193 74,409 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Percentage 0.8% 5.4% 67.9% 24.3% 1.6% 100.0% For the three months ended December 31, 2006, natural gas sales averaged 221.2 mmcf/d, 109 percent more than the 105.8 mmcf/d reported for the fourth quarter 2005. Crude oil and liquids production increased 98 percent to 43,402 bbl/d from 21,915 bbl/d reported for the same period a year earlier. Production volumes fluctuate day to day based on pipeline capacity restrictions, natural declines, inclement weather, down time due to normal repairs and maintenance and the timing of when new wells are brought on production. In 2006, our quarterly production volumes were impacted by unplanned turnarounds, tie-in delays and spring break-up. Fourth quarter production was affected by a planned September turnaround at Mitsue which extended into October and unseasonably cold weather in November and December which increased well down time. COMMODITY PRICES Benchmark Prices - (Annual Average) 2006 2005 2004 ------------------------------------------------------------------------- WTI Crude oil (US$/bbl) 66.25 56.56 41.40 NYMEX natural gas (US$/mcf) 7.07 8.55 6.14 AECO natural gas monthly index ($/mcf) 6.98 8.48 6.79 Canadian/U.S. Dollar Exchange Rate 0.8819 0.8253 0.7683 ------------------------------------------------------------------------- The price of West Texas Intermediate crude averaged US$66.25/bbl during 2006, up 17 percent from the average price of US$56.56/bbl for the same period in 2005. WTI during the fourth quarter decreased 6 percent from an average of US$70.55/bbl in the third quarter of 2006. West Texas Intermediate at Cushing, Oklahoma is the benchmark for North American crude oil prices. Canadian crude oil prices are determined by refiners' postings at major market hubs as Edmonton and Hardisty, Alberta. Canadian prices adjust WTI for the Canadian/U.S. exchange rate, transportation and quality differentials. NYMEX natural gas prices are referenced from Henry Hub, Louisiana. Western Canadian natural gas prices are referenced from AECO Hub in Alberta and are adjusted for heat content. Average Prices (before financial derivatives) 2006 2005 2004 ------------------------------------------------------------------------- Natural gas ($/mcf) 7.01 9.08 6.91 Crude oil ($/bbl) 60.61 57.78 46.44 Natural gas liquids ($/bbl) 47.84 40.44 34.18 ------------------------------------------------------------------------- For the year ended December 31, 2006, we received an average oil price of $60.61/bbl as compared to $57.78/bbl for the comparable period in 2005. Our average oil price during the quarter decreased 21 percent from an average of $67.27/bbl reported during the third quarter of 2006. High crude oil inventory levels across North America and pipeline apportionment problems in southeast Saskatchewan have caused Canetic's corporate average oil price differential to widen in relation to the benchmark NYMEX WTI futures contract over the past year. Our average natural gas price was $7.01/mcf for the year ended December 31, 2006 as compared to $9.08/mcf during the same period in 2005. The fourth quarter natural gas price averaged $6.90/mcf as compared to $6.21/mcf in the third quarter. The AECO Daily Index gas price averaged $6.43/mcf during 2006, down 26 percent from the average price of $8.73 for the same period in 2005. The AECO Daily Index price for the fourth quarter of 2006 was 21 percent higher than the third quarter 2006 price of $5.55/mcf. COMMODITY PRICE RISK MANAGEMENT The prices we receive for our petroleum and natural gas can fluctuate significantly due to supply and demand fundamentals which are influenced by weather patterns, the economic environment or political uncertainty. Our commodity price risk management program is designed to provide price protection on a portion of our future production in the event of an adverse commodity price movement, while retaining the opportunity to participate in favorable price movements. This practice allows us to generate stable cash flow for distributions and to ensure positive economic returns on capital development and acquisition activities. During 2006, we recorded a realized financial derivative loss of $8.5 million as compared to a loss of $80.2 million in 2005 (2004 - $39.4 million). The following commodity commitments have been put in place for 2007 and beyond as noted below: ------------------- ----------------------------------- ----------------- Commodity Contracts Annual Average ------------------- ----------------------------------- ----------------- Q1 Q2 Q3 Q4 Natural Gas 2007 2007 2007 2007 2007 2008 ------------------- ----------------------------------- ----------------- Fixed Price Volume (Gj/d) 5,000 50,000 50,000 20,163 31,250 - Fixed Price Average ($/Gj) $8.47 $7.32 $7.32 $7.51 $7.40 - Collar Volume (Gj/d) 100,000 80,000 80,000 86,667 86,667 22,500 Collar Floors $7.70 $6.74 $6.74 $6.92 $7.06 $7.00 Collar Caps $13.08 $9.62 $9.62 $10.74 $10.90 $11.23 Total Volume Hedged (Gj/d) 105,000 130,000 130,000 106,830 117,917 22,500 ------------------- ----------------------------------- ----------------- Q1 Q2 Q3 Q4 Crude Oil 2007 2007 2007 2007 2007 2008 ------------------- ----------------------------------- ----------------- Cdn Denominated Fixed Price Volume (bbl/d) 8,000 8,000 8,000 8,000 8,000 250 Cdn Denominated Fixed Price Average ($Cdn/bbl) $67.26 $67.26 $67.26 $67.26 $67.26 $72.20 US Denominated Fixed Price Volume (bbl/d) 1,500 1,500 1,500 1,500 1,500 - US Denominated Fixed Price Average ($US/bbl) $48.11 $48.11 $48.11 $48.11 $48.11 - Collar Volume (bbl/d) 6,000 6,000 6,000 6,000 6,000 5,000 Collar Floors ($US/bbl) $58.00 $58.00 $58.00 $58.00 $58.00 $63.00 Collar Caps ($US/bbl) $80.76 $80.76 $80.76 $80.76 $80.76 $83.23 Total Volume Hedged (bbl/d) 15,500 15,500 15,500 15,500 15,500 5,250 CURRENCY RISK MANAGEMENT The Canadian dollar averaged US$0.8819 during 2006 as compared to US$0.8261 for the same period last year. As the price of WTI crude oil is quoted in U.S. dollars, appreciation in the Canadian dollar reduces the average price received for our production. Canetic mitigates the impact of exchange rate fluctuations by either entering into foreign exchange contracts directly or executing some portion of our crude oil swaps in Canadian dollars. In 2006, Canetic had no foreign exchange contracts, but had entered into contracts for 6,000 bbl/d of its crude oil production using Canadian dollar denominated swaps. PETROLEUM AND NATURAL GAS SALES Revenue(1) ($000s ) 2006 2005 2004 ------------------------------------------------------------------------- Crude oil and natural gas liquids 931,884 454,124 283,292 Natural gas 475,870 346,125 238,222 ------------------------------------------------------------------------- Petroleum and natural gas sales 1,407,754 800,249 521,514 ------------------------------------------------------------------------- (1) Before financial derivative gains and losses. Crude oil and NGLs sales before derivative gains and losses increased 105 percent during the year to $931.9 million from $454.1 million in 2005 (2004 - $283.3 million). The increase is attributable to strong commodity prices throughout the year and the impact of increased production volumes associated with the Samson and StarPoint acquisitions. Average daily production of crude oil and NGLs increased to 43,358 bbl/d from 23,046 bbl/d in 2005. Natural gas sales increased 38 percent year over year from $346.1 million to $475.9 million. Natural gas prices in 2006 were 23 percent lower than those received in 2005, which negatively impacted revenue. Average daily sales of natural gas increased 78 percent to 186.3 mmcf/d in 2006 from 104.5 mmcf/d in 2005 primarily as a result of the volumes acquired from the acquisitions made during the year. For the three months ended December 31, 2006, petroleum and natural gas revenue totalled $347.7 million as compared to $234.1 million for the same period in 2005. The increase is attributable to higher production volumes. ROYALTIES Royalties ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Royalties, net of ARTC 258,260 175,723 103,957 % of petroleum and natural gas revenue 18.3% 22.0% 19.9% $/boe $ 9.51 $ 11.90 $ 8.50 ------------------------------------------------------------------------- ------------------------------------------------------------------------- We pay royalties to the owners of the mineral rights with whom we hold leases, including provincial governments. Overriding royalties are also paid to other parties according to contracts. In Alberta, where we produce the majority of our natural gas, a Crown royalty is invoiced on the Crown's share of production based on a monthly established Alberta Reference Price. The Alberta Reference Price is a monthly weighted average price of gas consumed in Alberta and natural gas exported from Alberta reduced for transportation and marketing allowances. For 2006, the Alberta Reference Price averaged $6.22/Gj or about $6.56/mcf. There is a maximum rate of 30 percent for new gas and 35 percent on old gas. The vast majority of our gas production is from new natural gas. In the 2006 gas price environment, we were subject to the maximum rates. Natural gas cost allowance, low productivity and other incentive schemes serve to reduce our effective royalty rate. The majority of our oil production is in Alberta and Saskatchewan. Royalty rates in both Alberta and Saskatchewan vary depending on the rate of production, oil prices and applicable incentives. For the year ended December 31, 2006, royalties totalled $258.3 million as compared to $175.7 million during the same period a year earlier. As a percentage of sales, royalties averaged 18.3 percent during 2006 as compared to 22 percent in the same period in 2005. For 2006, royalties averaged $9.51/boe or approximately 18.3 percent of Canetic's total petroleum and natural gas sales price (before hedging) of $51.83/boe. This compares to $11.90/boe or 22.0 percent of average sales price reported for the same period in 2005 (2004 - $8.50/boe). The reduced effective royalty rate results from the acquisition of properties that carry a lower royalty burden. For the three months ended December 31, 2006, royalties totalled $63.6 million as compared to $52.3 million during the same period a year earlier due to higher production volumes. During the fourth quarter, royalties as a percentage of sales averaged approximately 18.3 percent as compared to 16.9 percent in the third quarter. OPERATING COSTS Operating Costs ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Operating costs before unit-based compensation 249,623 125,448 98,001 Unit-based compensation: Cash expense 412 124 251 Accrued compensation 2,107 4,074 1,102 ------------------------------------------------------------------------- Total operating costs and unit-based compensation 252,142 129,646 99,354 ------------------------------------------------------------------------- ------------------------------------------------------------------------- $/boe before unit-based compensation $ 9.19 $ 8.49 $ 8.01 $/boe after unit-based compensation $ 9.28 $ 8.78 $ 8.12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Producing petroleum and natural gas involves many field activities including lifting the oil and natural gas to surface, as well as treating, processing, gathering and storing the commodities. Other costs involved in the production function include those incurred to operate and maintain the wells along with the leases and well equipment. Assets most suitable for the trust environment are generally more mature with more predictable production profiles. Operating costs associated with these types of assets will generally be higher on a unit-of-production basis reflecting the amount of manpower, repairs and maintenance required to keep the wells on production and the recovery techniques utilized to extract the reserves. Our operating costs net of processing fees and unit-based compensation, increased to $249.6 million compared to $125.4 million during the same period a year earlier (2004 - $98.0 million). On a unit-of-production basis, operating costs averaged $9.19/boe compared to $8.49/boe for the prior year (2004 - $8.01/boe). A general theme throughout the industry in 2005 and 2006 has been higher field service costs including higher energy and fuel costs, labour, trucking and other related mechanical services. These increases, combined with the operating cost structures inherited from acquisitions made, caused operating costs year-over-year to increase on a unit-of-production basis. In addition, certain assets within our portfolio, primarily in east central Alberta, are significantly more costly to operate. Although these assets increase our operating costs in total and on a per unit basis, they provide positive cash flow during a high commodity price cycle. Production Expense Variance Analysis ($000s) % Change ------------------------------------------------------------------------- Reported operating costs - 2005 125,448 ------------------------------------------------------------------------- Increase due to production volumes 105,260 85 Increase due to increased costs 18,915 15 ------------------------------------------------------------------------- Total increase 124,175 100 ------------------------------------------------------------------------- Reported operating costs - 2006 249,623 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the fourth quarter, operating costs before unit-based compensation totalled $71.4 million or $9.67 per boe as compared to $32.9 million or $9.05 per boe in 2005. Our estimate of $8.50 - $9.50/boe operating costs for the fourth quarter was impacted by a plant turnaround at Acheson in October and cold weather and associated repairs and maintenance in November required to restore production. The increase also reflects cost pressures due to industry activity. Canetic was also active in 2006 in completing operational activities associated with the EUB's guidelines for the suspension of existing wells, resulting in incremental costs incurred throughout the year. Although operating costs year-over-year increased on a unit-of-production basis, we are committed to managing operational efficiencies and maximizing field netbacks in all areas where we do business. As we continue to experience higher field costs throughout our asset base, considerable effort and focus is being given to operational efficiencies which will control operating costs on a unit-of-production basis. To date, Canetic has been successful in maintaining control of our operational costs in a high priced operating environment and will continue to focus on doing so in 2007. PETROLEUM AND NATURAL GAS TRANSPORTATION Transportation ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Transportation expense 18,968 9,897 8,807 $/boe $ 0.70 $ 0.67 $ 0.72 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Transportation costs are defined by the point of legal custody transfer of the commodity and are dependent upon the type of product being sold, location of the producing asset, availability of pipeline capacity and sales point of the product. For crude oil, Canetic sells all of its production at the lease. The purchaser picks up the production at the lease and pays Canetic a price for the applicable crude type based upon a price posted at the appropriate market hub, less the transportation costs between that market hub and the lease. For natural gas, Canetic transports its natural gas from the plant gate to certain established market hubs such as AECO C in Alberta, at which point title transfers to the purchaser. In both cases, transportation costs associated with getting natural gas and clean marketable oil to the point of title transfer are shown separately as a transportation expense. NETBACKS Operating netbacks represent the profit margin associated with the production and sale of petroleum and natural gas. For 2006, our netbacks were influenced by our product mix, commodity prices, financial derivative losses, royalty rates, the appreciation in the Canadian dollar and higher operating costs. ------------------------------------------------------------------------- Cash Netbacks Per Unit Natural Of Production Oil Gas NGL's Total ------------------------------------------------------------------------- Conven- tional Heavy ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ------------------------------------------------------------------------- Sales Price 63.39 43.57 7.01 47.84 51.83 Less: Royalties 10.58 6.54 1.42 11.77 9.51 Operating costs 10.80 12.97 1.44 - 9.19 Transportation 0.24 0.23 0.22 0.25 0.70 ------------------------------------------------------------------------- Cash Netbacks Per Unit Of Production 41.77 23.83 3.93 35.82 32.43 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Components of our netbacks are as follows: Netbacks ($/boe) 2006 2005 2004 ------------------------------------------------------------------------- Petroleum and natural gas revenue 51.83 54.19 42.63 Less: Royalties 9.51 11.90 8.50 Operating costs 9.19 8.49 8.01 Transportation 0.70 0.67 0.72 ------------------------------------------------------------------------- Cash net operating income 32.43 33.13 25.40 General and administrative 1.46 1.46 1.39 Interest on long term debt 1.98 0.93 0.98 Interest on convertible debentures 0.32 0.30 0.37 Realized loss on financial derivatives 0.31 5.43 3.21 Capital tax 0.64 0.54 0.21 ------------------------------------------------------------------------- Cash netback from operations 27.72 24.47 19.24 Non-cash unit-based compensation 0.62 1.90 0.74 Depletion, depreciation and amortization 23.76 15.82 14.68 Accretion 0.42 0.31 0.25 Unrealized (gain) loss on financial derivatives (3.51) 1.40 0.91 Future income taxes (recovery) (1.78) 0.58 0.10 ------------------------------------------------------------------------- Net earnings 8.21 4.46 2.56 ------------------------------------------------------------------------- ------------------------------------------------------------------------- GENERAL AND ADMINISTRATIVE EXPENSES General and Administrative Expenses ($000s) 2006 2005 2004 ------------------------------------------------------------------------- G&A expenses 60,631 31,885 21,356 Overhead recoveries (20,925) (10,299) (4,343) ------------------------------------------------------------------------- Cash G&A expenses before unit-based compensation 39,706 21,586 17,013 Unit-based compensation: Cash expense 2,336 695 1,421 Accrued compensation 11,941 23,091 6,242 ------------------------------------------------------------------------- Total G&A and unit-based compensation 53,983 45,372 24,676 ------------------------------------------------------------------------- ------------------------------------------------------------------------- $/boe before unit-based compensation $ 1.46 $ 1.46 $ 1.39 $/boe after unit-based compensation $ 1.99 $ 3.07 $ 2.02 ------------------------------------------------------------------------- ------------------------------------------------------------------------- General and administrative expenses net of overhead recoveries and unit-based compensation totalled $39.7 million in 2006, as compared to $21.6 million in 2005 (2004 - $17.0 million). On a unit-of-production basis, general and administrative expenses averaged $1.46/boe as compared to $1.46/boe for the same period in 2005 (2004 - $1.39/boe). During 2006, we increased our head office staff in order to properly manage our business. The level of activity in the trust sector increased the cost of hiring qualified candidates and retaining existing employees and consultants. In 2006, approximately 66 percent of our total general and administrative expenses were labour related, including salary, benefits and consulting fees. For the three months ended December 31, 2006, general and administrative expenses increased slightly to $1.62 per boe (net of unit-based compensation), reflecting costs associated with hiring additional permanent staff, leasing additional office space and integrating the assets acquired during the third quarter. Unit-based Compensation On December 19, 2005, the unitholders of Canetic approved a unit award incentive plan. The plan authorizes the Board of Directors to grant rights to acquire up to five percent of the trust units outstanding to directors, officers, employees and consultants of the Trust and its affiliates. These rights consist of Restricted Trust Units ("RTU's") and Performance Trust Units ("PTU's"). The number of PTU's granted is dependent on the performance of the Trust relative to a peer comparison group of petroleum and natural gas trusts and other companies or other criteria the Board of Directors may determine. A holder of an RTU or PTU may elect, subject to consent of the Trust, to receive cash upon vesting in lieu of the number of units to be issued. The plan provides for adjustments to the number of units issued based on the cumulative distributions of the Trust during the period that the RTU or PTU is outstanding. The compensation issued upon vesting of the PTU's is dependant upon the performance of the Trust compared to its peers. The performance multiplier is based on our percentile rank of total unitholder return compared to a select group of peers approved by the Board of Directors. Total return is calculated as the sum of the change in market price plus distributions in the period divided by the opening market price. The performance multiplier ranges from zero, where our total return is less than the 35th percentile, to two, if our performance exceeds the 75th percentile. For the year ended December 31, 2006, the Trust recorded a compensation expense of $16.8 million (2005 - $28.0 million) and capitalized unit-based compensation of $3.4 million (2005 - $11.0 million). Upon vesting, the obligation may be settled in units or cash, therefore, the amounts due in the next year of $7.3 million (2005 - $40.8 million) has been classified as a current liability. The compensation liability is remeasured each period at the current market price. The December 31, 2006 compensation liability was based on the period-end closing price of $16.44 and the number of RTU's and PTU's outstanding at that time and the number of PTU's expected to vest using a PTU multiplier of 0.6. As of December 31, 2006, there were 915,916 RTU's and 1,386,377 PTU's outstanding. INTEREST EXPENSE ON LONG-TERM DEBT Interest Expense ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Interest expense 53,809 13,752 12,054 Bank loans, December 31 1,289,678 309,146 283,845 Debt to funds flow 1.7 0.9 1.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest expense, representing interest on bank debt increased to $53.8 million or $1.98 per boe from $13.8 million or $0.93 per boe a year earlier (2004 - $12.1 million or $0.98/boe). In addition to slightly higher interest rates due to increases in the Bank of Canada lending rate in 2006, average debt levels have increased as a result of the corporate and property acquisitions made during the year. At December 31, 2006, $1.29 billion was drawn under our facility. Although interest rates continue to be favourable and are not expected to increase substantially in the short-term, interest expense in future periods will reflect our higher debt levels. Average interest rates incurred by Canetic during 2006 averaged approximately 5.1 percent. INTEREST EXPENSE ON CONVERTIBLE DEBENTURES Interest expense on convertible debentures totalled $8.6 million for the year ended December 31, 2006 as compared to $4.4 million for the same period in 2005. During the year, debentures totaling $230.0 million were issued in conjunction with the Samson acquisition. At December 31, 2006, debentures totaling $263.2 million remain outstanding. For the three months ended December 31, 2006, interest expense increased to $19.6 million reflecting the increased debt levels incurred to finance the Samson acquisition. INTEREST RATE RISK MANAGEMENT Canetic has assumed through the StarPoint arrangement, fixed interest rate swaps between January 6, 2006 and September 30, 2007 covering $40.0 million of principal, with interest rates varying between 3.58 percent and 3.65 percent, plus a stamping fee. The fair value of the fixed interest swaps at December 31, 2006 was a gain of approximately $0.3 million. DEPLETION, DEPRECIATION AND AMORTIZATION The current year provision for depletion, depreciation and amortization totalled $645.2 million as compared to $233.7 million in 2005 (2004 - $179.6 million). On a unit-of-production basis, depletion, depreciation and amortization costs averaged $23.76 per boe as compared to $15.82 per boe in 2005 (2004 - $14.68/boe). The increase in the 2006 depletion rate results from the assets acquired in 2006. UNREALIZED LOSS ON FINANCIAL DERIVATIVES Accounting standards require that we determine the fair value of our financial contracts and record a liability or asset at the end of each accounting period. Any changes in the fair value of the financial contracts are included in net earnings for the period. At December 31, 2006, we recorded a current financial derivative liability of $1.1 million and a long-term financial derivative asset of $6.2 million. The estimated fair value is based on a mark-to-market calculation as at December 31, 2006 to settle the financial contracts. The actual gain or loss realized upon settlement could vary significantly due to fluctuations in commodity prices. At December 31, 2006, Canetic recorded an unrealized financial derivative gain of $95.4 million (2005-loss of $20.6 million) which represents the change in the mark-to-market calculations from December 31, 2005. Gain (Loss) On Financial Derivatives ($000s) 2006 2005 ------------------------------------------------------------------------- Realized cash loss on financial derivatives (8,465) (80,157) Unrealized gain (loss) on financial derivatives 95,371 (20,635) ------------------------------------------------------------------------- Gain (loss) on financial derivatives 86,906 (100,792) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligation was estimated by management based on the Trust's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the facilities and the estimated timing of the costs to be incurred in future periods. The costs are expected to be incurred over an average of 15 years. The estimated cash flow has been calculated using a credit adjusted risk free discount rate of 8 percent and an inflation rate of 2 percent. As of December 31, 2006, the amount to be recorded as the fair value of the liability was estimated to be $191.9 million (December 31, 2005 - $68.2 million). During this year, Canetic incurred $16.9 million (2005 - $6.3 million) of actual abandonment and reclamation costs and recorded accretion of $11.4 million (2005 - $4.6 million). INCOME TAXES Future Income Taxes Future income taxes arise from differences between the accounting and tax bases of assets and liabilities of certain operating subsidiaries of the Trust. The future taxes recorded on the balance sheet are expected to be recovered over time through interest and/or royalty payments to the Trust from its operating subsidiaries. The Trust is a taxable entity under Canadian tax law and is subject to cash taxes only to the extent that income is not distributed or distributable to its unitholders. As the Trust is required to distribute all of its taxable income to unitholders, the Trust is not expected to be subject to current or future income taxes. For the period ended December 31, 2006, a future tax recovery of $48.3 million was included in income compared to a future tax expense of $8.6 million in 2005. The change year-over-year was mainly due to a significant increase in temporary differences arising from the acquisition of StarPoint Energy Trust, increased depletion on recognition of purchase price increments. Also, reductions to future corporate tax rates were enacted during the year by Federal, Alberta and Saskatchewan governments resulting in a future tax recovery of $32 million. These were offset by a future tax expense of $33.6 million related to unrealized hedging gains. On October 31, 2006, the Federal Government announced a proposal to introduce a new tax on publicly traded income trusts beginning in 2011. On December 21, 2006, draft legislation to implement these proposals was released for comment. If the legislation becomes enacted as currently proposed, the Trust will effectively become subject to tax on earnings in excess of available tax pools, in a similar manner as a corporation. It is anticipated that future taxes would be then be adjusted to include temporary differences between accounting and tax bases of assets and liabilities at the Trust level. Current Income Taxes In general, both current and future income taxes are transferred to the unitholder level through various interest and/or royalty payments. There are some corporate entities in the underlying structure which hold minority interests in some of the Trust's operating partnerships which subject them to a small amount of current income tax. The Trust has provided $2 million in this respect for the current year and $4 million in respect of prior periods. Capital Taxes Federal Large Corporations Tax was eliminated effective January 1, 2006 and thus no amount is provided for federal capital taxes in respect of 2006. The Trust has recorded $12 million of capital tax for the year, of this amount, $11 million relates to the Saskatchewan Resource Surcharge and is higher compared to the previous year due to an increase in oil and gas revenue earned in the Province of Saskatchewan, a result of the significant number of Saskatchewan properties added through the StarPoint acquisition. Estimated Income Tax Pools ($000s) December 31, 2006 ------------------------------------------------------------------------- Undepreciated capital costs 505,232 Canadian oil and gas property expenses 611,509 Canadian exploration expenses 2,966 Canadian development expenses 285,662 Non-capital losses 276,270 Financing charges 48 ------------------------------------------------------------------------- Total estimated income tax pools 1,681,687 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CAPITAL EXPENDITURES Petroleum and natural gas reserves are a non-renewable resource. As they are produced, our objective is to replace those reserves through a combination of property acquisitions and internal drilling opportunities. In 2005 and 2006, we have continued to increase our focus on upgrading the quality of our asset base through acquisition, exploiting our reserve base, drilling new wells and optimizing existing production. Capital Expenditures ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Land 14,868 13,361 3,792 Geological and geophysical 2,783 3,139 1,067 Drilling and completion 215,593 100,182 56,493 Production equipment and facilities 118,044 55,539 30,418 ------------------------------------------------------------------------- Net development expenditures 351,288 172,221 91,770 Major acquisitions StarPoint 2,511,746 - - Samson 924,635 - - Producing properties 23,869 - 477,168 Minor property acquisitions 32,416 13,554 10,447 Minor property dispositions (17,167) (4,610) (9,280) ------------------------------------------------------------------------- Net capital expenditures 3,826,787 181,165 570,105 Office 8,134 4,667 3,609 Asset retirement obligation - change in estimate 56,537 11,319 13,043 Asset retirement obligation - Samson 18,228 - - Capitalized non-cash compensation 3,365 11,016 - Other non-cash 11,000 - - ------------------------------------------------------------------------- Total capital expenditures 3,924,051 208,167 586,757 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During 2006, expenditures for exploration and development activities totalled $351.3 million as compared to $172.2 million in 2005 (2004 - $91.8 million). A total of 378 gross (174.4 net) wells were drilled during the year, including 115 gross (48.8 net) wells in the fourth quarter, compared to 82 gross (52.4 net) wells during the fourth quarter 2005 resulting in 161 gross (81.9 net) oil wells and 205 gross (85.4 net) natural gas wells. The increase reflects the larger opportunity associated with our assets as a result of the acquisitions made in 2006. Of the total wells drilled in 2006, 102 gross (90.6 net) were operated by Canetic resulting in 64 gross (58.0 net) oil wells and 32 gross (26.9 net) natural gas wells. The Trust also completed two major acquisitions in 2006 totalling $3.5 billion. The StarPoint transaction was completed by way of a Plan of Arrangement whereby unitholders of Acclaim received 0.8333 units of Canetic for each unit held and unitholders of StarPoint received one Canetic unit for each unit held. Costs associated with the transaction were financed through our bank facility. The merger was strategic in that it provided unitholders with a high quality asset base; a reserve base in excess of 230 million boe on a proved plus probable basis; a reserve life index in excess of 9 years; a diversified production base weighted 60 percent towards primarily light oil and a high quality low risk development drilling program. On August 31, 2006, we closed the Samson acquisition which included properties in British Columbia and central Alberta. We acquired approximately 13,500 boe/d of production, 40.1 million boe of proved plus probable reserves and 230,000 net acres of undeveloped land. The acquisition was financed by the issuance of 20.8 million trust units for net proceeds of $437 million, as well as $230.0 million principal ($220.8 million net) of 6.5% convertible, extendible, unsecured, subordinated debentures. The balance of the transaction was financed with bank debt. In addition, we also acquired approximately $87 million of working capital including $77 million of cash which was financed with long-term debt. Sources Of Funding Net Capital Expenditures Acquisitions Net -------------------------------- Development StarPoint Samson Other Total ------------------------------------------------------------------------- ($million) Net Capital Expenditures $ 351.3 $ 2,511.7 $ 924.6 $ 39.2 $ 3,826.8 ------------------------------------------------------------------------- Percentage funded by: Cashflow 47% - - - 5% DRIP 14% - - - 1% Issuance of equity - 99% 47% - 77% Issuance of debentures - - 24% - 6% Bank debt 39% 1% 29% 100% 11% ------------------------------------------------------------------------- 100% 100% 100% 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- GOODWILL The Trust recognizes goodwill on corporate acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. Goodwill is tested annually at year-end for impairment or as events occur that could result in impairment. Impairment is recognized and charged to income in the period in which the impairment occurs when the fair value of the Trust is less than the book value of the Trust. A write down of goodwill was not required at December 31, 2006 or 2005. The goodwill balance of $943.8 million arose primarily as a result of the StarPoint acquisition in 2006. The balance was determined based on the excess of total consideration plus the future income tax liability less the fair value of the assets acquired for accounting purposes. LIQUIDITY AND CAPITAL RE

SOURCES As an oil and gas trust we have a declining asset base and therefore rely on acquisitions and ongoing development activities to mitigate production and reserve declines. Future production volumes and reserves are highly dependent on our success in exploiting our asset base and acquiring addition reserves. The increase in capital expenditures in 2006 reflects both the costs associated with maintaining the larger producing asset base we now have, as well as the execution of growth programs that continue to be developed as we increase our operational knowledge of the properties acquired over the past three years. We finance our operations and capital activities primarily with funds generated from operating activities, but also through the issuance of trust units, debentures and borrowings from our credit facility. The amount of equity we raise through the issuance of trust units depends on many factors including projected cash needs, availability of funding through other sources, our unit price and the state of the capital markets. We believe our sources of cash, including bank debt, will be sufficient to fund our operations and anticipated capital expenditure program in 2007 as well as make monthly distribution payments. Our ability to fund will also depend on performance and is subject to commodity prices and other economic conditions which are beyond our control. In August 2006, in connection with the Samson acquisition, Canetic completed a $690 million bought deal equity and debenture issue. The net proceeds of $657.8 million in addition to bank borrowings under our credit facility were utilized to fund the acquisition. In addition, Canetic purchased working capital at May 31, 2006, of $89.1 million by drawing upon its bank facility. Working capital included approximately $77 million of cash. Under the terms of the agreement Canetic will be kept whole in the event of uncollectability or valuation of working capital. Canetic's capital structure at December 31, 2006 is reconciled as follows: 2006 2005 ($000s except per unit amounts) Amount % $/unit Amount % $/unit ------------------------------------------------------------------------- Debt Bank debt 1,289,678 25 5.71 309,146 27 3.38 Working capital deficiency 29,794 1 0.13 74,466 6 0.81 ------------------------------------------------------------------------- Net debt 1,319,472 26 5.84 383,612 33 4.19 Convertible debentures 258,959 5 1.15 16,289 1 0.18 Unitholders' equity 3,506,915 69 15.53 764,583 66 8.35 ------------------------------------------------------------------------- Total capitalization 5,085,346 100 22.52 1,164,484 100 12.72 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Bank Debt Canetic has an unsecured covenant based credit facility with a syndicate of financial institutions in the amount of $1.6 billion including a $50.0 million operating facility. The facility carries floating interest rates which range between 65.0 and 115.0 basis points over Banker's Acceptance rates. This facility was increased in the third quarter from $1.1 billion upon closing of the Samson acquisition. The loan has a maturity date of May 31, 2009 and is reviewed annually and may be extended at the option of the lender for an additional 1 year period. The loan has therefore been classified as long-term on the balance sheet. At December 31, 2006, $1.29 billion was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At December 31, 2006, Canetic had a working capital deficiency of $29.8 million including a financial derivative liability of $1.1 million. The increase in bank debt year over year includes $293.5 million drawn on the facility related to the acquisition of Samson which closed on August 31, 2006. As part of this acquisition, Canetic acquired $89.1 million of working capital including $77 million of cash at May 31, 2006. Our net debt at December 31, 2006 and 2005 is reconciled as follows: December 31, 2006 December 31, 2005 ------------------------------------------------------------------------- Star- ($000s) Acclaim Point(1) Total ------------------------------------------------------------------------- Bank debt 1,289,678 309,146 434,123 743,269 Working capital deficiency 29,794 45,630 101,477 147,107 ------------------------------------------------------------------------- Net debt 1,319,472 354,776 535,600 890,376 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) As at closing, January 5, 2006 Convertible Debentures As at December 31, 2006, we had convertible debentures outstanding of $260.7 million. The debentures consist of the StarPoint 9.4% convertible, unsecured, subordinated debentures; StarPoint 6.5% convertible, extendible, unsecured, subordinated debentures; Acclaim 8% convertible, extendible, unsecured, subordinated debentures; Acclaim 11% convertible, extendible, unsecured, subordinated debentures and Canetic 6.5% convertible, extendible, unsecured, subordinated debentures. The StarPoint debentures are described further below. The debentures are convertible into Canetic trust units at the following conversion prices: - StarPoint 9.4% Debentures (CNE.DB.A) - $16.02. Each $1,000 principal amount of 9.4% Debentures is convertible into approximately 62.42 Canetic trust units; - StarPoint 6.5% Debentures (CNE.DB.B) - $18.96. Each $1,000 principal amount of StarPoint 6.5% Debentures is convertible into approximately 52.74 Canetic trust units; - Acclaim 8% Debentures (CNE.DB.C) - $15.56. Each $1,000 principal amount of 8% Debentures is convertible into approximately 64.27 Canetic trust units; - Acclaim 11% Debentures (CNE.DB.D) - $11.24. Each $1,000 principal amount of 11% Debentures is convertible into approximately 88.97 Canetic trust units; and - Canetic 6.5% Debentures (CNE.DB.E) - $26.55. Each $1,000 principal amount of Canetic 6.5% Debentures is convertible into approximately 37.66 Canetic trust units. The following table is a summary of the dollar value of issuances and conversions of the convertible debentures: ------------------------------------------------------------------------- ($000s) 9.4% 6.5% 8% ------------------------------------------------------------------------- (CNE.DB.A) (CNE.DB.B) (CNE.DB.C) Balance, December 31, 2004 $ - $ - $ 72,901 Converted to units - (59,330) ------------------------------------------------------------------------- Balance, December 31, 2005 - - 13,571 Acquisition of StarPoint 9,255 43,944 - Samson acquisition - - - Converted to units (3,633) (26,123) (5,525) ------------------------------------------------------------------------- Balance, December 31, 2006 $ 5,622 $ 17,821 $ 8,046 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ($000s) 11% 6.5% ------------------------------------------------------------------------- (CNE.DB.D) (CNE.DB.E) Total Balance, December 31, 2004 $ 6,562 $ - $ 79,463 Converted to units (3,844) (63,174) ------------------------------------------------------------------------- Balance, December 31, 2005 2,718 - 16,289 Acquisition of StarPoint - - 53,199 Samson acquisition - 227,470 227,470 Converted to units (1,021) - (36,302) ------------------------------------------------------------------------- Balance, December 31, 2006 $ 1,697 $ 227,470 $ 260,656 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (000s) 9.4% 6.5% 8% ------------------------------------------------------------------------- Units Issuable Upon Conversion (CNE.DB.A) (CNE.DB.B) (CNE.DB.C) Balance, December 31, 2004 - - 5,401 Converted to units - - (4,395) ------------------------------------------------------------------------- Balance, December 31, 2005 - - 1,006 Adjustment to conversion ratio - - (135) Acquisition of StarPoint 576 2,313 - Samson acquisition - - - Converted to units (225) (1,373) (354) ------------------------------------------------------------------------- Balance, December 31, 2006 351 940 517 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (000s) 11% 6.5% ------------------------------------------------------------------------- Units Issuable Upon Conversion (CNE.DB.D) (CNE.DB.E) Total Balance, December 31, 2004 672 - 6,073 Converted to units (394) - (4,789) ------------------------------------------------------------------------- Balance, December 31, 2005 278 - 1,284 Adjustment to conversion ratio (36) - (171) Acquisition of StarPoint - - 2,889 Samson acquisition - 8,663 8,663 Converted to units (90) - (2,042) ------------------------------------------------------------------------- Balance, December 31, 2006 152 8,663 10,623 ------------------------------------------------------------------------- On August 24, 2006, Canetic issued $230.0 million principal amount of 6.5% convertible, extendible, unsecured, subordinated debentures to partially fund the Samson acquisition. The conversion feature was valued at $2.5 million which has been allocated to equity. The debentures have a face value of $1,000 per debenture, a coupon of 6.5%, a maturity date of December 31, 2011 and are convertible at any time, at the option of the holder, into the trust units of Canetic at a conversion price of $26.55 per trust unit. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after December 31, 2009 and at a redemption price of $1,025 per debenture after December 31, 2010 and before the maturity date. On June 15, 2004, Acclaim issued $75.0 million principal amount of 8% convertible, extendible, unsecured, subordinated debentures. The debentures have a face value of $1,000 per debenture, a coupon of 8.0%, a maturity date of August 31, 2009 and are convertible at any time, at the option of the holder, into trust units of Canetic at a price of $15.56 per trust unit. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after August 31, 2007 and at a redemption price of $1,025 per debenture after August 31, 2008 and before the maturity date. In December 2002, Acclaim issued $45.0 million principal amount of 11% convertible, extendible, unsecured, subordinated debentures. The debentures have a face value of $1,000 per debenture, a coupon of 11%, a maturity date of December 31, 2007 and are convertible at any time, at the option of the holder, into trust units of Canetic at a price of $11.24 per trust unit. The Trust may redeem the debentures in whole or in part at a redemption price of $1,025 per debenture before the maturity date. Convertible Debentures Assumed on Acquisition of StarPoint StarPoint issued $60.0 million of 6.5% convertible, extendible, unsecured, subordinated debentures (the "StarPoint 6.5% Debentures") on May 26, 2005. The StarPoint 6.5% Debentures mature on July 31, 2010 and are convertible at any time, at the option of the holder, into the trust units of Canetic at a conversion price of $18.96 per trust unit. The StarPoint 6.5% Debentures are not redeemable at the option of the Trust on or before July 31, 2008. After July 31, 2008, and prior to the maturity date, the StarPoint 6.5% Debentures may be redeemed in whole or in part, at a price of $1,050 per debenture after July 31, 2008 and after July 31, 2009 at a price of $1,025 per debenture. In connection with the StarPoint/APF Energy Trust Combination, and pursuant to a debenture agreement dated June 27, 2005, the 9.4% Debentures were assumed by StarPoint. The 9.4% unsecured, subordinated, convertible debentures are convertible at the holder's option into fully paid and non-assessable trust units of Canetic at any time prior to July 31, 2008 at a conversion price of $16.02 per trust unit. The 9.4% Debentures are redeemable at $1,050 per 9.4% Debenture, in whole or in part, after July 31, 2006 and redeemable at $1,025 per debenture after July 31, 2007 and before maturity. Trust Unit Capital As at December 31, 2006, we had issued capital of 225.8 million units and as at March 7, 2007, we had issued capital of 226.6 million units. If all the outstanding convertible debentures were converted into units, a total of 236.4 million units would have been outstanding as at December 31, 2006 and 237.2 million units as at March 7, 2007. The merger of Acclaim and StarPoint on January 5, 2006, occurred pursuant to a Plan of Arrangement in which Canadian unitholders could elect to exchange their units on a tax-deferred basis. Each Acclaim unitholder received 0.8333 of a Canetic trust unit for each unit held and each StarPoint unitholder received 1.0000 Canetic trust unit for each unit they held. A total of 106.2 million units were issued pursuant to the arrangement. Also pursuant to the Arrangement, all exchangeable shares were exchanged for trust units. a) Trust Units 2006 2005 ------------------------------------------------------------------------- Units Units (000s) Amount (000s) Amount ------------------------------------------------------------------------- Balance, beginning of year 91,583 $ 1,087,459 86,313 $ 1,003,294 Issued for cash: Acquisition of Samson, net of costs 20,769 437,001 - - Pursuant to equity offering, net of costs - - - (350) Employee Unit Savings Plan 274 6,184 89 1,646 Distribution reinvestment plan 2,470 44,825 456 8,492 Issued pursuant to Arrangement 106,242 2,562,563 - - Properties contributed to TriStar - (5,000) - - Conversion of debentures 2,042 36,302 3,990 63,174 Conversion of debentures - equity portion - 4,636 - - Conversion of exchangeable shares 358 3,804 357 4,033 Unit award incentive plan 2,058 46,696 378 7,170 ------------------------------------------------------------------------- Balance, end of year 225,796 $ 4,224,470 91,583 $ 1,087,459 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Units Amount (000s) ($000s) (Restated b) Exchangeable Shares - Note 1) ------------------------------------------------------------------------- Balance, December 31, 2004 673 7,837 Shares exchanged (357) (4,033) Adjustment to exchange ratio for distributions 42 - ------------------------------------------------------------------------- Balance, December 31, 2005 358 3,804 Shares exchanged (358) (3,804) ------------------------------------------------------------------------- Balance, December 31, 2006 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Funds Flow from Operations Funds flow from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Funds flow from operations is reconciled as follows: Funds Flow ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Net Earnings 223,101 65,848 31,263 ------------------------------------------------------------------------- Adjustments for: Unit-based compensation expense 14,049 27,166 7,344 Depletion, depreciation and amortization 645,203 233,693 179,557 Accretion 11,410 4,560 3,045 Unrealized gain on financial derivatives (95,371) 20,635 11,093 Future income taxes (48,246) 8,573 1,171 ------------------------------------------------------------------------- Funds flow from operations 750,146 360,475 233,473 ------------------------------------------------------------------------- Unitholder's equity 3,506,915 764,583 780,980 ------------------------------------------------------------------------- For the year ended December 31, 2006, funds flow from operations totalled $750.1 million or $3.57 per diluted unit, representing a 108 percent increase from the $360.5 million, or $3.98 per diluted unit during the same period in 2005 (2004 - $233.5 million or $3.09 per diluted unit). The increase is due to higher production levels associated with the StarPoint and Samson acquisitions. Our 2006 funds flow included a realized loss on financial derivative contracts of $8.5 million ($0.04 per diluted unit) as compared to a loss of $80.2 million ($0.88 per diluted unit) in 2005. Funds flow for the fourth quarter was $170.1 million or $0.75 per diluted unit as compared to $106.5 million or $1.15 per diluted unit during the same quarter in 2005 (2004 - $73.8 million or $0.84 per diluted unit). The increase is attributable to an increase in production due to the StarPoint and Samson acquisitions. We believe that funds generated from our operations, together with borrowings under our credit facility and proceeds from property dispositions, will be sufficient to finance our operations and planned capital expenditure program. During 2006, funds flow in excess of distributions funded 47 percent of our capital expenditure program. Our dividend reinvestment program plus additional bank borrowings funded the remaining 53 percent or $186.2 million. We anticipate that our annual capital expenditures over the next few years will be similar to our capital expenditures in fiscal 2006. We establish our capital expenditure program based on an annual budget review process, including budgeted cash flow from operations, and we closely monitor changes throughout the year. Cash Distributions Canetic declared cash distributions of $583.5 million ($2.76/unit), representing 78 percent of 2006 funds flow from operations compared to cash distributions of $208.5 million ($2.34/unit), representing 58 percent of funds flow from operations in 2005. The remaining 22 percent of funds flow in 2006 was utilized to fund 47 percent of Canetic's 2006 capital program. Effective with the merger with StarPoint, Canetic set its monthly distribution at $0.23 per unit per month beginning with distributions payable on February 15, 2006. This represented an 18 percent increase to former Acclaim unitholders and a five percent increase to former StarPoint unitholders. ($000s, except where indicated) 2006 2005 2004 ------------------------------------------------------------------------- Funds flow from operations 750,146 360,475 233,473 Total distributions 583,528 208,477 176,741 Distributions per unit ($) 2.76 2.34 2.34 Payout ratio (%) 78% 58% 74% ------------------------------------------------------------------------- ------------------------------------------------------------------------- In aggregate our distributions and net capital expenditure program totalled approximately $4.4 billion or approximately 586% of our 2006 cash flow of $750.1 million. We fund our distributions and capital expenditure programs with cash flow, but also supplement growth and fund acquisitions with long-term debt and equity. We distribute a portion of the funds flow from operations to our Trust unitholders on a monthly basis with a portion withheld to initially repay bank debt and ultimately fund capital expenditures. Although the level of funds retained for capital expenditures and/or debt repayment typically varies, we monitor our distribution policy with respect to forecasted funds flows from operations, debt levels, spending plans and taxability. Our 2006 distributions are summarized as follows: Value of Units Number Total Distri- Issued of DRIP ($000, except Distri- butions under Units Unit where indicated) butions Paid DRIP Issued Price ------------------------------------------------------------------------- Distributions declared: December 2006 51,933 47,793 4,140 284,172 $ 14.57 November 2006 51,848 46,743 5,104 330,490 $ 15.44 October 2006 51,739 45,419 6,321 424,474 $ 14.90 September 2006 51,642 45,289 6,353 374,054 $ 16.98 August 2006 51,577 47,029 4,548 225,495 $ 20.18 July 2006 46,699 41,236 5,463 252,973 $ 21.61 June 2006 46,583 42,538 4,045 189,023 $ 21.40 May 2006 46,516 42,570 3,946 184,238 $ 21.48 April 2006 46,439 43,175 3,264 145,356 $ 22.46 March 2006 46,272 43,230 3,042 130,570 $ 23.29 February 2006 46,208 43,629 2,579 119,674 $ 21.55 January 2006 46,072 46,000 72 3,175 $ 22.70 -------------------------------------------------------------- Total 583,528 534,651 48,877 2,663,694 -------------------------------------------------------------- -------------------------------------------------------------- In light of the weaker short-term outlook for commodity prices, Canetic announced on January 15, 2007 that it would reduce the monthly distribution in order to increase the level of cash flow available to fund drilling and development opportunities, bring Canetic's payout ratio in line with the Trust's long-term target of 60 to 70 percent of funds flow from operations, and prudently manage the level of Canetic's long-term debt. The regular monthly distribution was fixed at $0.19 per trust unit, commencing with the January 31, 2007 distribution paid on February 15, 2007. For the year ended December 31, 2006, we declared distributions of $583.5 million ($2.76 per unit) which represented 78 percent of funds flow from operations as compared to cash distributions of $208.5 million ($2.34 per unit) representing a 58 percent payout ratio in 2005. For the three months ended December 31, 2006, our payout ratio increased to 91 percent as we generated $170.1 million of funds flow from operations and distributed $155.5 million. CONTRACTUAL OBLIGATIONS In addition to financial derivative commitments, the Trust has the following contractual obligations as at December 31, 2006: ------------------------------------------------------------------------- ($000s) Total 2007 2008 2009 2010 2011 Thereafter ------------------------------------------------------------------------- Credit facility 1,289,678 - - - - - 1,289,678 Convertible debentures 260,656 1,697 5,622 8,046 17,821 227,740 - Office lease 24,659 6,415 6,295 6,295 3,231 2,423 - Pipeline contract 6,116 636 802 814 877 823 2,164 ------------------------------------------------------------------------- Total 1,581,109 8,748 12,719 15,155 21,929 230,986 1,291,842 ------------------------------------------------------------------------- ------------------------------------------------------------------------- TAXATION OF CASH DISTRIBUTIONS The following sets out a general discussion of the Canadian and U.S. tax consequences of holding Canetic units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular tax consequences. CANADIAN TAXPAYERS The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and, accordingly, trust units are qualified investments for RRSP's, RRIF's, RESP's and DPSP's. Each year, the Trust is required to file an income tax return and any taxable income of the Trust is allocated to unitholders. Unitholders are required to include in computing income their pro-rata share of any taxable income earned by the Trust in that year. An investor's adjusted cost base ("ACB") in a trust unit equals the purchase price of the unit less any non-taxable cash distributions received from the date of acquisition. To the extent the unitholders' ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholders' ACB will be brought to nil. Canetic paid $2.76 per trust unit in cash distributions to unitholders during the period February 2006 to January 2007. For Canadian tax purposes, 100 percent of these distributions are taxable as other income. During the same period in 2005, the Trust paid $1.95 per trust unit in cash distributions, of which 31.28 percent was a tax-deferred return of capital and 68.72 percent taxable. The taxability of our distributions increased during 2006, a direct result of increased cash flows due to strong commodity prices and limited tax pools associated with the acquired assets. U.S. TAXPAYERS Prior to 2005, U.S. unitholders who received cash distributions were subject to a 15 percent withholding tax, applied only on the taxable portion of the distribution as computed under Canadian tax law. Legislative changes which took effect on January 1, 2005, imposed an additional 15 percent withholding tax on the non-taxable portion of the distribution. U.S. taxpayers should be eligible for a foreign tax credit with respect to 100 percent of Canadian withholding taxes paid. The taxable portion of the cash distributions is determined by the Trust in relation to its current and accumulated earnings and profit using U.S. tax principles. The taxable portion so determined, is considered to be a dividend for U.S. tax purposes. For most taxpayers, these dividends should be considered "Qualifying Dividends" and eligible for a reduced rate of tax. The non-taxable portion of the cash distributions is a return of the cost (or other basis). The cost (or other basis) is reduced by this amount for computing any gain or loss from disposition. However, if the full amount of the cost (or other basis) has been recovered, any further non-taxable distributions should be reported as a gain. Canetic paid US$2.23 per trust unit to US residents during the calendar year 2006. The portion considered to be a qualified dividend will be announced immediately upon completion of the Trust's calculation of current earnings and accumulated deficit for the year. RISK MANAGEMENT Investors who purchase our units are participating in the net funds flow from a portfolio of western Canadian crude oil and natural gas producing properties. As such, the funds flow paid to investors and the value of the units are subject to numerous risks inherent in the industry. Our expected funds flow from operations depends largely on the volume of petroleum and natural gas production and the price received for such production, along with the associated operating costs and taxability of distributions. The price we receive for our oil depends on a number of factors, including West Texas Intermediate oil prices, Canadian/U.S. currency exchange rates, quality differentials and Edmonton par oil prices. The price we receive for our natural gas production is primarily dependent on current Alberta market prices. Canetic has an ongoing commodity price risk management policy that provides for downside protection on a portion of its future production while allowing access to the upside price movements. Acquisition of oil and natural gas assets depends on our assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the units. We employ experienced staff on the business development team and perform stringent levels of due diligence on our analysis of acquisition targets, including a detailed examination of reserve reports; re-engineering of reserves for a large portion of the properties to ensure the results are consistent; site examinations of facilities for environmental liabilities; detailed examination of balance sheet accounts; review of contracts; review of prior year tax returns and modeling of the acquisition to ensure accretive results to the unitholders. The Board of Directors approves all acquisitions greater than $5 million. Inherent in development of the existing oil and gas reserves are the risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. To minimize these risks, we employ experienced staff to evaluate and operate wells and utilize appropriate technology in our operations. In addition, we use prudent work practices and procedures, safety programs and risk management principles, including insurance coverage against potential losses. We are subject to credit risk associated with the purchase of the commodities produced. In order to mitigate the risk of non-payment, we minimize the total sales value with any particular purchaser. The value of our trust units is based on the underlying value of the oil and natural gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and gas prices increase the risk of write-downs on our oil and gas property investments. In order to mitigate this risk, our proven and probable oil and gas reserves are evaluated each year by a firm of independent reservoir engineers. A special committee of the Board of Directors reviews and approves the reserve report. Our access to commodity markets may be restricted at times by pipeline or processing capacity. We minimize these risks by controlling as much of our processing and transportation activities as possible and ensuring transportation and processing contracts are in place with reliable cost efficient counterparties. The petroleum and natural gas industry is subject to extensive controls, regulatory policies and income and resource taxes imposed by various levels of government. These regulations, controls and taxation policies are amended from time to time. We have no control over the level of government intervention or taxation in the petroleum and natural gas industry. However, we operate in such a manner to ensure that we are in compliance with all applicable regulations and are able to respond to changes as they occur. The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. We have reviewed our environmental risks and are in compliance with the appropriate environmental legislation and have determined that there is no current material impact on our operations. We are subject to financial market risk. In order to achieve substantial rates of growth, we must continue reinvesting in, acquiring or drilling for petroleum and natural gas. As we distribute the majority of our net cash flow to unitholders, we must finance a large portion of our acquisitions and development activity through continued access to equity and debt capital markets. One source of funding for our acquisition/expenditure program is through the issuance of equity. If we are not able to access the equity markets due to unfavorable market conditions for an extended period of time, this may adversely impact our growth rate. We minimize the financial market risk by maintaining a conservative financing structure. On October 31, 2006, the Canadian federal government announced proposals to introduce a new tax on distributions from existing publicly-traded income trusts. If enacted as currently proposed, Canetic would be subject to these new taxes beginning in 2011, provided it does not experience "undue expansion" in the intervening period as that term is defined in the recently released federal guidelines on "normal growth". The intent of these rules is to impose tax on income trusts in a similar manner and at similar rates as public corporations and the distributions be treated as dividends at the investor level. Income at the Trust level in excess of available tax shelter would be subject to the new tax at a statutory rate of 31.5 percent which would directly reduce cash available for distribution. These rules have not been enacted and are discussed in more detail in an earlier section of the MD&A. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The Trust's significant accounting policies are summarized in Note 1 to the Trust's audited consolidated financial statements for the years ended December 31, 2006 and 2005. Certain of these policies are recognized as critical because in applying these policies, management is required to make judgments, assumptions and estimates that have a significant impact on the financial results of the Trust. OIL AND GAS RESERVES Reserves estimates and revisions to those reserves, although not reported as part of the Trust's financial statements, can have a significant impact on net earnings as a result of their impact on depletion, depletion rates, asset retirement obligations, asset impairments and purchase price allocations. In adherence with National Instrument 51-101, 100 percent of the Trust's proved plus probable oil and gas reserves were evaluated and reported on by independent petroleum engineers GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. However, the process of estimating oil and gas reserves is complex and is subject to uncertainties and interpretations. Estimating reserves requires significant judgments based on available geological and reservoir data, past production and operating performance and forecasted economic and operating conditions. These estimates may change substantially as additional data from ongoing development, testing and production becomes available, and due to unforeseen changes in economic conditions which impact oil and gas prices and costs. FULL COST ACCOUNTING The Trust follows the full cost method of accounting for oil and natural gas activities. Using the full cost method of accounting, all costs of acquiring, exploring and developing oil and natural gas properties are capitalized, including unsuccessful drilling costs and administrative costs associated with acquisitions and development. In accordance with full cost accounting, a ceiling test is performed, on a quarterly basis, to test for asset impairment. An impairment loss is recorded if the sum of the undiscounted cash flows expected from the production of the proved reserves and the lower of cost and market of unproved properties does not exceed the carrying values of the oil and gas assets. An impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flow expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flow used in testing for impairment is based on the estimates of remaining proved and probable reserves, future commodity prices and future operating costs. Capitalized costs are depleted using the unit-of-production method based on estimated proved reserves of petroleum and natural gas before royalties as determined by independent petroleum engineers. Costs relating to unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves exist or if impairment occurs. Proved natural gas reserves and production are converted to equivalent volumes of crude petroleum based on the approximate relative energy content ratio of six thousand cubic feet of natural gas to one barrel of crude oil. ASSET RETIREMENT OBLIGATIONS Management calculates the asset retirement obligation based on estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to property, plant and equipment as part of the cost of the related asset and amortized over its useful life. BUSINESS COMBINATIONS Management makes various assumptions in determining the fair values of any acquired company's assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and natural gas properties. To determine the fair value of these properties we estimated oil and gas reserves and future prices of oil and natural gas. INCOME TAXES The Trust is not liable for income tax as it allocates substantially all of its taxable income to its unitholders. Future income taxes are calculated for the corporate subsidiaries using the liability method whereby tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between amounts reported in the financial statements and their respective tax base using substantively enacted income tax rates. The effect of a change in income tax rates in future tax liabilities and assets are recognized in income in the period in which the change occurs. The determination of income and other tax liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and assessment by taxing authorities after the lapse of considerable time. As a result, the actual income tax liability may differ from that recorded. RECENT ACCOUNTING PRONOUNCEMENTS FINANCIAL INSTRUMENTS Effective January 1, 2007, the Trust will apply the following new CICA Handbook sections: Section 1530-Comprehensive Income; Section 3251-Equity; Section 3855-Financial Instruments - Recognition and Measurement; and Section 3865-Hedges. The new accounting pronouncements are effective for the first quarter of 2007, and address the recognition and measurement of financial assets, financial liabilities and non-financial derivatives. The Trust has assessed the requirements under these sections, and has noted no current impact on the financial statements. Financial assets, financial liabilities and non-financial derivatives acquired in future periods will be evaluated under the framework set forth in the new pronouncements. BUSINESS RISKS The operations of Canetic are subject to underlying risks associated with the business of the Trust. For a detailed discussion of business risks, please refer to "Risk Factors" in the Trust's most recently filed Annual Information Form. Canetic Resources Trust Consolidated Balance Sheet (unaudited) As at December 31 ($000s) 2006 2005 ------------------------------------------------------------------------- ASSETS Current Assets Accounts receivable $ 261,498 $ 140,907 Prepaid expenses and deposits 34,647 11,630 ------------------------------------------------------------------------- 296,145 152,537 Property, plant and equipment, net (Note 4) 4,597,654 1,317,917 Goodwill (Note 2) 922,024 87,954 Deferred financing charges, net of amortization 8,996 689 Deferred costs - 12,000 Financial derivative asset (Note 12) 6,157 - ------------------------------------------------------------------------- Total assets $ 5,830,976 $ 1,571,097 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current Liabilities Accounts payable and accrued liabilities $ 260,206 $ 157,368 Income taxes payable (Note 3) 10,979 - Distributions payable 51,933 17,834 Convertible debentures (Note 6) 1,697 - Financial derivative liability (Note 12) 1,124 22,965 ------------------------------------------------------------------------- 325,939 198,167 ------------------------------------------------------------------------- Bank debt (Note 5) 1,289,678 309,146 Convertible debentures (Note 6) 258,959 16,289 Other long-term liabilities (Note 9) 7,272 - Financial derivative liability (Note 12) - 8,763 Future income taxes (Note 11) 250,339 202,110 Asset retirement obligations (Note 7) 191,874 68,235 ------------------------------------------------------------------------- 2,324,061 802,710 Non-controlling interest (Note 8) - 3,804 Commitments and guarantees (Note 14) UNITHOLDERS' EQUITY Capital (Note 8) 4,224,470 1,087,459 Convertible debentures (Note 6) 6,584 - Contributed surplus (Note 9) - 40,836 Deficit (Note 10) (724,139) (363,712) ------------------------------------------------------------------------- 3,506,915 764,583 ------------------------------------------------------------------------- Total liabilities and unitholders' equity $ 5,830,976 $ 1,571,097 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to consolidated financial statements. Approved on Behalf of the Board of Directors Jack C. Lee J. Paul Charron Chairman of the Board President and Chief Executive Officer Canetic Resources Trust Consolidated Statements of Earnings and Deficit (unaudited) Years ended December 31 Three months ended Year ended ($000s except per December 31 December 31 unit amounts) 2006 2005 2006 2005 ------------------------------------------------------------------------- REVENUE Petroleum and natural gas sales $ 347,701 $ 234,098 $ 1,407,754 $ 800,249 Royalty expense (63,609) (52,303) (258,260) (175,723) ------------------------------------------------------------------------- 284,092 181,795 1,149,494 624,526 ------------------------------------------------------------------------- EXPENSES Operating 70,981 34,671 252,142 129,646 Transportation 5,252 3,316 18,968 9,897 General and administrative 9,193 15,565 53,983 45,372 Interest on bank debt 19,612 3,922 53,809 13,752 Interest on convertible debentures 4,603 453 8,627 4,357 Depletion, depreciation and amortization 176,074 55,233 645,203 233,693 Accretion of asset retirement obligations 3,651 1,041 11,410 4,560 (Gain) loss on financial derivatives (Note 12) (19,978) (21,622) (86,906) 100,792 ------------------------------------------------------------------------- Earnings before taxes 14,704 89,217 192,258 82,457 Capital taxes 2,662 3,143 11,836 8,036 Current income tax 3,306 - 5,567 - Future income tax (recovery) expense (Note 11) 30,368 37,412 (48,246) 8,573 ------------------------------------------------------------------------- NET (LOSS) EARNINGS (21,632) 48,662 223,101 65,848 Deficit, beginning of period (546,987) (358,995) (363,712) (221,083) Distributions declared (155,520) (53,379) (583,528) (208,477) ------------------------------------------------------------------------- Deficit, end of year $ (724,139) $ (363,712) $ (724,139) $ (363,712) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net (loss) earnings per unit (Note 13) Basic $ (0.10) $ 0.53 $ 1.08 $ 0.74 Diluted $ (0.10) $ 0.52 $ 1.06 $ 0.73 Weighted average units outstanding (Note 13) Basic 225,192 91,489 206,081 89,331 Diluted 227,740 92,947 210,397 90,591 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to consolidated financial statements. Canetic Resources Trust Consolidated Statements of Cash Flows (unaudited) Years ended December 31 Three months ended Year ended ($000s except per December 31 December 31 unit amounts) 2006 2005 2006 2005 ----------------------------------------------- ------------------------- OPERATING ACTIVITIES Net earnings $ (21,632) $ 48,662 $ 223,101 $ 65,848 Adjustments for: Unit-based compensation (2,766) 11,448 14,049 27,166 Depletion, depreciation and amortization 176,074 55,233 645,203 233,693 Accretion 3,651 1,041 11,410 4,560 Unrealized (gain) loss on financial derivatives (15,612) (47,319) (95,371) 20,635 Future income tax (recovery) expense 30,368 37,412 (48,246) 8,573 Asset retirement costs incurred (6,314) (2,220) (16,877) (6,293) Changes in non-cash operating working capital 32,898 42,946 (50,778) (7,812) ------------------------------------------------------------------------- 196,667 147,203 682,491 346,370 ------------------------------------------------------------------------- FINANCING ACTIVITIES ------------------------------------------------------------------------- Proceeds from bank debt 66,662 (27,783) 546,409 25,301 Proceeds from issuance of units, net of issue costs - 2,357 437,001 9,788 Proceeds from issuance of convertible debentures - - 220,800 - Distributions to unitholders (154,094) (53,258) (538,703) (207,474) Changes in non-cash financing working capital - 902 - 1,231 ------------------------------------------------------------------------- (87,432) (77,782) 665,507 (171,154) ------------------------------------------------------------------------- 109,235 69,421 1,347,998 175,216 ------------------------------------------------------------------------- INVESTING ACTIVITIES Acquisition of petroleum and natural gas properties - (3,607) (56,285) (13,554) Disposition of petroleum and natural gas properties 2,132 - 17,168 4,610 Corporate acquisitions, net of cash - - (933,458) - Capital expenditures (111,367) (74,608) (375,423) (176,888) Changes in non-cash investing working capital - 8,794 (12,753) 10,616 ------------------------------------------------------------------------- (109,235) (69,421) (1,347,998) (175,216) ------------------------------------------------------------------------- Cash beginning and end of period $ - $ - $ - $ - ------------------------------------------------------------------------- The Trust paid the following cash amounts: Interest paid $ 18,994 $ 8,566 $ 60,875 $ 19,994 Capital taxes paid $ 19,606 $ 463 $ 34,494 $ 4,033 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to consolidated financial statements. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) Years Ended December 31, 2006 and 2005 (tabular amounts in $000s except for unit amounts) 1. SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION These consolidated financial statements include the accounts of Canetic Resources Trust and its direct and indirect wholly owned subsidiaries and partnerships (collectively, "Canetic" or the "Trust"). The consolidated financial statements have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles. A reconciliation between Canadian Generally Accounting Principles and the United States of America Generally Accepted Accounting Principles is disclosed in Note 15. The preparation of consolidated financial statements in conformity with Canadian Generally Accepted Accounting Principles requires management of the Trust to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimated. The consolidated financial statements have, in management's opinion, been properly prepared using careful judgment and within the framework of the following significant accounting principles. In particular the amounts recorded for depletion and depreciation of property, plant and equipment, the impairment test and asset retirement obligations are based on estimates of proven reserves, production rates, future crude oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and changes in such estimates may impact the financial statements in future periods. PETROLEUM AND NATURAL GAS PROPERTIES The Trust follows the full-cost method of accounting for petroleum and natural gas operations, whereby all costs related to the exploration and development of petroleum and natural gas reserves are capitalized. Such costs include land acquisition costs, costs of drilling both productive and non-productive wells, well equipment, flowline and plant costs, geological and geophysical expenses and overhead expenses directly related to exploration and development activities. Gains or losses on sales of properties are recognized only when crediting the proceeds to the recorded costs would result in a change of 20 percent or more in the depletion and depreciation rate. Capitalized costs are depleted using the unit-of-production method based on estimated proved reserves of petroleum and natural gas before royalties as determined by independent petroleum engineers. Costs relating to unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves exist or if impairment occurs. Proved natural gas reserves and production are converted to equivalent volumes of crude petroleum based on the approximate relative energy content ratio of six thousand cubic feet of natural gas to one barrel of crude oil. The Trust places a limit on the aggregate carrying value of the Trust's petroleum and natural gas properties. An impairment loss exists when the carrying amount of the Trust's petroleum and natural gas properties exceeds the estimated undiscounted future net cash flows associated with the Trust's proved reserves. If an impairment loss is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the Trust's proved and probable reserves are charged to earnings. Reserves are determined pursuant to National Instrument 51-101. GOODWILL The Trust recognizes goodwill on corporate acquisitions when the total purchase price exceeds the fair value of net identifiable assets and liabilities of the acquired entity. Goodwill is tested annually at year-end for impairment or as events occur that could result in impairment. Impairment is recognized based on the fair value of the Trust compared to the book value of the Trust. If the fair value of the Trust is less that the book value, impairment is measured by allocating the fair value to the identifiable assets and liabilities as if the Trust had been acquired in a business combination for its fair value. The excess of the fair value over the amounts assigned to the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value over this implied fair value of goodwill is the impairment amount. Impairment is charged to earnings in the period in which it occurs. Goodwill is stated at cost less impairment and is not amortized. HEDGING RELATIONSHIPS The Trust follows Accounting Guideline 13 - Hedging Relationships, which deals with the identification, designation, documentation and effectiveness of hedging relationships for the purpose of applying hedge accounting. Where hedge accounting does not apply, any changes in the fair value of the financial derivative contracts relating to a financial period can either reduce or increase net earnings and net earnings per trust unit for that period. The Trust enters into numerous financial instruments to manage commodity price and foreign exchange risk that do not qualify as hedges under Accounting Guideline 13. Therefore, the Trust has elected to not apply hedge accounting and to follow the fair value accounting method for all financial instruments. ASSET RETIREMENT OBLIGATIONS The Trust recognizes as a liability the estimated fair value of the future retirement obligations associated with PP&E. The fair value is capitalized and amortized over the same period as the underlying asset. The Trust estimates the liability based on the estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. This estimate is evaluated on a periodic basis and any adjustment to the estimate is prospectively applied. As time passes, the change in net present value of the future retirement obligation is expensed through accretion. Retirement obligations settled during the period reduce the future retirement liability. No gains or losses on retirement activities were realized, due to settlements approximating the estimates. JOINT VENTURES A portion of the Trust's development and production activities are conducted jointly with others. These financial statements reflect only the Trust's proportionate interest in such activities. REVENUE RECOGNITION Revenue associated with sales of crude oil, natural gas and NGLs is recognized when title passes to the purchaser, normally at the pipeline delivery point for natural gas and at the wellhead for crude oil. DEPRECIATION Office furniture and equipment is depreciated on a declining-balance method at annual rates of 10 percent to 33 percent. UNIT AWARD INCENTIVE PLAN The Trust has a Unit Award Incentive Plan for directors, officers, employees and consultants of the Trust. Under the terms of the plan, a holder may elect, subject to consent of the Trust, to receive cash upon vesting in lieu of the number of rights held. Compensation expense associated with rights granted under the plan is measured at the date of exercise or at the date of the financial statements for unexercised rights. Compensation expense on unexercised rights is determined on the rights as the excess of the market price over the exercise price of the rights at the end of each reporting period and is deferred and recognized in income over the vesting period of the rights. See Note 9 for a description of the plan. INCOME TAXES The Trust is a taxable entity under the Canadian Income Tax Act ("Act") and is taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income (if any) to the unitholders and meets the requirements of the Act applicable to the Trust, no provision for income tax has been made in the Trust. The Trust follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the Trust's corporate subsidiaries and their respective tax bases, using substantially enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in earnings in the period that the change occurs. CASH The Trust considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents primarily consist of funds on deposit under various terms or Banker's Acceptances utilized to fix the interest rate on bank debt. Cash and cash equivalents are stated at cost which approximates fair value. PER UNIT INFORMATION Basic earnings per unit are calculated using the weighted average number of units outstanding during the year adjusted for the impact of units to be issued on the conversion of exchangeable shares. Diluted earnings per unit are calculated using the treasury stock method to determine the dilutive effects of unit options and the "if converted" method is used to determine the dilution impact of the convertible debentures. The treasury method assumes that proceeds from the exercise of "in-the-money" unit options and exercise of the convertible debentures are used to re-purchase units at the prevailing market rate. 2. STARPOINT ARRANGEMENT Acclaim and StarPoint merged on January 5, 2006 pursuant to a Plan of Arrangement ("Arrangement"), which resulted in the creation of Canetic. Each Acclaim unitholder received 0.8333 of a Canetic trust unit for each trust unit they owned and each StarPoint unitholder received one Canetic trust unit for each trust unit they owned. Unitholders in both Acclaim and StarPoint also received common shares and warrants in a new publicly-listed junior exploration company, TriStar Oil & Gas Ltd. ("TriStar"), which was formed with assets from both Acclaim and StarPoint. Each Acclaim unitholder received 0.0833 of a TriStar common share for each trust unit they owned and each StarPoint unitholder received 0.1000 of a TriStar common share for each trust unit they owned. In addition, each Acclaim unitholder received 0.0175 of a TriStar warrant for each trust unit they owned and each StarPoint unitholder received 0.0210 of a TriStar warrant for each trust unit they owned. The merger was accounted for as an acquisition of StarPoint by Acclaim using the purchase method of accounting. ($000s) ------------------------------------------------------------------------- Current assets 124,803 Property, plant and equipment 2,511,746 Goodwill 834,070 Accounts payable and accrued liabilities (144,777) Distributions payable (22,662) Long-term debt (434,123) Financial derivative liability (57,785) Convertible debentures - liability (53,199) Convertible debentures - equity (8,691) Future income taxes (96,476) Asset retirement obligations (54,343) ------------------------------------------------------------------------- 2,598,563 ------------------------------------------------------------------------- Consideration was comprised of: Issuance of 106,242,000 units of Canetic 2,562,563 Transaction costs 36,000 ------------------------------------------------------------------------- 2,598,563 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 3. SAMSON ACQUISITION On August 31, 2006, Canetic completed the share acquisition of a private oil and gas company ("Samson") for total consideration of $955.1 million. The transaction was effective June 1, 2006. The transaction was financed with bank debt and a $690.0 million bought deal financing which was completed on August 24, 2006. Under the bought deal financing, Canetic issued 20,769,000 units at a price of $22.15 per unit and $230.0 million principal amount of convertible extendible unsecured subordinated debentures. This acquisition was accounted for using the purchase method of accounting as follows: ($000s) ------------------------------------------------------------------------- Cash 57,635 Current assets 76,803 Property, plant and equipment 942,864 Accounts payable and accrued liabilities (60,035) Income taxes payable (43,946) Asset retirement obligations (18,228) ------------------------------------------------------------------------- 955,093 ------------------------------------------------------------------------- Consideration was comprised of: Cash 951,314 Transaction costs 3,779 ------------------------------------------------------------------------- 955,093 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 4. PROPERTY, PLANT AND EQUIPMENT 2006 2005 ------------------------------------------------------------------------- Property, plant and equipment, at cost $ 5,879,523 $ 1,955,472 Accumulated depletion and depreciation 1,281,869 637,555 ------------------------------------------------------------------------- $ 4,597,654 $ 1,317,917 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Costs relating to unproved properties of $295 million (2005 - $42.5 million) were excluded from costs subject to depletion and depreciation. An impairment test calculation was performed on the Trust's property, plant and equipment at December 31, 2006 and 2005 in which the estimated undiscounted future net cash flows associated with the proved reserves exceeded the carrying amount of the Trust's property, plant and equipment. The following table outlines benchmark prices used in the impairment test: Year WTI Exchange AECO ($US/bbl) Rate ($CDN/mcf) ------------------------------------------------------------------------- 2007 63.87 0.87 7.46 2008 64.41 0.87 8.02 2009 60.21 0.87 7.74 2010 57.68 0.87 7.67 2011 - 2021 61.74 0.87 8.67 Thereafter (inflation %) 2.0% 0.0% 2.0% ------------------------------------------------------------------------- 5. LONG-TERM DEBT Canetic has an unsecured, covenant based, extendible revolving credit facility of $1.6 billion including a $50.0 million working capital facility with a syndicate of financial institutions. Canetic may draw under the credit facility by way of: a) Prime rate loans in Canadian dollars; b) U.S. base rate loans in U.S. dollars; c) Canadian and U.S. dollar Banker's Acceptances; d) London Inter-Bank Offered Rate ("LIBOR") loans in U.S. dollars; and e) Letters of Credit to be issued in Canadian or U.S. dollars. The credit facility is available on a revolving basis with a maturity date of May 31, 2009. On a annual basis, Canetic may request the maturity date be extended by one year. Prime rate and U.S. base rate loans bear interest at the lenders' prime rate. The rate charged on the other amounts drawn is based upon rates and fees outlined in the lending agreement. The effective interest rate on the credit facility for the year ended December 31, 2006 was 5.13 percent (2005 - 4.00 percent). 6. CONVERTIBLE DEBENTURES In connection with the acquisition of Samson (Note 3), Canetic issued $230 million, 6.5% extendible unsecured, subordinated debentures, convertible into units at the option of the holder any time prior to maturity at a conversion price of $26.55. The debentures have a face value of $1,000 per debenture, a coupon of 6.5% and a maturity date of December 31, 2011. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after December 31, 2009 and at a redemption price of $1,025 per debenture after December 31, 2010 before the maturity date. The value of the conversion feature was determined to be $2.5 million; therefore, $227.5 million of the convertible debentures has been disclosed as a liability and $2.5 million has been allocated to unitholders' equity. There were no conversions of these debentures in 2006. The StarPoint 9.4% extendible, unsecured, subordinated debentures are convertible into trust units at the option of the holder at any time prior to maturity at a conversion price of $16.02. The debentures have a face value of $1,000 per debenture, a coupon of 9.4% and a maturity date of July 31, 2008. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after July 31, 2006 and at a redemption price of $1,025 per debenture after July 31, 2007 before maturity. During 2006, $3.6 million of the 9.4% debentures were converted which resulted in the issuance of 225,000 trust units. The StarPoint 6.5% extendible, unsecured, subordinated debentures are convertible into trust units at the option of the holder at any time prior to maturity at a conversion price of $18.96. The debentures have a face value of $1,000 per debenture, a coupon of 6.5% and a maturity date of July 31, 2010. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after July 31, 2008 and at a redemption price of $1,025 per debenture after July 31, 2009. During 2006, $26.1 million of 6.5% debentures were converted which resulted in the issuance of 1,373,000 trust units. On June 15, 2004, Acclaim issued $75.0 million, 8% convertible, extendible, unsecured, subordinated debentures. The debentures are convertible into units at the option of the holder at any time prior to maturity at a conversion price of $15.56. The debentures have a face value of $1,000 per debenture, a coupon of 8.0% and a maturity date of August 31, 2009. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after August 31, 2007 and at a redemption price of $1,025 per debenture after August 31, 2008 before the maturity date. During 2006, $5.5 million of 8% debentures were converted resulting in the issuance of 354,000 trust units. In December 2002, Acclaim issued $45.0 million, 11% convertible, extendible, unsecured, subordinated debentures. The debentures are convertible into units at the option of the holder at any time prior to maturity at a conversion price of $11.24 per unit. The debentures have a face value of $1,000 per debenture, a coupon of 11% and a maturity date of December 31, 2007. The Trust may redeem the debentures in whole or in part at a redemption price of $1,025 per debenture before the final maturity date. During 2006, $1.0 million of 11% debentures were converted which resulted in the issuance of 90,000 trust units. In connection with the Arrangement, the fair value of the conversion feature of the 6.5% and 9.4% convertible debentures of $8.7 million was classified as equity. The fair value of the debentures upon acquisition and the allocation between liabilities and equity was determined based on the market price of the convertible debentures and an option pricing model. During 2006, $4.6 million was reclassified to capital upon conversion of the 6.5% and 9.4% debentures. The following table reconciles the number of units to be issued on conversion of the remaining balance of the convertible debentures. ($000s) 9.4% 6.5% 8% ------------------------------------------------------------------------- (CNE.DB.A) (CNE.DB.B) (CNE.DB.C) Balance, December 31, 2004 $ - $ - $ 72,901 Converted to units - (59,330) ------------------------------------------------------------------------- Balance, December 31, 2005 - - 13,571 Acquisition of StarPoint 9,255 43,944 - Acquisition of Samson - - - Converted to units (3,633) (26,123) (5,525) ------------------------------------------------------------------------- Balance, December 31, 2006 $ 5,622 $ 17,821 $ 8,046 ------------------------------------------------------------------------- ($000s) 11% 6.5% ------------------------------------------------------------------------- (CNE.DB.D) (CNE.DB.E) Total Balance, December 31, 2004 $ 6,562 $ - $ 79,463 Converted to units (3,844) (63,174) ------------------------------------------------------------------------- Balance, December 31, 2005 2,718 - 16,289 Acquisition of StarPoint - - 53,199 Acquisition of Samson - 227,470 227,470 Converted to units (1,021) - (36,302) ------------------------------------------------------------------------- Balance, December 31, 2006 $ 1,697 $ 227,470 $ 260,656 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (000s) 9.4% 6.5% 8% ------------------------------------------------------------------------- Units Issuable Upon Conversion (CNE.DB.A) (CNE.DB.B) (CNE.DB.C) Balance, December 31, 2004 - - 5,401 Converted to units - - (4,395) ------------------------------------------------------------------------- Balance, December 31, 2005 - - 1,006 Adjustment to conversion ratio - - (135) Acquisition of StarPoint 576 2,313 - Acquisition of Samson - - - Converted to units (225) (1,373) (354) ------------------------------------------------------------------------- Balance, December 31, 2006 351 940 517 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (000s) 11% 6.5% ------------------------------------------------------------------------- Units Issuable Upon Conversion (CNE.DB.D) (CNE.DB.E) Total Balance, December 31, 2004 672 - 6,073 Converted to units (394) - (4,789) ------------------------------------------------------------------------- Balance, December 31, 2005 278 - 1,284 Adjustment to conversion ratio (36) - (171) Acquisition of StarPoint - - 2,889 Acquisition of Samson - 8,663 8,663 Converted to units (90) - (2,042) ------------------------------------------------------------------------- Balance, December 31, 2006 152 8,663 10,623 ------------------------------------------------------------------------- 7. ASSET RETIREMENT OBLIGATIONS Total future asset retirement obligations were estimated by management based on the Trust's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Trust has estimated the net present value of its total asset retirement obligations to be $191.9 million (December 31, 2005 - $68.2 million) based on a total future liability of $603.3 million (December 31, 2005 - $216.5 million). The costs are expected to be incurred over an average period of 15 years. The estimated liability has been computed using an inflation rate of 2.0 percent and discounted using a credit adjusted risk free rate of 8 percent. The following table reconciles Canetic's asset retirement obligations: Asset Retirement Obligations 2006 2005 ------------------------------------------------------------------------- Balance, beginning of year $ 68,235 $ 58,649 Acquisition of StarPoint (Note 2) 54,343 - Acquisition of Samson (Note 3) 18,228 - Additions 3,117 1,551 Change in estimates 53,416 9,768 Settlement of liabilities during year (16,875) (6,293) Accretion expense 11,410 4,560 ------------------------------------------------------------------------- Balance, end of year $ 191,874 $ 68,235 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 8. CAPITAL Authorized capital of the Trust is comprised of an unlimited number of units and an unlimited number of special voting units. There are no special voting units outstanding. Each unitholder can request redemption of trust units at a price calculated as the lesser of 90 percent of the market price during the 10 days after the date units are tendered and the closing market price on the date units are tendered. Cash payments for units tendered are limited to $100,000 per month. The Trust may issue notes for redemption in excess of cash payments. a) Trust Units 2006 2005 ------------------------------------------------------------------------- Units Units (000s) Amount (000s) Amount ------------------------------------------------------------------------- Balance, beginning of year 91,583 $ 1,087,459 86,313 $ 1,003,294 Issued for cash: Acquisition of Samson, net of costs (Note 3) 20,769 437,001 - - Pursuant to equity offering, net of costs - - - (350) Employee Unit Savings Plan 274 6,184 89 1,646 Distribution reinvestment plan 2,470 44,825 456 8,492 Issued pursuant to Arrangement 106,242 2,562,563 - - Properties contributed to TriStar (Note 2) - (5,000) - - Conversion of debentures 2,042 36,302 3,990 63,174 Conversion of debentures - equity portion - 4,636 - - Conversion of exchangeable shares 358 3,804 357 4,033 Unit award incentive plan 2,058 46,696 378 7,170 ------------------------------------------------------------------------- Balance, end of year 225,796 $ 4,224,470 91,583 $ 1,087,459 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Units Amount (000s) ($000s) (Restated b) Exchangeable Shares - Note 1) ------------------------------------------------------------------------- Balance, December 31, 2004 673 7,837 Shares exchanged (357) (4,033) Adjustment to exchange ratio for distributions 42 - ------------------------------------------------------------------------- Balance, December 31, 2005 358 3,804 Shares exchanged (358) (3,804) ------------------------------------------------------------------------- Balance, December 31, 2006 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Pursuant to the Arrangement, all exchangeable shares were exchanged into units. DISTRIBUTION REINVESTMENT PLAN Canadian unitholders may elect to reinvest their cash distributions into additional units of the Trust. During 2006, 2,470,000 units (2005 - 456,000 units) were issued with $44.8 million (2005 - $8.5 million) being credited to capital. 9. UNIT-BASED COMPENSATION PLAN On January 5, 2006, the Board of Directors of Canetic approved a Restricted Trust Unit ("RTU") and Performance Trust Unit ("PTU") incentive plan (the "Plan"). Under the terms of the Plan, both RTU's and PTU's may be granted to directors, officers, employees of, and consultants and service providers to the Trust or any of its subsidiaries. The number of trust units issued pursuant to the Plan are adjusted for the value of the distributions from the time of the granting to the time when the trust units are issued. PTU's are also adjusted based on the Trust's performance relative to the performance of a group of comparable publicly traded oil and gas royalty trusts and other performance criteria determined by the Board of Directors. The following table summarizes the activity for the RTU's and PTU's. Number Number of RTU's of PTU's (000s) (000s) ------------------------------------------------------------------------- Balance, December 31, 2004 909 312 Granted 375 231 Exercised (378) - Forfeited (102) (50) ------------------------------------------------------------------------- Balance, December 31, 2005 804 493 Granted 1,035 2,021 Exercised (804) (927) Forfeited (119) (201) ------------------------------------------------------------------------- Balance, December 31, 2006 916 1,386 ------------------------------------------------------------------------- ------------------------------------------------------------------------- All RTU's and PTU's vested on January 5, 2006 pursuant to the Arrangement. At that time, 2,152,000 units were issued to holders of RTU's and PTU's. Compensation expense in 2005 reflects the full vesting of the RTU's and PTU's that occurred on January 5, 2006. The intrinsic value of vested rights of $40.8 million was included in Contributed Surplus at December 31, 2005. The Trust recorded unit-based compensation expense of $14.3 million and $2.5 million to general and administrative and operating expenses, respectively, and capitalized $3.4 million to property, plant and equipment for the year-ended December 31, 2006 to reflect the change in fair value (based on the period end price of the units) of the RTU's and PTU's ($23.4 million, $4.2 million and $11.0 million for the year-ended December 31, 2005). Other long-term liabilities consist of the long-term portion of the Trust's estimated liability for the Plan as at December 31, 2006. The amount of $7.3 million is payable in 2008 and 2009. During the year Canetic paid $2.8 million in taxes related to the payment of RTU's and PTU's (2005 - $0.8 million). EMPLOYEE UNIT SAVINGS PLAN The Trust has a savings plan whereby the employees can place up to 5 percent of their annual base salary and the Trust will match up to 10 percent of their annual base salary. All amounts are then invested in units of the Trust by way of market purchases or issuances from Treasury. During 2006, 274,000 (2005 - 89,000) units were issued from Treasury under the Employee Unit Savings Plan with $6.2 million (2005 - $1.6 million) being credited to capital (Note 8). The Trust matching portion is included in general and administrative expenses as a compensation expense to the employee. 10. DEFICIT Deficit consists of accumulated earnings and accumulated distributions for the Trust since inception as follows: ($000s) 2006 2005 ------------------------------------------------------------------------- Accumulated earnings $ 384,970 $ 161,869 Accumulated distributions (1,109,109) (525,581) ------------------------------------------------------------------------- $ (724,139) $ (363,712) ------------------------------------------------------------------------- ------------------------------------------------------------------------- The table below shows the cumulative distributions to unitholders: Distributions on issued units(1) $/Unit Amount ------------------------------------------------------------------------- Year ended December 31, 2002 0.585 19,025 ------------------------------------------------------------------------- Year ended December 31, 2003 2.340 121,338 ------------------------------------------------------------------------- Year ended December 31, 2004 2.340 176,741 ------------------------------------------------------------------------- Year ended December 31, 2005 2.340 208,477 ------------------------------------------------------------------------- Three months ended March 31, 2006 0.690 138,634 Three months ended June 30, 2006 0.690 139,567 Three months ended September 30, 2006 0.690 149,918 Three months ended December 31, 2006 0.690 155,409 ------------------------------------------------------------------------- Year ended December 31, 2006 2.760 583,528 ------------------------------------------------------------------------- Accumulated distributions $ 1,109,109 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) All disclosures of units and per unit amounts of Acclaim up to the merger on January 5, 2006 have been restated using the exchange ratio of 0.8333 of a Canetic unit for each Acclaim unit. 11. INCOME TAXES THE TRUST AND OTHER NON-CORPORATE ENTITIES The Trust is an inter vivos trust for income tax purposes. Accordingly, the Trust is taxable on any taxable income that is not allocated to the unitholders. The Trust intends to allocate all taxable income to the unitholders. Should the Trust incur any income taxes, the funds available for distribution will be reduced accordingly. The Trust had no taxable income in 2006 or 2005. The Trust also owns interests directly or indirectly in various non-corporate entities which are considered flow-through entities for tax purposes. These entities are designed to allocate 100 percent of their taxable income to the Trust and therefore do not recognize future income taxes on differences between the carrying value and the tax value of their net assets. The Trust and other non-corporate entities had the following tax pools: 2006 2005 ------------------------------------------------------------------------- Canadian oil and gas property expense $ 383,570 $ 8,460 Undepreciated capital cost 36,537 69,915 Canadian development expense 6,090 5,961 Canadian exploration expense 2,562 - Share issue costs - 10,868 ------------------------------------------------------------------------- $ 428,759 $ 95,204 ------------------------------------------------------------------------- ------------------------------------------------------------------------- PROPOSED TAX ON INCOME TRUSTS On October 31, 2006, the Canadian Federal Government proposed a new tax on certain distributions of publicly traded income and royalty trusts. The intent of these proposals is to ultimately tax income earned in the trust structure on an equal basis as income earned in a corporation. If enacted, these provisions will be directly applicable to Canetic beginning in 2011 at a statutory rate of 31.5 percent. The new tax will not apply until 2011 provided Canetic does not exceed the Department of Finance's published guidelines on normal growth and expansion. It is expected that Canetic can issue up to $4.5 billion of new equity before 2011 without exceeding these guidelines. The proposed changes are not substantively enacted at the present time. Draft legislation was released on December 21, 2006 and circulated for comment. We are unable to predict the timing of enactment or whether the final legislation will implement the proposals as they currently exist. No amounts in respect of these proposals are reflected in the future income tax accounts. If enacted, the Fund would be treated as a taxable entity and would recognize future income tax assets and liabilities at substantively enacted tax rates based on the differences between the accounting and tax basis of its assets and liabilities. CORPORATE SUBSIDIARIES The Trust has recorded a net future income tax liability associated with the temporary differences of the corporate subsidiaries as at December 31, 2006 and 2005 relating to the following: 2006 2005 ------------------------------------------------------------------------- Capital assets in excess of tax value $ 324,135 $ 233,103 Asset retirement obligations (48,173) (18,703) Financial derivatives 1,912 (10,976) Finance expense charged to unitholders' equity - (1,314) Tax losses carried forward (81,037) - Deferred partnership income 53,502 - ------------------------------------------------------------------------- $ 250,339 $ 202,110 ------------------------------------------------------------------------- ------------------------------------------------------------------------- At December 31, 2006, the corporate subsidiaries had the following tax pools: 2006 2005 ------------------------------------------------------------------------- Canadian oil and gas property expense $ 227,939 $ 181,042 Undepreciated capital cost 468,695 123,218 Canadian development expense 279,573 103,711 Canadian exploration expense 404 8,414 Non-capital losses 276,270 - Share issue costs 48 3,797 ------------------------------------------------------------------------- $ 1,252,929 $ 420,182 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Non-capital losses may be carried forward and are fully deductible against taxable income in future years. They are subject to expiry after seven, ten or twenty years depending upon the taxation year in which the losses arose. At December 31, 2006 the Trust had $276 million of non-capital loss available for carry-forward. $56 million of these losses will expire if unused at various times between 2007 and 2015. $220 million of these losses are scheduled to expire in 2026. Income tax expense varies from amounts that would be computed by applying Canadian federal and provincial income tax rates as follows: 2006 2005 ------------------------------------------------------------------------- Net Earnings before taxes $ 192,258 $ 82,457 Statutory income tax rate 35.25% 38.12% ------------------------------------------------------------------------- Expected income tax expense 67,771 31,433 Add (deduct) the tax effect of: Non-deductible crown charges 25,529 15,454 Non-deductible compensation expense 4,952 10,356 Net income attributed to the Trust (67,642) (31,693) Resource allowance (28,781) (13,720) Change in tax rates (32,118) (3,257) Prior period adjustments (9,690) - Other (2,700) - ------------------------------------------------------------------------- (42,679) 8,573 ------------------------------------------------------------------------- Future income tax (recovery) expense (48,246) 8,573 Current income tax 5,567 - ------------------------------------------------------------------------- Total income tax (recovery) expense $ (42,679) $ 8,573 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 12. FINANCIAL INSTRUMENTS The Trust's financial instruments recognized on the consolidated balance sheets include accounts receivable, current liabilities and bank debt. The fair values of financial instruments other than bank debt approximates their carrying amounts due to the short-term nature of these instruments. The carrying value of bank debt approximates its fair value due to floating interest terms. The Trust is exposed to the commodity price fluctuations of crude oil and natural gas and to fluctuations in the Canada/US dollar exchange rate. The Trust manages this risk by entering into various derivative financial instruments. The Trust is exposed to credit risk due to the potential non-performance of counterparties to the above financial instruments. The Trust mitigates this risk by dealing only with larger, well-established commodity marketing companies and with major national chartered banks.. The Trust is exposed to interest rate risks as a result of its floating rate bank debt. The Trust has entered into the following financial contracts and fixed price physical contracts for 2006 and future years: ------------------------------------------------------------------------- Future Commodity Contracts ------------------------------------------------------------------------- Daily Quantity Contract Price Term ------------------------------------------------------------------------- Natural Gas - Collars (AECO) ------------------------------------------------------------------------- 10,000 Gj/d Cdn $8.00 - $14.50 November 1, 2006 - March 31, 2007 5,000 Gj/d Cdn $8.00 - $15.60 November 1, 2006 - March 31, 2007 10,000 Gj/d Cdn $9.00 - $15.00 November 1, 2006 - March 31, 2007 20,000 Gj/d Cdn $7.00 - $11.10 November 1, 2006 - March 31, 2007 10,000 Gj/d Cdn $8.00 - $12.08 November 1, 2006 - March 31, 2007 10,000 Gj/d Cdn $7.50 - $12.05 November 1, 2006 - March 31, 2007 10,000 Gj/d Cdn $8.00 - $12.75 November 1, 2006 - March 31, 2007 10,000 Gj/d Cdn $7.50 - $14.00 January 1, 2007 - March 31, 2007 10,000 Gj/d Cdn $7.50 - $14.20 January 1, 2007 - March 31, 2007 5,000 Gj/d Cdn $7.00 - $12.45 January 1, 2007 - March 31, 2007 5,000 Gj/d Cdn $7.35 - $11.00 April 1, 2007 - October 31, 2007 5,000 Gj/d Cdn $7.50 - $11.00 April 1, 2007 - October 31, 2007 5,000 Gj/d Cdn $7.50 - $11.40 April 1, 2007 - October 31, 2007 5,000 Gj/d Cdn $7.50 - $11.45 April 1, 2007 - October 31, 2007 10,000 Gj/d Cdn $7.00 - $9.04 April 1, 2007 - October 31, 2007 10,000 Gj/d Cdn $7.00 - $9.00 April 1, 2007 - October 31, 2007 10,000 Gj/d Cdn $7.00 - $9.50 April 1, 2007 - October 31, 2007 20,000 Gj/d Cdn $6.00 - $9.00 April 1, 2007 - October 31, 2007 10,000 Gj/d Cdn $6.50 - $9.25 April 1, 2007 - October 31, 2007 20,000 Gj/d Cdn $7.00 - $11.00 November 1, 2007 - March 31, 2008 10,000 Gj/d Cdn $7.00 - $10.65 November 1, 2007 - March 31, 2008 10,000 Gj/d Cdn $7.00 - $10.70 November 1, 2007 - March 31, 2008 5,000 Gj/d Cdn $7.00 - $11.10 November 1, 2007 - March 31, 2008 5,000 Gj/d Cdn $7.00 - $11.15 November 1, 2007 - March 31, 2008 20,000 Gj/d Cdn $7.00 - $11.30 November 1, 2007 - March 31, 2008 20,000 Gj/d Cdn $7.00 - $12.00 November 1, 2007 - March 31, 2008 ------------------------------------------------------------------------- Natural Gas - Fixed Price Contracts (AECO) ------------------------------------------------------------------------- 5,000 Gj/d Cdn $8.47 January 1, 2007 - December 31, 2007 20,000 Gj/d Cdn $7.00 April 1, 2007 - October 31, 2007 10,000 Gj/d Cdn $7.14 April 1, 2007 - October 31, 2007 10,000 Gj/d Cdn $7.265 April 1, 2007 - October 31, 2007 5,000 Gj/d Cdn $7.95 April 1, 2007 - October 31, 2007 ------------------------------------------------------------------------- Crude Oil - Collars (WTI) ------------------------------------------------------------------------- 1,000 bbl/d US $50.00 - $77.00 January 1, 2007 - December 31, 2007 1,000 bbl/d US $53.00 - $77.00 January 1, 2007 - December 31, 2007 2,000 bbl/d US $60.00 - $77.00 January 1, 2007 - December 31, 2007 1,000 bbl/d US $60.00 - $80.05 January 1, 2007 - December 31, 2007 1,000 bbl/d US $65.00 - $96.50 January 1, 2007 - December 31, 2007 1,000 bbl/d US $60.00 - $85.55 January 1, 2008 - December 31, 2008 1,000 bbl/d US $65.00 - $79.25 January 1, 2008 - December 31, 2008 1,000 bbl/d US $65.00 - $79.70 January 1, 2008 - December 31, 2008 1,000 bbl/d US $65.00 - $81.50 January 1, 2008 - December 31, 2008 1,000 bbl/d US $60.00 - $90.15 January 1, 2008 - December 31, 2008 ------------------------------------------------------------------------- Crude Oil - Fixed Price Contracts (WTI) ------------------------------------------------------------------------- 3,500 bbl/d Cdn $70.70 January 1, 2007 - December 31, 2007 4,500 bbl/d Cdn $64.58 January 1, 2007 - December 31, 2007 500 bbl/d Cdn $72.20 January 1, 2008 - June 30, 2008 1,000 bbl/d US $48.12 January 1, 2006 - December 31, 2007 500 bbl/d US $48.08 January 1, 2006 - December 31, 2007 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The estimated fair value of financial derivative instruments is based on quoted market prices. 2006 2005 ------------------------------------------------------------------------- Realized loss on financial derivatives $ 8,465 $ 80,157 Unrealized (gain) loss on financial derivatives (95,371) 20,635 ------------------------------------------------------------------------- (Gain) loss on financial derivatives $ (86,906) $ 100,792 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 13. NET EARNINGS PER UNIT Net earnings per unit has been calculated based on the following: 2006 2005 ------------------------------------------------------------------------- Weighted average units outstanding 206,081 88,720 Units issuable on conversion of exchangeable shares - 611 ------------------------------------------------------------------------- Basic weighted average units and exchangeable shares outstanding 206,081 89,331 Dilutive impact of convertible debentures(1) 1,968 - Dilutive impact of RTU's and PTU's 2,348 1,260 ------------------------------------------------------------------------- Diluted weighted average units outstanding 210,397 90,591 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Diluted trust units include trust units issuable for the convertible debentures (CNE.DB.B, CNE.DB.C and CNE.DB.D). 14. COMMITMENTS AND GUARANTEES In addition to financial derivative commitments, the Trust has the following commitments: ------------------------------------------------------------------------- ($000s) Total 2007 2008 2009 2010 2011 Thereafter ------------------------------------------------------------------------- Credit facility 1,289,678 - - - - - 1,289,678 Convertible debentures 260,656 1,697 5,622 8,046 17,821 227,740 - Office lease 24,659 6,415 6,295 6,295 3,231 2,423 - Pipeline contract 6,116 636 802 814 877 823 2,164 ------------------------------------------------------------------------- Total 1,581,109 8,748 12,719 15,155 21,929 230,716 1,291,842 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net earnings as reported for Canadian GAAP $ - $ 65,848 Adjustments: Depletion, depreciation and amortization (Note a) 12,353 Unrealized loss on financial derivatives (Note b) 2,818 Effect of applicable income taxes on the above adjustments (5,783) ------------------------------------------------------------------------- Net earnings per unit Basic $ 0.70 Diluted $ 0.69 Weighted average number of trust units outstanding Basic 107,202 Diluted 108,714 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Canadian Increase U.S. GAAP (Decrease) GAAP ------------------------------------------------------------------------- December 31, 2006 Property, plant and equipment (Note a) Future income taxes Non-controlling interest (Note c) Temporary equity (Note c) Capital (Note c) Contributed surplus (Note c) Accumulated earnings (deficit) Accumulated distributions (Note c) ------------------------------------------------------------------------- December 31, 2005 Property, plant and equipment (Note a) $ 1,317,917 (45,902) $ 1,272,015 Future income taxes 202,110 (15,803) 186,307 Non-controlling interest (Note c) 3,804 (3,804) - Temporary equity (Note c) - 2,090,829 2,090,829 Capital (Note c) 1,087,459 (1,087,459) - Contributed surplus (Note c) 40,836 (40,836) - Accumulated earnings (deficit) 161,869 (1,514,410) (1,352,541) Accumulated distributions (Note c) $ (525,581) $525,581.00 $ - ------------------------------------------------------------------------- -------------------------------------------------------------------------

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For further information: please see Canetic's website at
www.canetictrust.com or contact Canetic investor relations by email at:
Info@canetictrust.com or toll free telephone at 1-877-539-6300

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CANETIC RESOURCES TRUST

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