Exhibit
4.8


To the Board of Directors of Canetic
Resources Trust:


We have audited the consolidated financial
statements of Canetic Resources Trust as at December 31, 2006 and 2005 and
for the years then ended and have issued our reports thereon dated March 21,
2007 (which audit report expresses an unqualified opinion and includes
explanatory paragraphs relating to our consideration of internal control over
financial reporting and the issuance of separate financial statements prepared
solely under Canadian generally accepted accounting principles and includes a
separate report titled Comments by Independent Registered Chartered Accountants
on Canada-United States of America Reporting Differences pertaining to changes
in accounting principles).  Such
financial statements and our report thereon dated March 21, 2007 are included
in the Company’s Annual Report on Form 40-F for the year ended December
31, 2006. We have also audited the following Differences between Canadian and
United States Generally Accepted Accounting Principles of Canetic Resources
Trust as at December 31, 2006 and 2005 and for the years then ended which
are included herein and were prepared to comply with the requirements of
Item 18 of Form 20-F. This supplemental disclosure is the
responsibility of the Company’s management. Our responsibility is to express an
opinion based on our audits. In our opinion, the Differences between Canadian
and United States Generally Accepted Accounting Principles as at
December 31, 2006 and 2005 and for the years then ended, when considered
in relation to the 2006 and 2005 basic financial statements taken as a whole,
presents fairly, in all material respects, the information set forth therein.


/s/ Deloitte & Touche LLP


Independent Registered Chartered Accountants

Calgary, Alberta, Canada


August 3, 2007











DIFFERENCES BETWEEN
CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES


The following information
should be read in conjunction with Canetic (“the Company”) audited annual
consolidated financial statements as at and for the years ended
December 31, 2006 and 2005. The Trust’s consolidated financial statements
have been prepared in accordance with Canadian generally accepted accounting
principles (“Canadian GAAP”).  These
principles, as they pertain to the Trust’s consolidated financial statements
differ from generally accepted accounting principles in the United States of
America (“U.S. GAAP”) as follows:


The application of U.S.
GAAP would have the following effects on net earnings as reported:


 


	
   

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Net earnings as
  reported for Canadian GAAP

  	
   

  	
  $ 223,101

  	
   

  	
  $    65,848

  	
   

  
	
  Adjustments:

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Depletion,
  depreciation and amortization (Note a)

  	
   

  	
  (732,379

  	
  )

  	
  12,353

  	
   

  
	
  Unit-based
  compensation (Note f)

  	
   

  	
  (2,021

  	
  )

  	
  —

  	
   

  
	
  Non-cash
  interest on debentures (Note e)

  	
   

  	
  2,070

  	
   

  	
   

  	
   

  
	
  Unrealized loss
  on financial derivatives (Note b)

  	
   

  	
  —

  	
   

  	
  2,818

  	
   

  
	
  Effect of
  applicable income taxes on the above adjustments

  	
   

  	
  205,190

  	
   

  	
  (5,783

  	
  )

  
	
  Net earnings (loss) and
  comprehensive income

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
   - U.S. GAAP (Note d)

  	
   

  	
  $ (304,039

  	
  )

  	
  $    75,236

  	
   

  
	
  Net earnings (loss) per
  unit

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Basic

  	
   

  	
  $      (1.48

  	
  )

  	
  $        0.84

  	
   

  
	
  Diluted

  	
   

  	
  $      (1.48

  	
  )

  	
  $        0.83

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Weighted average number
  of trust units outstanding

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Basic

  	
   

  	
  206,081

  	
   

  	
  89,331

  	
   

  
	
  Diluted

  	
   

  	
  206,081

  	
   

  	
  90,591

  	
   

  



 


The application of U.S.
GAAP would have the following effects on the balance sheets as reported:











 


	
   

  	
   

  	
  Canadian

  	
   

  	
  Increase

  	
   

  	
  U.S.

  	
   

  
	
   

  	
   

  	
  GAAP

  	
   

  	
  (Decrease)

  	
   

  	
  GAAP

  	
   

  
	
  December
  31, 2006

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Assets:

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Property, plant and equipment (Note a)

  	
   

  	
  $  4,597,654

  	
   

  	
  $    (777,534

  	
  )

  	
  $ 3,820,120

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Liabilities:

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Accounts payable and accrued liabilities (Note f)

  	
   

  	
  260,206

  	
   

  	
  2,768

  	
   

  	
  262,974

  	
   

  
	
  Convertible debentures (Note e)

  	
   

  	
  260,656

  	
   

  	
  4,514

  	
   

  	
  265,170

  	
   

  
	
  Future income taxes

  	
   

  	
  250,339

  	
   

  	
  (225,702

  	
  )

  	
  24,637

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Temporary equity
  (Note c)

  	
   

  	
  —

  	
   

  	
  3,103,011

  	
   

  	
  3,103,011

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Unitholders’
  equity:

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Capital (Note c)

  	
   

  	
  4,224,470

  	
   

  	
  (4,224,470

  	
  )

  	
  —

  	
   

  
	
  Convertible debentures (Note e)

  	
   

  	
  6,584

  	
   

  	
  (6,584

  	
  )

  	
  —

  	
   

  
	
  Deficit (Note c)

  	
   

  	
  (724,139

  	
  )

  	
  568,929

  	
   

  	
  (155,210

  	
  )

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  December
  31, 2005

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Assets:

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Property, plant and equipment (Note a)

  	
   

  	
  $  1,317,917

  	
   

  	
  (45,902

  	
  )

  	
  $ 1,272,015

  	
   

  
	
  Liabilities:

  	
   

  	
   

  	
   

  	
   

  	
   

  	
  —

  	
   

  
	
  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

  	
   

  
	
  Unitholders’
  equity:

  	
   

  	
   

  	
   

  	
   

  	
   

  	
  —

  	
   

  
	
  Capital (Note c)

  	
   

  	
  1,087,459

  	
   

  	
  (1,087,459

  	
  )

  	
   

  	
   

  
	
  Contributed surplus (Note c)

  	
   

  	
  40,836

  	
   

  	
  (40,836

  	
  )

  	
  —

  	
   

  
	
  Deficit (Note c)

  	
   

  	
  $    (363,712

  	
  )

  	
  $    (988,829

  	
  )

  	
  $ (1,352,541

  	
  )

  



 











a)              Property, plant and
equipment and depletion, depreciation and amortization:


Under U.S. GAAP, the book value of petroleum and
natural gas properties, net of deferred income taxes, is limited to the present
value of after tax future net cash flows from proven reserves, discounted at 10
percent (based on prices and costs at the balance sheet date), plus the lower
of cost and fair value of unproven properties.


Under Canadian GAAP, an impairment loss arises when
the book value of the petroleum and natural gas properties exceeds the
undiscounted future cash flow from proved reserves calculated using forecast
prices and costs.  If an impairment loss
is determined to exist, the impairment is measured as the amount by which the
net book value of the petroleum and natural gas properties exceeds the future
discounted cash flow from proved plus probable reserves at forecast prices and
costs.


For
the year ended December 31, 2006, depletion, depreciation and amortization
calculated under U.S. GAAP was $732.4 million ($520.0 million net of tax)
higher than depletion, depreciation and amortization calculated under Canadian
GAAP This amount was comprised of a ceiling test impairment totaling $739.1
million ($524.7 million net of tax) reduced by depletion, depreciation and
amortization totaling $6.7 million ($4.8 million net of tax) relating to the
reduction of depletable costs.  For the
year ended December 31, 2005, depletion, depreciation and amortization
calculated under U.S. GAAP was $12.4 million ($7.6 million net of tax) lower
than depletion, depreciation and amortization calculated under Canadian GAAP
and there was no ceiling test impairment under U.S. GAAP in 2005.


b)              Financial
derivatives and unrealized loss on financial derivatives:


Effective
January 1, 2004, the Trust prospectively adopted CICA Accounting Guideline — 13
“Hedging Relationships” (“AcG-13”) and Emerging Issues Committee Abstract 128 “Accounting
for Trading, Speculative or Non-hedging Derivative Financial Instruments”. This
effectively eliminates U.S. GAAP differences relating to financial instruments
that do not qualify for hedge accounting for future periods. The Trust enters
into numerous financial instruments to manage commodity price and foreign
exchange risk that do not qualify as hedges under the new accounting guideline.
The Trust has elected to not apply hedge accounting to any of its financial
instruments for both Canadian and U.S. GAAP.


Upon
adoption of AcG-13 the Trust recorded in 2005, $2.8 million ($1.7 million net
of tax) of a deferred financial derivative loss, which was amortized into
earnings under AcG-13. Because this amount was required to be expensed under
U.S. GAAP prior to 2005, an adjustment for this amount was made during the 2005
year.


c)              Temporary equity:


The
Trust issues units and exchangeable shares that are redeemable at the option of
the unitholder. Under Canadian GAAP, all Trust units are classified as
unitholders’ equity and all exchangeable shares are classified as
non-controlling interest. For U.S. GAAP, Trust units and exchangeable shares
that are redeemable at the option of the unitholder are valued at their
redemption value and presented as temporary equity. The redemption value of the
trust units and exchangeable shares is based on the trading value of the units
at the balance sheet date. Changes in redemption value are charged or credited
to accumulated earnings. As contributed surplus relates to trust units, it has
also been reclassified to temporary equity.











d)              Comprehensive
income:


Comprehensive
income is recognized and measured under U.S. GAAP pursuant to Statement of
Financial Accounting Standard (SFAS) 130, “Reporting Comprehensive Income”.
This standard defines comprehensive income as all changes in equity other than
those resulting from investments by owners and distributions to owners.
Comprehensive income is comprised of two components, net income and other
comprehensive income (“OCI”). OCI refers to amounts that are recorded as an
element of shareholders’ equity but are excluded from net income because these
transactions or events were attributed to changes from non-owner sources.
Comprehensive income is equivalent to net income in 2006 and 2005.


e)              Convertible
Debentures:


Under Canadian GAAP, certain of the Trust’s
convertible debentures were classified as debt with a portion, representing the
value associated with the conversion feature, being allocated to equity under
Canadian GAAP.  In addition, under
Canadian GAAP a non-cash interest expense representing the effective yield of
the debt component is recorded in the consolidated statement of earnings with a
corresponding credit to the convertible debenture liability balance to accrete
that balance to the full principal due on maturity.


Under U.S. GAAP, the convertible debentures in their
entirety are classified as debt.  The
difference between the fair value and the face value of the debentures is
amortized over the life of the debentures using the effective yield method.


f)                Unit-Based
Compensation:


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.  Under
Canadian GAAP, compensation expense associated with rights granted under the
plan is measured at the date of exercise or at the date of the financial
statement 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.


U.S. GAAP, SFAS 123R “Share Based Payments” eliminates
the ability to account for share-based compensation using APB 25, “Accounting
for Stock Issued to Employees” and generally requires instead, that such
transactions be accounted for using a fair-value-based method.  The methodology for determining the fair
value of equity instruments issued in exchange for employee services prescribed
by SFAS 123R differs from that prescribed by Canadian GAAP.  Under U.S. GAAP, the Trust unit liability is
calculated based on the RTUs’ and PTUs’ fair value at each reporting date until
the date of settlement.  Compensation
cost for each period is based on the change in the fair value of the RTUs and
PTUs for each reporting period.  When the
RTUs and PTUs vest, the amounts recorded as a trust unit rights liability, are
recorded to mezzanine equity.


For the period ended December 31, 2005, the Trust
recorded share-based compensation using APB 25, and for the 2006 fiscal year
the Trust used SFAS 123R.


The Trust adopted SFAS 123R using the modified
prospective approach.  As at and during
the year ended December 31, 2006 the Trust has recorded additional unit-based
compensation expense totalling $2 million, additional PP&E totalling $1
million and an additional liability totalling $3 million under U.S. GAAP
relating to difference in methodology in determining the fair value of certain
equity instruments.  As the Trust adopted
SFAS 123R using the modified prospective approach, prior periods 











have not been restated, as required by the
standard.  SFAS 123R, under the modified
prospective approach, requires the cumulative impact of a change in an
accounting policy to be presented in the current years statement of
earnings.  As no PTUs were outstanding as
at December 31, 2005, there was no impact of adopting SFAS 123R.


Assumptions


We used the Binomial
Lattice model to estimate the fair value of our stock-based compensation, with
the following assumptions:


	
  Expected Annual Distribution
  per Unit ($/unit)

  	
   

  	
  2.76

  	
   

  
	
  Expected
  Volatility

  	
   

  	
  36

  	
  %

  
	
  Risk-Free
  Interest Rate

  	
   

  	
  4.5

  	
  %

  
	
  Fair Value per Option
  Grant

  	
   

  	
  $ 24.34

  	
   

  



 


The basis for our assumptions, among other things, is as follows:


·                  Annual
distribution expectations take into account historical distribution payments
and reflect our expectation for future payments.


·                  Volatility
expectations are based on our historical unit price volatility.


·                  Our
risk-free interest rate assumption is the three month Canadian treasury bill
rate.


·                  We
assume forfeiture rates based on historical experience.


(g)           Additional U.S. GAAP disclosures:


	
  ($000s)

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Components of
  accounts receivable

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Trade

  	
   

  	
  $ 86,813

  	
   

  	
  $   38,571

  	
   

  
	
  Accruals

  	
   

  	
  168,376

  	
   

  	
  85,606

  	
   

  
	
  Other accruals

  	
   

  	
  6,309

  	
   

  	
  16,731

  	
   

  
	
   

  	
   

  	
  $ 261,498

  	
   

  	
  $ 140,908

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Components of
  prepaid expenses and deposits

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Prepaid expenses

  	
   

  	
  $   3,101

  	
   

  	
  $        828

  	
   

  
	
  Prepaid interest

  	
   

  	
  3,949

  	
   

  	
  —

  	
   

  
	
  Prepaid inventory

  	
   

  	
  6,131

  	
   

  	
  —

  	
   

  
	
  Funds on deposit

  	
   

  	
  21,466

  	
   

  	
  10,802

  	
   

  
	
   

  	
   

  	
  $ 34,647

  	
   

  	
  $   11,630

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Components of
  accounts payable

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Accounts payable

  	
   

  	
  $ 125,230

  	
   

  	
  $   43,498

  	
   

  
	
  Capital accrual

  	
   

  	
  59,100

  	
   

  	
  31,028

  	
   

  
	
  Operating accrual

  	
   

  	
  42,080

  	
   

  	
  28,233

  	
   

  
	
  Other liabilities

  	
   

  	
  33,796

  	
   

  	
  54,609

  	
   

  
	
   

  	
   

  	
  $ 260,206

  	
   

  	
  $ 157,368

  	
   

  



 











(h)         The net change in
non-cash working capital balances comprises the following:


	
  ($000s)

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
  Accounts receivable

  	
   

  	
  $ 75,172

  	
   

  	
  $ (29,008

  	
  )

  
	
  Prepaid expenses and deposits

  	
   

  	
  (17,174

  	
  )

  	
  1,975

  	
   

  
	
  Deferred financing charges

  	
   

  	
  —

  	
   

  	
  2,622

  	
   

  
	
  Accounts payable

  	
   

  	
  (87,246

  	
  )

  	
  17,830

  	
   

  
	
  Income taxes payable

  	
   

  	
  (32,966

  	
  )

  	
  —

  	
   

  
	
  Distributions payable

  	
   

  	
  11,436

  	
   

  	
  —

  	
   

  
	
   

  	
   

  	
  $ (50,778

  	
  )

  	
  $   (6,581

  	
  )

  
	
  Relating to:

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Operating
  activities

  	
   

  	
  $ (50,778

  	
  )

  	
  $   (7,812

  	
  )

  
	
  Financing
  activities

  	
   

  	
  —

  	
   

  	
  1,231

  	
   

  
	
  Investing
  activities (1)

  	
   

  	
  —

  	
   

  	
  —

  	
   

  
	
   

  	
   

  	
  $ (50,778

  	
  )

  	
  $   (6,581

  	
  )

  







(1) Non-cash working capital
included in capital expenditures was $65.3 million (2005 - $78.0 million).


(i)                                    Additional
disclosure


The Trust presents oil and natural gas sales and royalty amounts gross
in the Consolidated Statement of Earnings. 
These line items would be combined and presented net in a statement of
earnings prepared in accordance with U.S. GAAP. 
This difference does not result in an adjustment to the financial
results as reported under Canadian GAAP.


 (j)           StarPoint
Acquisition


The merger was
accounted for as an acquisition of StarPoint by Acclaim using the purchase
method of accounting.  Goodwill paid was
attributable to the fair value assigned to the reserves acquired and the
knowledge and business relationships acquired through the management team and
employees of StarPoint.  The amount of
Goodwill deductible for tax purposes is nil.


The consolidated
financial statements reflect the operations of StarPoint from January 5,
2006.  If the acquisition had occurred on
January 1, 2005 the following pro forma results would have been realized by the
Trust in 2005:


 


	
  ($000s except per unit amounts)

  	
   

  	
  2005

  	
   

  
	
   

  	
   

  	
  (unaudited)

  	
   

  
	
  Revenue

  	
   

  	
  $ 1,170,928

  	
   

  
	
  Net income

  	
   

  	
  $    123,915

  	
   

  
	
  Net income per
  Trust unit - basic

  	
   

  	
  $          0.63

  	
   

  
	
  Net income per
  Trust unit - diluted

  	
   

  	
  $          0.63

  	
   

  



 











(k)                                Samson
Acquisition


The consolidated
financial statements reflect the operations of Samson from August 31,
2006.  If the acquisition had occurred on
January 1, 2005 and January 1, 2006 the following pro forma results would have
been realized by the Trust in 2005 and 2006:


	
  ($000s except per unit amounts)

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
   

  	
   

  	
  (unaudited)

  	
   

  
	
  Revenue

  	
   

  	
  $ 1,289,500

  	
   

  	
  $    802,348

  	
   

  
	
  Net income

  	
   

  	
  $  234,474

  	
   

  	
  $    134,626

  	
   

  
	
  Net income per
  Trust unit - basic

  	
   

  	
  $         1.03

  	
   

  	
  $          1.22

  	
   

  
	
  Net income per Trust
  unit - diluted

  	
   

  	
  $         1.01

  	
   

  	
  1.21

  	
   

  



 


RECENT ACCOUNTING PRONOUNCEMENTS


In September 2006,
the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit
Pension and Other Postretirement Plans — an amendment of SFAS Nos. 87, 88, 106
and 132R. This statement requires the an entity to recognize in its
consolidated balance sheet the overfunded or underfunded status of its defined
benefit plans as an asset or liability and to recognize changes in that funded
status in the year in which the changes occur through comprehensive income.
This statement also requires that the entity measure the funded status of a
plan as of December 31 rather than September 30 as previously
permitted. The adoption of this standard at December 31, 2006 had no
impact on the Trust’s financial statements.


In September 2006,
the U.S. Securities and Exchange Commission released Staff Accounting Bulletin
No. 108, Considering the Effects of Prior Year Misstatements when
Quantifying Misstatements in Current Year Financial Statements (SAB 108), which
provides interpretive guidance on the SEC’s views regarding the process of
quantifying materiality of financial statement misstatements. SAB 108 was
effective for fiscal years ending after November 15, 2006, with early
application for the first interim period ending after November 15, 2006.
The adoption of this standard at December 31, 2006 had no impact on the
Trust’s financial statements.


In June 2006, the
EITF finalized Issue 06-3, How Taxes Collected from Customers and Remitted to
Governmental Authorities Should Be Presented in the Income Statement. The Task
Force reached a consensus that this EITF applied to any tax assessed by a
governmental authority that is directly imposed on a revenue-producing
transaction between a seller and a customer and may include, but is not limited
to sales, use, value added, and some excise taxes. The EITF concluded that the
presentation of taxes within the scope of this issue may be either gross
(included in revenues and costs) or net (excluded from revenues and costs) and
is an accounting policy decision that should be disclosed by the Trust.  The Trust is considering the effect of
adoption of EITF 06-03.


SFAS No. 151,
Inventory Costs, was issued by the FASB in November 2004. This statement amends
Accounting Research Bulletin No. 43, to clarify that abnormal amounts of
idle facility expense, freight, handling costs and wasted materials should be
recognized as current-period charges, and it also requires that allocation of
fixed production overheads be based on the normal capacity of the related
production facilities. This statement was adopted by the Trust on
January 1, 2006 and it did not have a material impact on the Trust’s
financial statements.


In June 2006, the
FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes. This interpretation clarifies the criteria for recognizing income tax
benefits under FASB Statement No. 109, Accounting for Income Taxes, and
requires additional financial statement disclosures about uncertain tax
positions. The interpretation is effective beginning January 1, 2007. The
Trust is currently evaluating this interpretation and does not expect a
material impact on its financial statements.











In September 2006,
the FASB issued SFAS No. 157, Fair Value Measurements. This Statement defines
fair value, establishes a framework for measuring fair value in generally
accepted accounting principles (GAAP), and expands disclosures about fair value
measurements. This Statement applies under other accounting pronouncements that
require or permit fair value measurements, and where applicable simplifies and
codifies related guidance within GAAP and does not require any new fair value
measurements. The Statement is effective for fiscal years beginning
January 1, 2008. Provisions of the Statement are to be applied
prospectively except in limited situations. The Trust does not expect the
initial adoption of this Statement to have a material impact on its financial
statements.


In June 2005, the
FASB issued SFAS 154, Accounting Changes and Error Corrections, which replaces
APB Opinion 20 and FASB Statement 3. 
Statement 154 changes the requirements for the accounting and reporting
of a change in accounting principle. 
Opinion 20 previously required that most voluntary changes in accounting
principle be recognized by including the cumulative effect of the new
accounting principle in net income of the period of the change.  Statement 154 now requires retrospective
application of changes in accounting principle to prior period financial
statements, unless it is impracticable to determine either the period-specific
effects or the cumulative effect of the change. 
The adoption of this standard at January 1, 2006 had no impact on the
Trust’s financial statements.


In February 2006,
FASB issued SFAS 155, Accounting for Certain Hybrid Financial Instruments — an
amendment of SFAS 133 and 140.  This
statement amends SFAS 133, Accounting for Derivative Instruments and Hedging
Activities, and SFAS 140, Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities. 
This Statement resolves issues addressed in SFAS 133 Implementation
Issue No. D1, Application of Statement 133 to Beneficial Interests in
Securitized Financial Assets.  The
Statement a) permits fair value remeasurement for any hybrid financial
instrument that contains an embedded derivative that otherwise would require
bifurcation, b) clarifies which interest-only strips and principal-only strips
are not subject to the requirements of SFAS 133, c) establishes a requirement
to evaluate interests in securitized financial assets to identify interests
that are freestanding derivatives or that hybrid financial instruments that
contain an embedded derivative requiring bifurcation, d) clarifies that
concentrations of credit risk in the form of subordination are not embedded
derivatives, and e) amends SFAS 140 to eliminate the prohibition on a
qualifying special-purpose entity from holding a derivative financial
instrument that pertains to a beneficial interest other than another derivative
financial instrument.  This Statement is
effective for all financial instruments acquired or issued after the beginning
of an entity’s first fiscal year that begins after September 15, 2006 with
early adoption permitted.  The Trust is
considering the effect of adoption of SFAS 155.


In December 2004,
the FASB issued Statement 153, Exchanges of Non-Monetary Assets, an amendment
of APB Opinion 29, Accounting for Non-Monetary Transactions.  This amendment eliminates the exception for
Non-Monetary exchanges of similar productive assets and replaces it with a
general exception for exchanges of non-monetary assets that do not have
commercial substance.  Under Statement
153, if a non-monetary exchange of similar productive assets meets a
commercial-substance test and fair value is determinable, the transaction must
be accounted for at fair value resulting in the recognition of a gain or
loss.  This statement is effective for
non-monetary transactions in fiscal periods that begin after June 15, 2005 The
adoption of this standard at January 1, 2006 had no impact on the Trust’s
financial statements.


In February 2007,
the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and
Financial Liabilities — Including an Amendment of FASB Statement No. 115.”  This pronouncement permits entities to use
the fair value method to measure certain financial assets and liabilities by
electing an irrevocable option to use the fair value method at specified
election dates.  After election of the
option, subsequent changes in fair value would result in the recognition of
unrealized gains or losses as period costs during the period the change
occurred.  SFAS No. 159 becomes effective
as of the beginning of the first fiscal year that begins after November 15,
2007, with early adoption permitted. 
However, entities may not retroactively apply the provisions of SFAS No.
159 to fiscal years preceding the date of adoption.  We are currently evaluating the impact of
SFAS No. 159 may have on our financial position, results of operations and cash
flows.











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; 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.











SUPPLEMENTARY OIL AND GAS
INFORMATION — SFAS 69 (UNAUDITED)


The tables in this
section set forth oil and gas information prepared by the Registrant in
accordance with U.S disclosure standards, pertaining to SFAS 69, “Disclosure
about Oil and Gas Producing Activities”.


Standardized Measure of
Discounted Future Net Cash Flows and Changes Therein


In calculating the
standardized measure of discounted future net cash flows, year-end constant
prices and cost assumptions were applied to Canetic’s annual future production from
proved reserves to determine cash inflows. Future production and development
costs are based on constant price assumptions and assume the continuation of
existing economic, operating and regulatory conditions. Future income taxes are
calculated by applying statutory income tax rates to future pre-tax cash flows
after provision for the tax cost of the oil and natural gas properties based
upon existing laws and regulations. The Trust is currently not taxable. The
discount was computed by application of a 10 percent discount factor to the
future net cash flows. The calculation of the standardized measure of
discounted future net cash flows is based upon the discounted future net cash
flows prepared by Canetic’s independent qualified reserves evaluators in relation
to the reserves they respectively evaluated, and adjusted by Canetic is to
account for management’s estimates of risk management activities, asset
retirement obligations and future income taxes.


Canetic cautions that the
discounted future net cash flows relating to proved oil and gas reserves are an
indication of neither the fair market value of the Registrant’s oil and gas
properties, nor of the future net cash flows expected to be generated from such
properties. The discounted future cash flows do not include the fair market
value of exploratory properties and probable or possible oil and gas reserves,
nor is consideration given to the effect of anticipated future changes in crude
oil and natural gas prices, development, asset retirement and production costs
and possible changes to tax and royalty regulations. The prescribed discount
rate of 10 percent may not appropriately reflect interest rates.


Capitalized
Costs Relating to Oil and Gas Producing Activities


($
000s)


	
  As At December 31,

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
  Proved oil and
  gas properties

  	
   

  	
  $ 5,584,737

  	
   

  	
  $ 1,913,013

  	
   

  
	
  Unproved oil and
  gas properties

  	
   

  	
  294,786

  	
   

  	
  42,459

  	
   

  
	
  Total capital
  costs

  	
   

  	
  5,879,523

  	
   

  	
  1,955,472

  	
   

  
	
  Accumulated
  depletion and depreciation

  	
   

  	
  1,281,864

  	
   

  	
  637,555

  	
   

  
	
  Net capitalized costs

  	
   

  	
  $ 4,597,659

  	
   

  	
  $ 1,317,917

  	
   

  



 


Costs Incurred in Oil and Gas
Property Acquisition,


Exploration and Development
Activities


($
000s)


	
  For the years ended December 31,(1)

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
  Property
  acquisition costs (1)

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Proved oil and gas properties

  	
   

  	
  $ 3,237,969

  	
   

  	
  $        8,944

  	
   

  
	
  Unproved oil and gas properties

  	
   

  	
  237,530

  	
   

  	
  —

  	
   

  
	
  Exploration
  costs (2)

  	
   

  	
  2,783

  	
   

  	
  3,139

  	
   

  
	
  Development
  costs (3)

  	
   

  	
  348,505

  	
   

  	
  169,082

  	
   

  
	
  Total

  	
   

  	
  $ 3,826,787

  	
   

  	
  $ 181,165

  	
   

  







(1)          Acquisitions are net of
disposition of properties.


(2)          Cost of geological and
geophysical capital expenditures.


(3)          Development and
facilities capital expenditures and drilling and completion costs.











Results of Operations for
Producing activities


($
000s)


	
  For the years ended December 31,

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
  Oil and gas
  sales, net of royalties and commodity contracts

  	
   

  	
  $ 1,149,494

  	
   

  	
  $    624,526

  	
   

  
	
  Lease operating,
  costs and capital taxes

  	
   

  	
  263,978

  	
   

  	
  137,682

  	
   

  
	
  Transportation
  costs

  	
   

  	
  18,968

  	
   

  	
  9,897

  	
   

  
	
  Depletion,
  depreciation and accretion

  	
   

  	
  656,613

  	
   

  	
  238,253

  	
   

  
	
  Operating income

  	
   

  	
  209,935

  	
   

  	
  238,694

  	
   

  
	
  Income taxes

  	
   

  	
  5,567

  	
   

  	
  —

  	
   

  
	
  Results of
  operations from producing activities

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  (excluding corporate
  overhead and interest costs)

  	
   

  	
  $    204,368

  	
   

  	
  $    238,694

  	
   

  







(1)          Canetic is currently not
taxable, current income tax disclosed for the years 2005 through 2006 represent
Large Corporation Tax, which is calculated by reference to balance sheet items
(debt and equity) and not by income items.


Reserve Quantity Information for
the Year Ended December 31, 2005


Constant
Prices and Costs


	
   

  	
   

  	
  Light and

  	
   

  	
   

  	
   

  	
  Natural

  	
   

  	
  Natural Gas

  	
   

  	
  Barrels of Oil

  	
   

  
	
  Net proved

  	
   

  	
  Medium oil

  	
   

  	
  Heavy Oil

  	
   

  	
  Gas

  	
   

  	
  Liquids

  	
   

  	
  Equivalent

  	
   

  
	
  Reserves

  	
   

  	
  (mbbls)

  	
   

  	
  (mbbls)

  	
   

  	
  (bcf)

  	
   

  	
  (mbbls)

  	
   

  	
  (mboe)

  	
   

  
	
  December
  31, 2004

  	
   

  	
  34,604

  	
   

  	
  7,439

  	
   

  	
  151,085

  	
   

  	
  5,621

  	
   

  	
  72,845

  	
   

  
	
  Extensions

  	
   

  	
  543

  	
   

  	
  468

  	
   

  	
  25,381

  	
   

  	
  592

  	
   

  	
  5,848

  	
   

  
	
  Improved
  recovery

  	
   

  	
  111

  	
   

  	
  564

  	
   

  	
  1,781

  	
   

  	
  157

  	
   

  	
  943

  	
   

  
	
  Technical
  revisions

  	
   

  	
  2,405

  	
   

  	
  116

  	
   

  	
  7,920

  	
   

  	
  433

  	
   

  	
  4,540

  	
   

  
	
  Discoveries

  	
   

  	
  65

  	
   

  	
  415

  	
   

  	
  2,310

  	
   

  	
  31

  	
   

  	
  760

  	
   

  
	
  Acquisitions

  	
   

  	
  27

  	
   

  	
  —

  	
   

  	
  52

  	
   

  	
  2

  	
   

  	
  40

  	
   

  
	
  Dispositions

  	
   

  	
  (261

  	
  )

  	
  —

  	
   

  	
  (1,743

  	
  )

  	
  (19

  	
  )

  	
  (608

  	
  )

  
	
  Economic Factors

  	
   

  	
  473

  	
   

  	
  204

  	
   

  	
  2,275

  	
   

  	
  86

  	
   

  	
  1,130

  	
   

  
	
  Infill Drilling

  	
   

  	
  640

  	
   

  	
  —

  	
   

  	
  3,428

  	
   

  	
  60

  	
   

  	
  1,359

  	
   

  
	
  Production

  	
   

  	
  (4,197

  	
  )

  	
  (1,585

  	
  )

  	
  (29,203

  	
  )

  	
  (1,328

  	
  )

  	
  (11,976

  	
  )

  
	
  Change for the
  year

  	
   

  	
  (194

  	
  )

  	
  182

  	
   

  	
  12,201

  	
   

  	
  14

  	
   

  	
  2,036

  	
   

  
	
  December 31, 2005

  	
   

  	
  34,410

  	
   

  	
  7,621

  	
   

  	
  163,286

  	
   

  	
  5,635

  	
   

  	
  74,881

  	
   

  



 


Reserve Quantity Information for
the Year Ended December 31, 2006


Constant
Prices and Costs


	
   

  	
   

  	
  Light and

  	
   

  	
   

  	
   

  	
  Natural

  	
   

  	
  Natural Gas

  	
   

  	
  Barrels of Oil

  	
   

  
	
  Net proved

  	
   

  	
  Medium oil

  	
   

  	
  Heavy Oil

  	
   

  	
  Gas

  	
   

  	
  Liquids

  	
   

  	
  Equivalent

  	
   

  
	
  Reserves

  	
   

  	
  (mbbls)

  	
   

  	
  (mbbls)

  	
   

  	
  (bcf)

  	
   

  	
  (mbbls)

  	
   

  	
  (mboe)

  	
   

  
	
  December
  31, 2005

  	
   

  	
  34,410

  	
   

  	
  7,621

  	
   

  	
  163,286

  	
   

  	
  5,635

  	
   

  	
  74,881

  	
   

  
	
  Starpoint

  	
   

  	
  41,199

  	
   

  	
  10,440

  	
   

  	
  127,325

  	
   

  	
  1,951

  	
   

  	
  74,811

  	
   

  
	
  Extensions

  	
   

  	
  1,261

  	
   

  	
  365

  	
   

  	
  11,191

  	
   

  	
  732

  	
   

  	
  4,223

  	
   

  
	
  Improved
  recovery

  	
   

  	
  —

  	
   

  	
  2,749

  	
   

  	
  3,437

  	
   

  	
  169

  	
   

  	
  3,491

  	
   

  
	
  Technical
  revisions

  	
   

  	
  5,489

  	
   

  	
  (2,596

  	
  )

  	
  6,216

  	
   

  	
  514

  	
   

  	
  4,443

  	
   

  
	
  Discoveries

  	
   

  	
  291

  	
   

  	
  0

  	
   

  	
  547

  	
   

  	
  49

  	
   

  	
  432

  	
   

  
	
  Acquisitions

  	
   

  	
  834

  	
   

  	
  —

  	
   

  	
  106,555

  	
   

  	
  1,881

  	
   

  	
  20,474

  	
   

  
	
  Dispositions

  	
   

  	
  —

  	
   

  	
  —

  	
   

  	
  (535

  	
  )

  	
  (85

  	
  )

  	
  (174

  	
  )

  
	
  Economic Factors

  	
   

  	
  103

  	
   

  	
  32

  	
   

  	
  263

  	
   

  	
  10

  	
   

  	
  189

  	
   

  
	
  Infill Drilling

  	
   

  	
  2,211

  	
   

  	
  835

  	
   

  	
  3,364

  	
   

  	
  46

  	
   

  	
  3,653

  	
   

  
	
  Production

  	
   

  	
  (10,012

  	
  )

  	
  (2,305

  	
  )

  	
  (54,034

  	
  )

  	
  (1,536

  	
  )

  	
  (22,859

  	
  )

  
	
  Change for the
  year

  	
   

  	
  41,376

  	
   

  	
  9,520

  	
   

  	
  204,329

  	
   

  	
  3,731

  	
   

  	
  88,683

  	
   

  
	
  December 31, 2006

  	
   

  	
  75.786

  	
   

  	
  17,141

  	
   

  	
  367,615

  	
   

  	
  9,366

  	
   

  	
  163,564

  	
   

  



 











(1)          Definitions:


(a)          “Net” reserves are the
remaining reserves of Canetic after deduction of estimated royalties and
including royalty interest


(b)         “Proved” reserves are the
estimated quantities of crude oil, natural gas and NGL’s which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made.


(2)          Canetic does not file
any estimates of total net proved crude oil or natural gas reserves with any
U.S federal authority or agency other than the SEC.


Standardize Measure of Discounted
Future Net Cash Flows


Relating to Proved Oil and Gas
Reserves


($
000s)


	
   

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
  Future Cash
  inflows

  	
   

  	
  $ 9,581,387

  	
   

  	
  $ 5,228,165

  	
   

  
	
  Future
  production costs

  	
   

  	
  4,262,896

  	
   

  	
  2,129,770

  	
   

  
	
  Future
  development costs

  	
   

  	
  398,264

  	
   

  	
  124,645

  	
   

  
	
  Future income
  taxes (1)

  	
   

  	
  —

  	
   

  	
  —

  	
   

  
	
  Future net cash
  flows

  	
   

  	
  4,920,227

  	
   

  	
  2,973,750

  	
   

  
	
  Less 10% annual
  discount factor

  	
   

  	
  1,910,962

  	
   

  	
  1,180,624

  	
   

  
	
  Standardize measure of
  discounted future net cash flows

  	
   

  	
  $ 3,009,265

  	
   

  	
  $ 1,793,126

  	
   

  







(1)          Canetic is currently not
taxable


Reconciliation of Changes in Net
Present Values of Future Net Revenue


Discounted at 10% Per Year


Proved Reserves- Constant Prices
and Costs


($
000s)


	
   

  	
   

  	
  2006

  	
   

  	
  2005

  	
   

  
	
  Opening Balance

  	
   

  	
  1,793,127

  	
   

  	
  1,122,818

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Acquisition of StarPoint

  	
   

  	
  1,597,905

  	
   

  	
   

  	
   

  
	
  Sales and Transfers of Oil and Gas Produced, Net of Production Costs
  and Royalties

  	
   

  	
  (923,545

  	
  )

  	
  (201,813

  	
  )

  
	
  Net Change in Prices, Production Costs and Royalties Related to
  Future Production

  	
   

  	
  (442,994

  	
  )

  	
  551,948

  	
   

  
	
  Changes in Previously Estimated Development Costs incurred During the
  Period

  	
   

  	
  —

  	
   

  	
  —

  	
   

  
	
  Changes in Estimated Future Development Costs

  	
   

  	
  (20,535

  	
  )

  	
  (33,532

  	
  )

  
	
  Extensions, Infill Drilling and Improved Recovery

  	
   

  	
  236,271

  	
   

  	
  153,210

  	
   

  
	
  Discoveries

  	
   

  	
  9,380

  	
   

  	
  14,288

  	
   

  
	
  Acquisition of Reserves

  	
   

  	
  325,475

  	
   

  	
  752

  	
   

  
	
  Dispositions of Reserves

  	
   

  	
  (17,167

  	
  )

  	
  (12,177

  	
  )

  
	
  Net change Resulting from Revisions in Quantity Estimates

  	
   

  	
  112,246

  	
   

  	
  85,351

  	
   

  
	
  Accretion of Discount

  	
   

  	
  339,103

  	
   

  	
  112,282

  	
   

  
	
  Net Change in Income Taxes

  	
   

  	
  —

  	
   

  	
  —

  	
   

  
	
  Closing Balance

  	
   

  	
  3,009,266

  	
   

  	
  1,793,127