EXHIBIT 1
---------
HARVEST ENERGY TRUST
FORM 51-102 F4
BUSINESS ACQUISITION REPORT
ITEM 1 IDENTITY OF REPORTING ISSUER
1.1 NAME AND ADDRESS OF REPORTING ISSUER
Harvest Energy Trust (the "TRUST")
2100, 330 - 5th Avenue S.W.
Calgary Alberta T2P 0L4
1.2 EXECUTIVE OFFICER
The name of the executive officer of Harvest Operations Corp. ("HARVEST
OPERATIONS" or the "CORPORATION"), administrator of the Trust, who is
knowledgeable about the significant acquisition and this Report is
David Rain, Vice President, Chief Financial Officer and Corporate
Secretary and his business telephone number is (403) 265-1178.
ITEM 2 DETAILS OF ACQUISITION
2.1 NATURE OF ASSETS ACQUIRED
On August 2, 2005 Harvest Breeze Trust No. 1 ("HBT1") and Harvest
Breeze Trust No. 2 ("HBT2"), each of which is a subsidiary of the
Trust, acquired Nexen Canada No. 1 Partnership (the "PARTNERSHIP") and
related assets from Nexen Inc. and a corporation and a partnership
controlled by it (collectively, the "VENDOR") for consideration of
approximately $238 million, after closing adjustments (the
"ACQUISITION"). Pursuant to the Acquisition, HBT1 and HBT2 acquired
medium gravity crude oil assets located in northeastern British
Columbia which are held in the Partnership and related assets
(collectively, the "NEW PROPERTIES").
A more detailed description of the nature of the New Properties is
contained in Schedule C to this Report.
2.2 DATE OF ACQUISITION
The date of the Acquisition for accounting purposes was August 2, 2005.
2.3 CONSIDERATION
The total consideration for the Acquisition was approximately $238
million in cash, after closing adjustments. The Trust financed the
Acquisition with a new revolving credit facility (the "NEW CREDIT
FACILITY") with a syndicate of banks. The New Credit Facility increased
the Trust's borrowing capacity from $325 million to $400 million and
bears interest at the prime rate plus an applicable margin as
determined by the Trust's debt to cash flow ratio. The New Credit
Facility is secured by a $750 million principal amount fixed and
floating charge debenture over substantially all of the Trust's assets.
The New Credit Facility is scheduled to mature in July 2006 subject to
a one-year extension and a semi-annual review of the borrowing base.
-2-
The amount drawn on the New Credit Facility was partially repaid with
the net proceeds from a $250 million bought deal financing with a
syndicate of underwriters completed on August 2, 2005 (the "BOUGHT DEAL
FINANCING"). The Bought Deal Financing consisted of an offering of a
total of 6,505,600 subscription receipts ("SUBSCRIPTION RECEIPTS")
issued at a price of $26.90 per Subscription Receipt for gross proceeds
of $175 million and $75 million principal amount of 6.5% convertible
unsecured subordinated debentures (the "DEBENTURES"). With the closing
of the Acquisition, holders of Subscription Receipts received one trust
unit of the Trust ("TRUST UNIT") for each Subscription Receipt held,
effective as of 5:00 p.m. on August 2, 2005. The Debentures consisted
of 75,000 Debentures having a principal amount of $1,000 per Debenture.
Each Debenture had an initial maturity date of September 30, 2005 which
was automatically extended to December 31, 2010 as result of the
closing of the Acquisition and bears interest from the date of issue at
6.5% per annum, payable semi-annually in arrears on June 30 and
December 31 of each year, commencing December 31, 2005.
2.4 EFFECT ON FINANCIAL POSITION
The New Properties consist primarily of medium gravity crude oil assets
located in northeastern British Columbia. The New Properties also
include undeveloped lands located in British Columbia and Alberta.
Pursuant to the Acquisition, HBT1 and HBT2 acquired an average 97%
working interest in approximately 77,500 gross acres (approximately
75,300 net acres) of land, of which approximately 54,300 net acres are
undeveloped and are strategically positioned for further oil and
natural gas exploitation and development. The average gross production
of the New Properties for the six months ended June 30, 2005 was
approximately 5,560 bbls/d of medium crude oil. The Trust will operate
100% of and will acquire a working interest of 100% in the crude oil
production from these properties.
Total reserves associated with the New Properties determined in
accordance with National Instrument 51-101 pursuant to reserve
evaluations (the "SPROULE REPORT") performed by Sproule Associates
Limited ("SPROULE") as at March 31, 2005 are as follows:
GROSS RESERVES
Proved producing reserves 13,979 MBOE
Total proved reserves 16,420 MBOE
Proved plus probable reserves 19,779 MBOE
NET RESERVES
Proved producing reserves 12,264 MBOE
Total proved reserves 14,346 MBOE
Proved plus probable reserves 17,200 MBOE
For further information in respect of the New Properties, see Schedule
C to this Report.
The Trust does not anticipate making significant changes to the assets
acquired, other than continuing to refine operations and seeking
efficiencies where possible. The Trust has no other plans relating to
its business as a result of the Acquisition. The Acquisition and the
related financings substantially increased the Trust's asset base,
trust units outstanding and debt balance.
-3-
The Trust believes the incremental cash flow associated with the
Properties is sufficient to service the increased debt issued as part
of the related financing.
A more detailed description of the effect of the Acquisition on the
operations of the Trust is contained under the heading "Effect of the
Acquisition on the Trust" contained in Schedule C to this Report.
All oil and natural gas information contained in this Business
Acquisition Report has been prepared and presented in accordance with
National Instrument 51-101. In this business acquisition report, all
estimates of oil and natural gas reserves and production are presented
on a "working interest" basis.
The Trust has adopted the standard of 6 Mcf:1 BOE when converting
natural gas to BOEs. BOE may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
2.5 PRIOR VALUATIONS
None.
2.6 PARTIES TO TRANSACTION
Not applicable.
2.7 DATE OF REPORT
October 14, 2005.
ITEM 3 FINANCIAL STATEMENTS
The unaudited pro forma consolidated financial statements of the Trust
as at June 30, 2005 and for the six months then ended and the year
ended December 31, 2004 are attached as Schedule A to this Report.
The unaudited schedule of revenues and expenses for the six months
ended June 30, 2005 and 2004 and the audited schedule of revenues and
expenses for each of the years in the two year period ended December
31, 2004 for the New Properties are attached as Schedule B to this
Report.
FORWARD-LOOKING INFORMATION
This Business Acquisition Report contains forward-looking information and
estimates with respect to the Trust and its operations and oil and natural gas
reserves. This information addresses future events and conditions, and as such
involves risks and uncertainties that could cause actual results to differ
materially from those contemplated by the information provided. These risks and
uncertainties include but are not limited to, factors intrinsic in domestic and
international politics and economics, general industry conditions including the
impact of environmental laws and regulations, imprecision of reserve estimates,
fluctuations in commodity prices, interest rates or foreign exchange rates and
stock market volatility.
SCHEDULE A
PRO FORMA CONSOLIDATED FINANCIAL
STATEMENTS OF THE TRUST
COMPILATION REPORT
To the Directors of Harvest Operations Corp.
We have read the accompanying unaudited pro forma consolidated balance sheet of
Harvest Energy Trust (the "Trust") as at June 30, 2005 and the unaudited pro
forma consolidated statements of income for the six months then ended and for
the year ended December 31, 2004, and have performed the following procedures:
1. Compared the figures in the columns captioned "Harvest Energy Trust" to
the unaudited interim consolidated financial statements of the Trust as
at June 30, 2005 and for the six months then ended.
2. Compared the figures in the column captioned "Harvest Energy Trust
Restated" for the year ended December 31, 2004 to the audited
consolidated statement of income of the Trust for the year ended
December 31, 2004 as adjusted for the changes in accounting policies
set out in the unaudited interim consolidated financial statements of
the Trust as at and for the six months ended June 30, 2005.
3. Compared the figures in the column captioned "Storm Energy Ltd." to a
schedule that combines the unaudited consolidated statement of income
of Storm Energy Ltd. for the three month period ended March 31, 2004
and the unaudited results of operations for the three month period
ended June 30, 2004 and found them to be in agreement.
4. Compared the figures in the column captioned "EnCana Properties" to a
schedule that combines the unaudited schedule of revenues, royalties
and operating expenses of the properties for the six month period ended
June 30, 2004, and the unaudited revenues, royalties and operating
expenses of the properties for the two months ended August 31, 2004 and
found them to be in agreement.
5. Compared the figures in the columns captioned "New Properties" to the
unaudited schedule of revenue, royalties and operating expenses
associated with the properties for the six month period ended June 30,
2005, and to the audited schedule of revenue, royalties and operating
expenses for the year ended December 31, 2004 and found them to be in
agreement.
6. Made enquiries of certain officials of the Trust who have
responsibility for financial and accounting matters about:
(a) the basis for the determination of the pro forma adjustments;
and
(b) whether the pro forma financial statements comply as to form
in all material respects with the regulatory requirements of
the various Securities Commissions and similar regulatory
authorities in Canada.
The officials:
(a) described to us the basis for determination of the pro forma
adjustments; and
A - 2
(b) stated that the pro forma financial statements comply as to
form in all material respects with the regulatory requirements
of the various Securities Commissions and similar regulatory
authorities in Canada.
7. Read the notes to the pro forma financial statements, and found them to
be consistent with the basis described to us for determination of the
pro forma adjustments.
8. Recalculated the application of the pro forma adjustments to the
aggregate of the amounts in the other applicable columns as at June 30,
2005 and for the six months then ended and for the year ended December
31, 2004 and found the amounts in the column captioned "Pro Forma
Consolidated" to be arithmetically correct.
A pro forma financial statement is based on management assumptions and
adjustments which are inherently subjective. The foregoing procedures are
substantially less than either an audit or a review, the objective of which is
the expression of assurance with respect to management's assumptions, the pro
forma adjustments and the application of the adjustments to the historical
financial information. Accordingly, we express no such assurance. The foregoing
procedures would not necessarily reveal matters of significance to the pro forma
financial statements, and we therefore make no representation about the
sufficiency of the procedures for the purposes of a reader of such statements.
(signed) "KPMG LLP"
Chartered Accountants
Calgary, Canada
October 14, 2005
A - 3
HARVEST ENERGY TRUST
Pro Forma Consolidated Balance Sheet
As at June 30, 2005
(000's)
==================================================================================================================================
EQUITY
HARVEST ISSUE/
HARVEST ENERGY TRUST CONVERTIBLE PRO FORMA
ENERGY TRUST NEW PROPERTIES ADJUSTMENTS SUBTOTAL DEBENTURES CONSOLIDATED
------------ -------------- ----------- -------- ---------- ------------
ASSETS
Current assets
Accounts receivable $ 66,329 -- -- $ 66,329 -- $ 66,329
Current portion of derivative 9,809 -- -- 9,809 -- 9,809
contracts
Prepaid expenses and deposits 45,929 -- -- 45,929 -- 45,929
Future income tax 9,963 -- -- 9,963 -- 9,963
---------- -------- ------ ---------- ------ ----------
132,030 -- -- 132,030 -- 132,030
Deferred charges 13,734 -- 1,500(2a) 15,234 3,036(2a) 18,270
Long term portion of derivative 3,608 -- -- 3,608 -- 3,608
contracts
Capital assets 924,588 212,000(2a) 4,100(2a) 1,140,688 -- 1,140,688
Goodwill 43,832 -- -- 43,832 -- 43,832
---------- -------- ------ ---------- ------ ----------
$1,117,792 $212,000 $5,600 $1,335,392 $3,036 $1,338,428
========== ======== ====== ========== ====== ==========
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued $ 101,672 -- -- $ 101,672 -- $ 101,672
liabilities
Cash distributions payable 8,754 -- -- 8,754 -- 8,754
Current portion of derivative
contracts 38,291 -- -- 38,291 -- 38,291
---------- -------- ------ ---------- ------ ----------
148,717 -- -- 148,717 -- 148,717
Bank debt 138,090 212,000(2a) 1,500(2a) 351,590 (237,950) 113,640
(2a)
Deferred gains 1,287 -- -- 1,287 -- 1,287
Long term portion of derivative 52,603 -- -- 52,603 -- 52,603
contracts
Convertible debentures 10,723 -- -- 10,723 72,145(2a, 82,868
2d)
Senior notes 306,350 -- -- 306,350 -- 306,350
Asset retirement obligation 94,042 -- 4,100(2a) 98,142 -- 98,142
Future income tax 14,806 -- -- 14,806 -- 14,806
---------- -------- ------ ---------- ------ ----------
766,618 212,000 5,600 984,218 (165,805) 818,413
Non-controlling interest 3,489 -- -- 3,489 -- 3,489
Unitholders' equity
Unitholders' capital 499,836 -- -- 499,836 175,000(2a) 665,936
(8,900)(2a)
Equity component of convertible
debentures 60 -- -- 60 2,741(2a, 2d) 2,801
Accumulated income 7,165 -- -- 7,165 -- 7,165
Accumulated cash distributions (159,376) -- -- (159,376) -- (159,376)
---------- -------- ------ ---------- ------ ----------
347,685 -- -- 347,685 168,841 516,526
---------- -------- ------ ---------- ------ ----------
$1,117,792 $212,000 $5,600 $1,335,392 $3,036 $1,338,428
========== ======== ====== ========== ====== ==========
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HARVEST ENERGY TRUST
Pro Forma Consolidated Statement of Income For the six months ended June 30,
2005 (000's except per unit amounts)
=================================================================================================================================
HARVEST EQUITY ISSUE /
HARVEST NEW ENERGY TRUST CONVERTIBLE PRO FORMA
ENERGY TRUST PROPERTIES ADJUSTMENTS SUBTOTAL DEBENTURES CONSOLIDATED
------------ ---------- ----------- -------- ---------- ------------
REVENUE
Oil and natural gas sales $ 273,044 $55,026 -- $ 328,070 -- $ 328,070
Royalty expense (42,850) (13,405) -- (56,255) -- (56,255)
---------- ------- -------- --------- ------ ----------
230,194 41,621 -- 271,815 -- 271,815
EXPENSES
Operating 55,983 9,618 65,601 -- 65,601
General and administrative 12,075 -- 500(2f) 12,575 -- 12,575
Interest on short term debt 5,369 -- 5,151(2a, 11,270 (5,151)(2a, 2d) 6,119
2d)
750(2d)
Interest on long term debt 13,778 -- -- 13,778 280(2a, 2d) 16,714
2,417(2a, 2d)
239(2d)
Depletion, depreciation and 78,975 -- 12,679(2e) 91,654 -- 91,654
accretion
Foreign exchange loss (gain) 5,367 -- -- 5,367 -- 5,367
Gains and losses on derivative
contracts 111,649 -- -- 111,649 -- 111,649
---------- ------- -------- --------- ------ ----------
283,196 9,618 19,080 311,894 (2,215) 309,679
---------- ------- -------- --------- ------ ----------
Income (losses) before taxes (53,002) 32,003 (19,080) (40,079) 2,215 (37,864)
TAXES
Current income tax 755 -- -- 755 -- 755
Future tax recovery (29,828) -- -- (29,828) -- (29,828)
---------- ------- -------- --------- ------ ----------
NET INCOME (LOSS) BEFORE
NON-CONTROLLING INTEREST (23,929) 32,003 (19,080) (11,006) 2,215 (8,791)
Non-controlling interest (375) -- 87(2i) (288) 17(2i) (271)
---------- ------- -------- --------- ------ ----------
NET INCOME (LOSS) FOR THE PERIOD $(23,554) $32,003 $(19,167) $(10,718) $2,198 $(8,520)
Loss per trust unit, basic $(0.55) $(0.17)
Loss per unit, diluted $(0.56) $(0.17)
A - 5
HARVEST ENERGY TRUST
Pro Forma Consolidated Statement of Income For the year ended December 31, 2004
(000's except per unit amounts)
=================================================================================================================
HARVEST
ENERGY STORM
TRUST ENERGY ADJUST- ENCANA ADJUST- NEW ADJUST-
RESTATED LTD. MENTS PROPERTIES MENTS PROPERTIES MENTS
-------- ---- ----- ---------- ----- ---------- -----
REVENUE
Oil and natural gas sales $331,331 $40,814 $(5,029) $187,592 -- $105,333 --
Royalty expense (54,236) (8,902) 1,095 (23,195) -- (25,683) --
Other -- 198 -- -- -- -- --
Alberta royalty tax credit -- 328 -- -- -- -- --
------- ------ ------- -------- -------- ------- --------
277,095 32,438 (3,934) 164,397 -- 79,650 --
EXPENSES
Operating 73,442 4,711 (1,024) 33,830 12,795
General and administrative 19,980 1,839 (1,075) -- 1,200 -- 1,000(2f)
Interest on short term debt 10,515 -- -- -- 3,000 -- 12,840(2a,
2d)
1,500
Interest on long term debt 11,183 1,113 2,957 -- 10,193 -- --
5,081
4,874
1,064
Depletion, depreciation and
accretion 102,776 9,153 6,734 -- 73,317 -- 24,094(2e)
Foreign exchange loss (gain) (7,111) -- -- -- -- -- --
Gains and losses on derivative
contracts 63,701 4,685 -- -- -- -- --
------- ------ ------- -------- -------- ------- --------
274,486 21,501 7,592 33,830 98,729 12,795 39,434
------- ------ ------- -------- -------- ------- --------
Income (loss) before taxes 2,609 10,937 (11,526) 130,567 (98,729) 66,855 (39,434)
TAXES
Current income tax -- 841 -- -- -- -- --
Large corporation tax 1,505 117 -- -- -- -- --
Future tax expense (recovery) (10,362) 2,293 (2,512) -- -- -- --
------- ------ ------- -------- -------- ------- --------
NET INCOME (LOSS) BEFORE 11,466 7,686 (9,014) 130,567 (98,729) 66,855 (39,434)
NON-CONTROLLING INTEREST
Non-controlling interest 225 -- (26) -- 620 -- 534(2i)
------- ------ ------- -------- -------- ------- --------
NET INCOME (LOSS) FOR THE PERIOD $11,241 $7,686 $(8,988) $130,567 $(99,349) $66,855 $(39,968)
Income per trust unit, basic $ 0.45
Income per unit, diluted $ 0.43
HARVEST EQUITY
ENERGY ISSUE /
TRUST CONVERTIBLE PRO FORMA
SUBTOTAL DEBENTURES CONSOLIDATED
-------- ---------- ------------
REVENUE
Oil and natural gas sales $660,041 -- $660,041
Royalty expense (110,921) -- (110,921)
Other 198 -- 198
Alberta royalty tax credit 328 -- 328
-------- ------ -------
549,646 -- 549,646
EXPENSES
Operating 123,754 -- 123,754
General and administrative 22,944 -- 22,944
Interest on short term debt 27,855 (12,840)(2a, 15,015
2d)
Interest on long term debt 36,465 581(2a, 2d) 42,415
4,875(2a,
2d)
494(2d)
Depletion, depreciation and
accretion 216,074 -- 216,074
Foreign exchange loss (gain) (7,111) -- (7,111)
Gains and losses on derivative
contracts 68,386 -- 68,386
-------- ------ -------
488,367 (6,890) 481,477
-------- ------ -------
Income (loss) before taxes 61,279 6,890 68,169
TAXES
Current income tax 841 -- 841
Large corporation tax 1,622 -- 1,622
Future tax expense (recovery) (10,581) -- (10,581)
-------- ------ -------
NET INCOME (LOSS) BEFORE 69,397 6,890 76,287
NON-CONTROLLING INTEREST
Non-controlling interest 1,353 134(2i) 1,487
-------- ------ -------
NET INCOME (LOSS) FOR THE PERIOD $ 68,044 $6,756 $74,800
Income per trust unit, basic $ 1.82
Income per unit, diluted $ 1.65
A - 6
HARVEST ENERGY TRUST
Notes to Consolidated Pro Forma Balance Sheet and Statements of Income
================================================================================
1. BASIS OF PRESENTATION
Harvest Energy Trust (the "Trust") is an open-ended, unincorporated investment
trust formed under the laws of Alberta. Pursuant to the trust indenture and an
administration agreement, the Trust is managed by its wholly owned subsidiary,
Harvest Operations Corp. ("Harvest Operations" or the "Corporation"). The Trust
acquires and holds net profit interests in oil and natural gas properties in
Alberta acquired and held by Harvest Operations and a partnership held by the
Subsidiary Trusts. The Trust acquires and holds net profit interests in oil and
natural gas properties in Saskatchewan and held by Harvest Sask. Energy Trust.
The Trust is the sole unitholder of Harvest Sask. Energy Trust. The New
Properties to be acquired, as described below, are held in a partnership. The
partnership will be owned by Harvest Breeze Trust 1 and Harvest Breeze Trust 2
(collectively "Subsidiary Trusts"), of which the Trust is the direct or indirect
sole unitholder of each. All properties under the Trust are operated by Harvest
Operations.
The accompanying unaudited consolidated pro forma financial statements have been
prepared by the management of Harvest Operations in accordance with Canadian
generally accepted accounting principles on a basis consistent with the
consolidated financial statements of the Trust. These consolidated pro forma
financial statements should be read in conjunction with the historical financial
statements of the Trust. The consolidated statement of income for the year ended
December 31, 2004 has been restated to reflect the adoption of new accounting
pronouncements. In the opinion of management, the pro forma consolidated
financial statements include all material adjustments necessary for fair
presentation in accordance with Canadian generally accepted accounting
principles.
The pro forma consolidated financial statements are not necessarily indicative
either of the results that actually would have occurred if the following events
reflected herein had taken place on the dates indicated or of the results that
may be obtained in the future.
o On June 30, 2004, the Trust completed a plan of arrangement with Storm
Energy Ltd. ("Storm"), whereby the Trust acquired all of the outstanding
shares of Storm for approximately $192.2 million, including assumed net
debt and transaction costs of approximately $67.3 million. As part of the
Plan of Arrangement, certain assets of Storm were transferred to a new
entity ("ExploreCo") which is owned by former Storm shareholders.
o On September 2, 2004, the Trust completed the acquisition of oil and
natural gas properties from EnCana Corporation ("EnCana") (the "EnCana
Properties"). The cost to the Trust and Harvest Operations was
approximately $511.4 million net of adjustments and costs.
o On October 14, 2004, Harvest Operations Corp. closed an agreement to sell,
on a private placement basis in the United States, US$250 million of senior
notes due October 15, 2011. The senior notes are unsecured and
unsubordinated and bear interest at an annual rate of 7 7/8% and were sold
at a price of 99.3392% of their principal amount. The senior notes are
unconditionally guaranteed by the Trust and all of its wholly-owned
subsidiaries.
o On June 24, 2005, the Subsidiary Trusts entered into an agreement to
acquire properties from a third party (the "New Properties"). The cost to
the Trust and the Corporation is approximately $238 million net of
adjustments, including transaction costs. Upon signing the agreement, a $26
million deposit was made.
A - 7
HARVEST ENERGY TRUST
Notes to Consolidated Pro Forma Balance Sheet and Statements of Income
================================================================================
The unaudited pro forma consolidated balance sheet and statement of income as at
and for the six month period ended June 30, 2005, and the statement of income
for the year ended December 31, 2004 have been based on the following financial
statements:
The unaudited consolidated balance sheet and statement of income of the Trust as
at and for the six month period ended June 30, 2005, the unaudited schedule of
revenue and expenses of the New Properties for the six months ended June 30,
2005 and the audited consolidated statement of income of the Trust for the year
ended December 31, 2004, the audited schedule of revenue and expenses of the New
Properties for the year ended December 31, 2004, the unaudited schedule of
revenues, royalties and operating expenses for the EnCana Properties for the six
month period ended June 30, 2004, and the unaudited financial statements for
Storm for the six months ended June 30, 2004.
2. PRO FORMA ASSUMPTIONS AND ADJUSTMENTS
The consolidated pro forma statements of income for the six month period ended
June 30, 2005 and for the year ended December 31, 2004 have been prepared
assuming that the transactions described in notes 2(a), 2(b) and 2(c) were
completed at the beginning of the respective periods as follows:
a) ACQUISITION OF NEW PROPERTIES
The amounts included in the pro forma consolidated statements of income for the
six month period ended June 30, 2005 and the year ended December 31, 2004
related to the New Properties are derived from the unaudited Schedule of Revenue
and Expenses for the New Properties for the six month period ended June 30, 2005
and the audited Schedule of Revenue and Expenses for the New Properties for the
year ended December 31, 2004, respectively. Consideration for the New Properties
is estimated to be $238 million, consisting of a purchase price of $260 million
net of estimated interim adjustments and transaction costs of $22 million. On
June 24, 2005, a deposit of $26 million was made and has been included as part
of Capital Assets in the Consolidated Balance Sheet of the Trust at June 30,
2005. Asset retirement obligations related to this property are estimated to be
$4.1 million.
In accordance with the financing requirements it has been assumed for these
consolidated pro forma financial statements that the following transactions have
occurred:
i) Issue of Subscription Receipts
On August 2, 2005, the Trust issued 6,505,600 subscription receipts
("Subscription Receipts") at a price of $26.90 per Subscription Receipt each of
which entitled the holder to receive one trust unit for gross proceeds of $175
million. The net proceeds were approximately $166 million after deduction of the
underwriters' commission at 5% and estimated costs of $150,000.
ii) Issue of Convertible Unsecured Subordinated Debentures.
On August 2, 2005, the Trust issued 75,000 convertible unsecured subordinated
debentures ("Debentures") at a price of $1,000 each, for total gross proceeds of
$75 million. The net proceeds were approximately $72 million after the deduction
of the underwriters' commission at 4% and estimated costs of $150,000. Of the
total costs incurred, $3 million has been recorded in deferred charges and
$114,000 has been applied against the equity component of convertible
debentures. The Debentures have a maturity date of December 31, 2010. The
Debentures bear interest at an annual rate of 6.5% payable semi-annually on June
30 and December 31 in each year commencing on December 31, 2005. The
A - 8
HARVEST ENERGY TRUST
Notes to Consolidated Pro Forma Balance Sheet and Statements of Income
================================================================================
Debentures are redeemable by the Trust at a price of $1,050 per Debenture after
December 31, 2008 and at a price of $1,025 per Debenture after December 31, 2009
and before maturity on December 31, 2010, in each case, plus accrued and unpaid
interest thereon, if any.
iii) Debt Facility
Upon acquisition of the New Properties, the Trust initially financed the
acquisition by drawing on the credit facility. The Trust's original credit
facilities totalled $325 million but were replaced by a new credit facility
totalling $400 million in connection with the acquisition of the New Properties.
The new credit facility bears interest at variable rates based on, among other
things, the lenders' prime rates. The closing of the Subscription Receipts and
the $75 million Debentures was used to reduce outstanding balances under the
credit facility. Fees incurred in connection with the new credit facility are
estimated to be $1.5 million.
(b) ACQUISITION OF ENCANA ASSETS
The amounts included in the pro forma consolidated statement of income for the
year ended December 31, 2004 have been derived from the unaudited schedule of
revenues, royalties and operating expenses for the EnCana assets for the six
month period ended June 30, 2004 and the unaudited financial information of the
revenues, royalties and operating expenses of the EnCana assets for the two
month period ended August 31, 2004. Historical results for the period from
September 2, 2004, the date of acquisition, to December 31, 2004, are included
in the Trust's consolidated statement of income for the year ended December 31,
2004. Consideration for the EnCana Properties was $511.4 million, consisting of
the purchase price of $526 million net of interim adjustments and acquisition
costs estimated to be $14.6 million. The following is a table reconciling the
amounts within the pro forma statement of income to the New Properties Schedule
of Revenue, Royalties and Operating Expenses statement included in the Exchange
Offer Prospectus relating to the 7 7/8% Senior Notes of the Corporation due
October 15, 2011:
SIX MONTHS ENDED TWO MONTHS ENDED ENCANA PROPERTIES
JUNE 30, 2004 AUGUST 31, 2004 PRO FORMA
------------- --------------- ---------
Revenue $135,246 $52,346 $187,592
Royalties 16,800 6,395 23,195
------------- --------------- ---------
118,446 45,951 164,397
Operating expenses 24,652 9,178 33,830
- ---------------------------------------------------------------------------------------------------------
Excess of revenue of over operating expenses $93,794 $36,773 $130,567
- ---------------------------------------------------------------------------------------------------------
In accordance with the financing requirements for the purchase of the EnCana
Properties, it has been assumed for these pro forma financial statements that
the following transactions occurred on January 1, 2004 for the consolidated pro
forma income statement for the year ended December 31, 2004.
(i) Issue of Subscription Receipts
On July 15, 2004, the Trust entered into an underwriting agreement for the issue
of 12,166,666 subscription receipts at a price of $14.40 each, which entitled
the holder to receive one trust unit per subscription receipt for approximate
gross proceeds of $175.2 million. The net proceeds were $165.9
A - 9
HARVEST ENERGY TRUST
Notes to Consolidated Pro Forma Balance Sheet and Statements of Income
================================================================================
million after the deduction of the underwriters' commission at 5% and
approximately $0.5 million for other transaction costs.
(ii) Issue of Convertible Unsecured Subordinated Debentures
On July 15, 2004, the Trust entered into an underwriting agreement for the issue
of 100,000 convertible unsecured subordinated debentures ("debentures") at a
price of $1,000 each, for gross proceeds of $100 million. The net proceeds were
$95.5 million after the deduction of the underwriters' commission at 4% and
estimated costs of $0.5 million. The debentures have a maturity date of
September 30, 2009. The debentures bear interest at an annual rate of 8% payable
semi-annually on March 31 and September 30 in each year commencing on March 31,
2005. The debentures are redeemable by the Trust at a price of $1,050 per
debenture after September 30, 2007, and on or before September 30, 2008, and at
a price of $1,025 per debenture after September 30, 2008 and before maturity on
September 30, 2009, in each case, plus accrued and unpaid interest thereon, if
any.
(iii) Bank Borrowings
The cost of the EnCana Properties, less the net proceeds from the issuance of
subscription receipts and debentures, was financed through a new credit facility
arrangement. The new facilities bear interest at variable rates based on the
lenders' prime rates.
(c) PLAN OF ARRANGEMENT WITH STORM
The amounts included in the pro forma consolidated statement of income for Storm
for the year ended December 31, 2004 include amounts derived from Storm's
unaudited financial statements for the six months ended June 30, 2004.
Historical results from the Storm assets for the period from July 1, 2004
through December 31, 2004 are included in the Trust's consolidated statement of
income for the year ended December 31, 2004. In accordance with the terms of the
plan of arrangement with Storm concluded June 30, 2004, the consideration paid
consisted of 2,720,837 trust units and 600,587 exchangeable shares at an
ascribed value of $14.77 per trust unit and exchangeable share, and cash of $75
million for an aggregate consideration of approximately $192.2 million
(including assumed debt and transaction costs totalling approximately $67.3
million). The exchangeable shares are exchangeable by the holder at any time
into trust units. Application of a new accounting pronouncement EIC-151 during
the first quarter of 2005 required retroactive restatement to the December 31,
2004 statement of income resulting in an allocation of $26,000 of the loss
incurred to the non-controlling interest holders, being the holders of the
exchangeable shares.
(d) INTEREST AND AMORTIZATION OF DEFERRED FINANCING CHARGES
Interest has been adjusted to include the costs associated with the new bank
loan borrowings upon acquisition of Storm, the new bank loan and bridge loan
borrowings upon acquisition of the EnCana assets, and the initial bank loan
financing upon acquisition of the New Properties and the subsequent issue of the
convertible debentures. The balance also includes the interest on the senior
notes as if the senior notes had been issued at the beginning of the respective
period, offset with interest on bank loan and bridge loan amounts repaid with
net proceeds from the senior note issuance. Deferred finance costs associated
with the senior note and convertible debenture issuances as well as new bank
financings have been amortized over their respective periods to maturity.
A - 10
HARVEST ENERGY TRUST
Notes to Consolidated Pro Forma Balance Sheet and Statements of Income
================================================================================
The Trust adopted the amendments to CICA Handbook Section 3860, "Financial
Instruments - Disclosure and Presentation", on January 1, 2005. As a result, the
debentures issued to finance the EnCana acquisition as well as the debentures
used to finance the acquisition of the New Properties have been classified as
debt with a portion, representing the value of the conversion feature, allocated
to equity. The interest relating to the debentures is a direct charge to income
and includes a non-cash interest charge. The debt balance associated with the
convertible debentures accretes over time to the amount owing on maturity, as
such, increases in the debt balance are reflected as non-cash interest expense
in the statement of income.
(e) DEPLETION, DEPRECIATION AND ACCRETION
The pro forma adjustments for depletion, depreciation and accretion have been
determined using the full cost method of accounting based on combined proved
reserves, future development costs and production volumes and incorporation of
the cost of the properties acquired pursuant to the Storm plan of arrangement,
the purchase of the EnCana Properties and the purchase of New Properties.
(f) GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense has been adjusted to reflect the estimated
costs of the associated combined entity under the plan of arrangement with
Storm, the purchase of the EnCana Properties and the purchase of the New
Properties, respectively.
(g) TAXES
For income tax purposes, the Trust is able to, and intends to, claim a deduction
for all amounts paid or payable to unitholders, and then to allocate the
remaining income, if any, to the unitholders. With respect to the Storm
acquisition, the pro forma adjustment for future income taxes has been based on
the assumption that 50% of the incremental cash flow related to the Storm assets
would have been paid by Storm to the Trust as a royalty payment. Future tax
expense is calculated based on the adjustments at an average rate of 40%. The
EnCana Properties and the New Properties are held by trusts, and as such, there
is no adjustment required for future or corporate taxes.
(h) INCOME PER TRUST UNIT
The number of trust units included in the basic weighted average number
outstanding for the six month period ended June 30, 2005 was based on the
weighted average number of trust units actually outstanding for the period, plus
the 6,505,600 issued on August 2, 2005.
The diluted weighted average number of trust units for the six month period
ended June 30, 2005 was 49,239,554 which excluded the potentially dilutive
impact of the exchangeable shares, the convertible debentures and the unit
appreciation rights as these instruments were anti-dilutive.
The number of trust units included in the basic weighted average number
outstanding for the year ended December 31, 2004 was based on the weighted
average number of trust units actually outstanding for the period, plus a
pro-ration of the trust units issued under the terms of the Storm plan of
arrangement of 1,352,984 and a pro-ration of the trust units issued in the
purchase of the EnCana Properties of 8,210,837 and 6,505,600 units representing
the trust units to be issued in connection with the acquisition of the New
Properties.
A - 11
HARVEST ENERGY TRUST
Notes to Consolidated Pro Forma Balance Sheet and Statements of Income
================================================================================
The pro forma diluted weighted average number of trust units for the year ended
December 31, 2004 was 54,756,280 which includes trust unit appreciation rights
issued to new employees of Harvest associated with the Storm plan of arrangement
and the EnCana Properties acquisition, a pro-ration of the exchangeable shares
issued under the terms of the Storm plan of arrangement and the dilutive impact
of the convertible debentures.
(i) NON-CONTROLLING INTEREST
The adjustments to non-controlling interest income for the original consolidated
pro forma statement of income for the six months ended June 30, 2004 resulting
from the Storm plan of arrangement, and to the pro forma consolidated statement
of income for the nine months ended September 30, 2004 associated with the
acquisition of EnCana Properties were due to the Trust's retroactive application
of EIC-151 "Exchangeable Securities Issued by a Subsidiary of an Income Trust"
in the first quarter of 2005. EIC-151 requires recognition of non-controlling
interests on the balance sheet to reflect the fair value of exchangeable shares
upon issuance plus the accumulated earnings attributable to such non-controlling
interest less conversions to date. On the consolidated statement of income, the
non-controlling interest represents the share of net income attributable to the
non-controlling interest based on the Trust Units issuable for exchangeable
shares in proportion to total Trust Units issued and issuable at each period
end.
For the year ended December 31, 2004 adjustments were made to non-controlling
interest to reflect the non-controlling interest attributable to income from the
New Properties.
SCHEDULE B
FINANCIAL STATEMENTS OF THE NEW PROPERTIES
AUDITORS' REPORT
To the Managing Partner of Nexen Canada No. 1
We have audited the schedule of revenue and expenses of the properties of Nexen
Canada No. 1 (the "New Properties") for each of the years in the two year period
ended December 31, 2004. This financial information is the responsibility of the
management of Nexen Canada No. 1. Our responsibility is to express an opinion on
this financial information based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial information is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial information. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the financial
information.
In our opinion, this schedule presents fairly, in all material respects, the
revenue and expenses of the New Properties as described in Note 1 for each of
the years in the two year period ended December 31, 2004 in accordance with
Canadian generally accepted accounting principles.
Calgary, Alberta (signed) "Deloitte & Touche LLP"
February 28, 2005 Chartered Accountants
B - 2
NEW PROPERTIES
SCHEDULE OF REVENUE AND EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2004 AND 2003
AND THE SIX MONTHS ENDED JUNE 30, 2005 AND 2004
($000'S)
SIX MONTHS ENDED JUNE 30, FOR THE YEARS ENDED DECEMBER 31,
2005 2004 2004 2003
--------- --------- --------- ---------
(unaudited) (unaudited)
Revenue $ 55,026 $ 51,472 $ 105,333 $ 93,649
Royalties (13,405) (12,275) (25,683) (23,028)
Operating Expenses (9,618) (8,886) (12,795) (10,172)
--------- --------- --------- ---------
Net Operating Income $ 32,003 $ 30,311 $ 66,855 $ 60,449
========= ========= ========== =========
B - 3
NEW PROPERTIES
SCHEDULE OF REVENUE AND EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2004 AND 2003
AND THE SIX MONTHS ENDED JUNE 30, 2005 AND 2004
(Information for the six months ended June 30, 2005 and 2004 is unaudited)
1. BASIS OF PRESENTATION
This schedule has been prepared by management of Nexen Inc. (the
managing partner) and relates only to the working interests in the
properties transferred from Nexen Petroleum Canada (partnership) as at
December 31, 2004.
This schedule includes only those revenues, royalties, and operating
expenses that are directly related to the properties transferred and
does not include any expenses related to general and administrative
expenses, insurance, interest, income and capital taxes or any
provisions related to depletion, depreciation or asset retirement
obligations.
SIGNIFICANT ACCOUNTING POLICIES
(a) Revenue
Sales are recorded when title to the commodities passes to the
purchaser, at the pipeline delivery point for gas and at the
wellhead for crude oil.
(b) Royalties
Royalties are recorded at the time the product is produced and
are calculated in accordance with the applicable regulations.
(c) Operating expenses
Operating expenses include all costs related to the lifting,
gathering, processing, and delivery to a sales point of the
commodities.
SCHEDULE C
INFORMATION CONCERNING THE NEW PROPERTIES
Certain information in this Report in respect of the New Properties has
been taken from information provided by the Vendor.
DRILLING HISTORY
The following table sets forth the number of gross and net wells that
were drilled on the New Properties during the periods indicated:
SIX MONTHS ENDED YEAR ENDED
JUNE 30, 2005 DECEMBER 31, 2004
------------------- ---------------------
GROSS(1) NET(2) GROSS(1) NET(2)
-------- ------ -------- ------
Oil Wells...................... 6 6 16 16
Gas Wells...................... -- -- 1 1
Other.......................... 7 7 13 13
Dry and Abandoned(3)........... -- -- -- --
-------- ------ -------- ------
Total.......................... 13 13 30 30
======== ====== ======== ======
- ------------------
NOTES:
(1) "GROSS" wells are defined as the total number of wells in which the Trust
acquired an interest pursuant to the Acquisition.
(2) "NET" wells are defined as the aggregate of the numbers obtained by
multiplying each gross well by the percentage working interest therein
acquired by the Trust.
(3) "DRY" refers to a well that is not productive. A productive well is a well
which is capable of producing hydrocarbons in quantities considered by the
operator to be sufficient to justify the costs required to complete, equip
and produce the well.
OIL AND GAS WELLS
The following table sets forth the number and status of wells in which
the Trust acquired a material royalty or working interest effective June 30,
2005, which were producing or which the Vendor considered to be capable of
production which were acquired pursuant to the Acquisition:
PRODUCING SHUT-IN(1)
--------------------------------------- --------------------------------------
CRUDE OIL NATURAL GAS CRUDE OIL NATURAL GAS
------------------ ------------------ ------------------ ------------------
GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3)
-------- ------ -------- ------ -------- ------ -------- ------
British Columbia.......... 91 91 1 1 30 30 2 2
- ---------------------------
NOTES:
(1) "SHUT IN" wells means wells which have encountered and are capable of
producing crude oil or natural gas but which are not producing due to lack
of available transportation facilities, available markets or other reasons.
(2) "GROSS" wells are defined as the total number of wells in which the Trust
acquired an interest pursuant to the Acquisition.
(3) "NET" wells are defined as the aggregate of the numbers obtained by
multiplying each gross well by the percentage working interest therein
acquired by the Trust.
C - 2
PRINCIPAL PRODUCING PROPERTIES
The following is a description of the principal properties comprising
the New Properties on production or under development as at June 30, 2005,
except for reserves information which is as at March 31, 2005. The term "gross",
when used to describe the share of production of the New Properties, means the
aggregate of the working interest share acquired by the Trust before deduction
of royalties owned by others. Reserve amounts are stated, before deduction of
royalties, at March 31, 2005, based on forecast cost and price assumptions as
evaluated in the Sproule Report. See "Statement of Reserves Data and Other Oil
and Gas Information for the New Properties". The following information in
respect of gross and net acres of land is as at June 30, 2005 and information in
respect of production is net for the New Properties and is as at June 30, 2005
except where otherwise indicated. The reserves set forth in the principal
property description below are as presented in the Sproule Report. Such
additional reserves are set forth on a consolidated basis in the oil and natural
gas reserve tables set forth under the heading "Statement of Reserves Data and
Other Oil and Gas Information for the New Properties". All of the New Properties
proved producing reserves were on production on March 31, 2005.
HAY RIVER
The Trust acquired an average 97% working interest in approximately
77,500 gross acres (approximately 75,300 net acres) of land, of which
approximately 54,300 net acres are undeveloped and are strategically positioned
for further oil and natural gas exploitation and development. The average gross
production of the New Properties for the six months ended June 30, 2005 was
approximately 5,560 bbls/d of medium crude oil. The Trust operates 100% of and
acquired a working interest of 100% in the crude oil production from these
properties.
The Sproule Report assigned proven reserves of 15,335.0 mbbls of medium
crude oil and 6,512.0 mmcf of natural gas to these properties. In addition,
probable reserves of 3,182.6 mbbls of medium crude oil and 1,054.0 mmcf of
natural gas have been assigned to these properties.
UNDEVELOPED LANDS
The following table summarizes the undeveloped land holdings, in acres,
as at June 30, 2005 associated with the New Properties.
AVERAGE WORKING
GROSS(1) NET(2) INTEREST
-------- ------ --------
Alberta............................. 32,100 31,800 99%
British Columbia.................... 22,500 22,500 100%
-------- ------
Total............................... 54,600 54,300 99%
====== ======
- ---------------------------
NOTES:
(1) "GROSS" refers to the total acres in which the Trust acquired an interest
pursuant to the Acquisition.
(2) "NET" refers to the total acres in which the Trust acquired an interest,
multiplied by the percentage working interest therein acquired.
C - 3
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION FOR THE NEW
PROPERTIES
The statement of reserves data and other oil and gas information set
forth below (the "STATEMENT") is dated March 31, 2005 in respect of the reserves
data for the New Properties. The effective date of the Statement is March 31,
2005 and the preparation date of the Statement is March 31, 2005.
DISCLOSURE OF RESERVES DATA
The reserves data set forth below (the "RESERVES DATA") for the New
Properties are based upon an evaluation by Sproule with an effective date of
March 31, 2005 as contained in the Sproule Report. The Reserves Data summarizes
the crude oil, liquids and natural gas reserves of the New Properties and the
net present values of future net revenue for these reserves using constant
prices and costs and forecast prices and costs. The Reserves Data conforms with
the requirements of National Instrument 51-101 Standards of Disclosure for Oil
and Gas Activities ("NI 51-101") except that no estimate of future abandonment
liabilities has been made in determining the future cash flows. Additional
information not required by NI 51-101 has been presented to provide continuity
and additional information which we believe is important to the readers of this
information. Sproule was engaged to provide an evaluation of proved and proved
plus probable reserves and also proved plus probable plus possible reserves.
All of the New Properties' reserves are located in Canada and,
specifically, in the province of British Columbia.
DISCLOSURE PROVIDED HEREIN IN RESPECT OF BOES MAY BE MISLEADING,
PARTICULARLY IF USED IN ISOLATION. A BOE CONVERSION RATIO OF 6 MCF: 1 BBL IS
BASED ON AN ENERGY EQUIVALENCY CONVERSION METHOD PRIMARILY APPLICABLE AT THE
BURNER TIP AND DOES NOT REPRESENT A VALUE EQUIVALENCY AT THE WELLHEAD.
IT SHOULD NOT BE ASSUMED THAT THE ESTIMATES OF FUTURE NET REVENUES
PRESENTED IN THE TABLES BELOW REPRESENT THE FAIR MARKET VALUE OF THE RESERVES.
THERE IS NO ASSURANCE THAT THE CONSTANT PRICES AND COSTS ASSUMPTIONS AND
FORECAST PRICES AND COSTS ASSUMPTIONS WILL BE ATTAINED AND VARIANCES COULD BE
MATERIAL.
RESERVES DATA (CONSTANT PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF MARCH 31, 2005
CONSTANT PRICES AND COSTS
SOLUTION GAS MEDIUM OIL(1)
------------------- ----------------------
RESERVES CATEGORY GROSS NET GROSS NET
- ----------------- ------- ------- -------- --------
(mmcf) (mmcf) (mbbl) (mbbl)
Proved Producing..................................... 6,512 5,461 12,993.8 11,227.3
Proved Non-Producing................................. -- -- -- --
------- ------- -------- --------
Total Proved Developed............................. 6,512 5,461 12,993.8 11,227.3
Proved Undeveloped................................... -- -- 2,441.8 2,022.4
------- ------- -------- --------
Total Proved....................................... 6,512 5,461 15,435.6 13,249.7
Probable............................................. 1,144 959 3,667.9 3,077.3
------- ------- -------- --------
Total Proved + Probable............................ 7,656 6,420 19,103.5 16,327.0
======= ======= ======== ========
- ---------------------------
NOTE:
(1) The crude oil for this property has an average API of 24o (medium grade);
however, it benefits from a heavy oil royalty regime and therefore would be
classified as heavy oil according to NI 51-101.
C - 4
NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT
(%/YEAR)
RESERVES CATEGORY 0 5 10 15 20
- ----------------- ------- ------- ------- ------- -------
(M$) (M$) (M$) (M$) (M$)
Proved Producing................................. 491,731 363,150 290,954 245,426 214,110
Proved Non-Producing............................. -- -- -- -- --
------- ------- ------- ------- -------
Total Proved Developed......................... 491,731 363,150 290,954 245,426 214,110
Proved Undeveloped............................... 71,016 53,239 40,773 31,729 24,975
------- ------- ------- ------- -------
Total Proved................................... 562,747 416,389 331,727 277,155 239,085
Probable......................................... 127,337 75,256 50,414 36,406 27,544
------- ------- ------- ------- -------
Total Proved + Probable........................ 690,084 491,645 382,141 313,561 266,629
======= ======= ======= ======= =======
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF MARCH 31, 2005
CONSTANT PRICES AND COSTS
WELL
OPERATING DEVELOPMENT ABANDONMENT FUTURE NET REVENUE
RESERVES CATEGORY REVENUE ROYALTIES COSTS COSTS COSTS BEFORE INCOME TAXES
- ----------------- ------- --------- ----- ----- ----- -------------------
(M$) (M$) (M$) (M$) (M$) (M$)
Proved Reserves............... 1,014,005 141,093 252,194 57,971 -- 562,747
Proved + Probable Reserves.... 1,250,966 178,544 296,879 85,459 -- 690,084
FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF MARCH 31, 2005
CONSTANT PRICES AND COSTS
FUTURE NET REVENUE BEFORE
INCOME TAXES
RESERVES CATEGORY PRODUCTION GROUP (DISCOUNTED AT 10%/YEAR)
- ----------------- ---------------- -------------------------
(M$)
Proved Reserves Medium Crude Oil
(including solution gas and other by-products).... 331,727
Proved Plus Probable Reserves Medium Crude Oil
(including solution gas and other by-products).... 382,141
C - 5
RESERVES DATA (FORECAST PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF MARCH 31, 2005
FORECAST PRICES AND COSTS
SOLUTION GAS MEDIUM OIL(1)
------------------ --------------------
RESERVES CATEGORY GROSS NET GROSS NET
- ----------------- ----- --- ----- ---
(mmcf) (mmcf) (mbbl) (mbbl)
Proved Producing........................................ 6,512 5,464 12,893.2 11,353.5
Proved Non-Producing.................................... -- -- -- --
----- ----- -------- --------
Total Proved Developed................................ 6,512 5,464 12,893.2 11,353.5
Proved Undeveloped...................................... -- -- 2,441.8 2,081.6
----- ----- -------- --------
Total Proved.......................................... 6,512 5,464 15,335.0 13,435.1
Probable................................................ 1,054 882 3,182.6 2,707.7
----- ----- -------- --------
Total Proved + Probable................................. 7,566 6,346 18,517.6 16,142.8
===== ===== ======== ========
- ---------------------------
NOTE:
(1) The crude oil for this property has an average API of 24(0) (medium grade);
however, it benefits from a heavy oil royalty regime and therefore would be
classified as heavy oil according to NI 51-101.
NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT
(%/YEAR)
RESERVES CATEGORY 0 5 10 15 20
- ----------------- ------- ------- ------- ------- -------
(M$) (M$) (M$) (M$) (M$)
Proved Producing.................................. 186,249 153,444 133,562 119,917 109,722
Proved Non-Producing.............................. -- -- -- -- --
------- ------- ------- ------- -------
Total Proved Developed.......................... 186,249 153,444 133,562 119,917 109,722
Proved Undeveloped................................ 18,503 12,089 7,497 4,122 1,586
------- ------- ------- ------- -------
Total Proved.................................... 204,752 165,533 141,059 124,039 111,308
Probable.......................................... 50,721 29,484 18,554 12,159 8,057
------- ------- ------- ------- -------
Total Proved + Probable........................... 255,473 195,017 159,613 136,198 119,365
======= ======= ======= ======= =======
C - 6
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF MARCH 31, 2005
FORECAST PRICES AND COSTS
WELL FUTURE NET
OPERATING DEVELOPMENT ABANDONMENT REVENUE BEFORE
RESERVES CATEGORY REVENUE ROYALTIES COSTS COSTS COSTS INCOME TAXES
- ----------------- ------- --------- ----- ----- ----- ------------
(M$) (M$) (M$) (M$) (M$) (M$)
Proved Reserves................. 648,566 80,341 298,757 64,716 -- 204,752
Proved + Probable Reserves...... 781,380 99,388 337,056 89,463 -- 255,473
FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF MARCH 31, 2005
FORECAST PRICES AND COSTS
FUTURE NET REVENUE
BEFORE INCOME TAXES
RESERVES CATEGORY PRODUCTION GROUP (DISCOUNTED AT 10%/YEAR)
- ----------------- ---------------- ------------------------
(M$)
Proved Reserves Medium Crude Oil (including solution gas and
other by-products)............................... 141,059
Proved + Probable Reserves Medium Crude Oil (including solution gas and
other by-products)............................... 159,613
DEFINITIONS AND OTHER NOTES
In the tables set forth above and elsewhere in this Report except where
indicated otherwise the following definitions and other notes are applicable:
(1) "GROSS" means:
(a) in relation to the interest in production and reserves of the
New Properties, its "gross reserves", which is the interest
acquired by the Trust (operating and non-operating) before
deduction of royalties and without including any royalty
interest of the New Properties;
(b) in relation to wells, the total number of wells in which the
Trust acquired an interest; and
(c) in relation to properties, the total area of properties in
which the Trust acquired an interest.
(2) "NET" means:
C - 7
(a) in relation to the interest in production and reserves of the
New Properties, its "net reserves", which is the interest
acquired by the Trust (operating and non-operating) after
deduction of royalties obligations, plus the royalty interest
in production or reserves;
(b) in relation to wells, the number of wells obtained by
aggregating the working interest in each of its gross wells;
and
(c) in relation to interest in the New Properties, the total area
in which the Trust acquired an interest multiplied by the
working interest acquired.
(3) "EXPLORATION WELL" means a well that is not a development well, a
service well or a stratigraphic test well.
(4) "DEVELOPMENT COSTS" means costs incurred to obtain access to reserves
and to provide facilities for extracting, treating, gathering and
storing the oil and gas from reserves. More specifically, development
costs, including applicable operating costs of support equipment and
facilities and other costs of development activities, are costs
incurred to:
(a) gain access to and prepare well locations for drilling,
including surveying well locations for the purpose of
determining specific development drilling sites, clearing
ground draining, road building, and relocating public roads,
gas lines and power lines, pumping equipment and wellhead
assembly;
(b) drill and equip development wells, development type
stratigraphic test wells and service wells, including the
costs of platforms and of well equipment such as casing,
tubing, pumping equipment and wellhead assembly;
(c) acquire, construct and install production facilities such as
flow lines, separators, treaters, heaters, manifolds,
measuring devices and production storage tanks, natural gas
cycling and processing plants, and central utility and waste
disposal systems; and
(d) provide improved recovery systems.
(5) "DEVELOPMENT WELL" means a well drilled inside the established limits
of an oil and gas reservoir, or in close proximity to the edge of the
reservoir, to the depth of a stratigraphic horizon known to be
productive.
(6) "EXPLORATION COSTS" means costs incurred in identifying areas that may
warrant examination and in examining specific areas that are considered
to have prospects that may contain oil and gas reserves, including
costs of drilling exploratory wells and exploratory type stratigraphic
test wells. Exploration costs may be incurred both before acquiring the
related property and after acquiring the property. Exploration costs,
which include applicable operating costs of support equipment and
facilities and other costs of exploration activities, are:
(a) costs of topographical, geochemical, geological and
geophysical studies, rights of access to properties to conduct
those studies, and salaries and other expenses of geologists,
geophysical crews and others conducting those studies;
C - 8
(b) costs of carrying and retaining unproved properties, such as
delay rentals, taxes (other than income and capital taxes) on
properties, legal costs for title defence, and the maintenance
of land and lease records;
(c) dry hole contributions and bottom hole contributions;
(d) costs of drilling and equipping exploratory wells; and
(e) costs of drilling exploratory type stratigraphic test wells.
(7) "SERVICE WELL" means a well drilled or completed for the purpose of
supporting production in an existing field. Wells in this class are
drilled for the following specific purposes: gas injection (natural
gas, propane, butane or flue gas), water injection, steam injection,
air injection, salt water disposal, water supply for injection,
observation or injection for combustion.
(8) Definitions used for reserve categories are as follows:
The following definitions apply to both estimates of individual
reserves entities and the aggregate of reserves for multiple entities.
RESERVE CATEGORIES
Reserves are estimated remaining quantities of oil and natural gas and
related substances anticipated to be recoverable from known
accumulations, from a given date forward, based on
(a) analysis of drilling, geological, geophysical and engineering
data;
(b) the use of established technology; and
(c) specified economic conditions (see the discussion of "Economic
Assumptions" below).
Reserves are classified according to the degree of certainty associated
with the estimates.
(a) Proved reserves are those reserves that can be estimated with
a high degree of certainty to be recoverable. It is likely
that the actual remaining quantities recovered will exceed the
estimated proved reserves.
(b) Probable reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally
likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus
probable reserves.
"Economic Assumptions" will be the prices and costs used in the
estimate, namely:
(a) constant prices and costs as at the preparation date of the
evaluation (March 31, 2005); and
(b) forecast prices and costs.
C - 9
DEVELOPMENT AND PRODUCTION STATUS
Each of the reserve categories (proved and probable) may be divided
into developed and undeveloped categories:
(a) Developed reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low
expenditure (for example, when compared to the cost of
drilling a well) to put the reserves on production. The
developed category may be subdivided into producing and
non-producing.
(b) Developed producing reserves are those reserves that are
expected to be recovered from completion intervals open at the
time of the estimate. These reserves may be currently
producing or, if shut-in, they must have previously been on
production, and the date of resumption of production must be
known with reasonable certainty.
(c) Developed non-producing reserves are those reserves that
either have not been on production, or have previously been on
production, but are shut-in, and the date of resumption of
production is unknown.
(d) Undeveloped reserves are those reserves expected to be
recovered from known accumulations where a significant
expenditure (for example, when compared to the cost of
drilling a well) is required to render them capable of
production. They must fully meet the requirements of the
reserves classification (proved, probable) to which they are
assigned.
In multi-well pools it may be appropriate to allocate total pool
reserves between the developed and undeveloped categories or to
subdivide the developed reserves for the pool between developed
producing and developed non-producing. This allocation should be based
on the estimator's assessment as to the reserves that will be recovered
from specific wells, facilities and completion intervals in the pool
and their respective development and production status.
LEVELS OF CERTAINTY FOR REPORTED RESERVES
The qualitative certainty levels referred to in the definitions above
are applicable to individual reserve entities (which refers to the
lowest level at which reserves calculations are performed) and to
reported reserves (which refers to the highest level sum of individual
entity estimates for which reserves are presented). Reported reserves
should target the following levels of certainty under a specific set of
economic conditions:
(a) at least a 90 percent probability the estimated proved
reserves will be recovered; and
(b) at least a 50 percent probability that the sum of the
estimated proved plus probable reserves will be recovered.
A qualitative measure of the certainty levels pertaining to estimates
prepared for the various reserves categories is desirable to provide a
clearer understanding of the associated risks and uncertainties.
However, the majority of reserves estimates will be prepared using
deterministic methods that do not provide a mathematically derived
quantitative measure of probability. In
C - 10
principle, there should be no difference between estimates prepared
using probabilistic or deterministic methods.
(9) Forecast prices and costs
Future prices and costs that are:
(a) generally acceptable as being a reasonable outlook of the
future; and
(b) if and only to the extent that, there are fixed or presently
determinable future prices or costs to which the working
interest owner is legally bound by a contractual or other
obligation to supply a physical product, including those for
an extension period of a contract that is likely to be
extended, those prices or costs rather than the prices and
costs referred to in paragraph (a).
The forecast summary table under "Pricing Assumptions" identifies
benchmark reference pricing that apply to the New Properties.
(10) Constant prices and costs
Prices and costs used in an estimate that are:
(a) the Corporation's prices and costs as at the effective date of
the estimation, held constant throughout the estimated lives
of the properties to which the estimate applies; and
(b) if, and only to the extent that, there are fixed or presently
determinable future prices or costs to which the working
interest owner is legally bound by a contractual or other
obligation to supply a physical product, including those for
an extension period of a contract that is likely to be
extended, those prices or costs rather than the prices and
costs referred to in paragraph (a).
(c) For the purposes of paragraph (a), the Corporation's prices
are the posted prices for oil and the spot price for gas,
after historical adjustments for transportation, gravity and
other factors.
(11) Estimated future abandonment and reclamation costs related to a
property have not been taken into account by Sproule in determining
reserves that should be attributed to a property and in determining the
aggregate future net revenue therefrom. A reasonable estimate of future
well abandonment costs was not deducted.
(12) Numbers may not add due to rounding.
(13) Both the constant and forecast price and cost assumptions assumed the
continuance of current laws and regulations.
(14) The extended character of all factual data supplied to Sproule were
accepted by Sproule as represented. No field inspection was conducted.
(15) The estimates of future net revenue presented in the tables above do
not represent fair market value.
C - 11
PRICING ASSUMPTIONS
The following sets out the benchmark reference prices, as at March 31,
2005, reflected in the Reserves Data. These forecast price assumptions were
provided by the Vendor. The constant prices as of March 31, 2005 were supplied
by Sproule.
SUMMARY OF PRICING ASSUMPTIONS
AS OF MARCH 31, 2005
CONSTANT PRICES AND COSTS
OIL NATURAL GAS
------------------------------ --------------
WTI CUSHING EDMONTON PAR
YEAR OKLAHOMA PRICE 40(0) API AECO GAS PRICE EXCHANGE RATE(1)
- ---- -------- --------------- -------------- ----------------
($US/bbl) ($Cdn/bbl) ($Cdn/mcf) ($US/$Cdn)
March 31, 2005 and thereafter............. 55.41 67.38 7.56 0.827
- ---------------------------
NOTE:
(1) The exchange rate used to generate the benchmark reference prices in this
table.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
AS OF MARCH 31, 2005
FORECAST PRICES AND COSTS
OIL NATURAL GAS
-------------------------------- --------------
WTI CUSHING EDMONTON PAR INFLATION
YEAR OKLAHOMA PRICE 40(0) API AECO GAS PRICE RATES(1) EXCHANGE RATE(2)
- ---- -------- --------------- -------------- -------- ----------------
($US/bbl) ($Cdn/bbl) ($Cdn/GJ) (%/Year) ($US/$Cdn)
Forecast
2005......................... 43.07 50.969 6.712 2.15 0.825
2006......................... 40.48 47.838 6.580 2.25 0.825
2007......................... 37.37 44.016 6.373 2.25 0.825
2008......................... 34.23 40.196 6.018 2.25 0.825
2009......................... 33.17 38.898 5.781 1.75 0.825
2010......................... 33.31 39.030 5.768 1.75 0.825
2011......................... 33.90 39.715 5.924 1.75 0.825
2012......................... 34.50 40.456 6.027 1.75 0.825
Thereafter................... Escalated at Escalated at Escalated at 0.75 0.825
2%/year 2%/year 2%/year
- -------------------
NOTES:
(1) Inflation rates for forecasting prices and costs.
(2) Exchange rates used to generate the benchmark reference prices in this
table.
Weighted average historical prices realized in respect of the New
Properties for the year ended December 31, 2004 were $46.33/bbl for medium oil.
No natural gas was sold during this period.
C - 12
ADDITIONAL INFORMATION RELATING TO RESERVES DATA
The recovery of the Proven Undeveloped and Probable reserves of the New
Properties will occur primarily through development drilling, drilling injection
wells and improved waterflood recovery. The recovery of these reserves will be
dependent on these future wells exhibiting similar performance characteristics
to the existing wells drilled into the pool.
FUTURE DEVELOPMENT COSTS
The following table sets forth development costs deducted in the
estimation of the future net revenue in respect of the New Properties
attributable to the reserve categories noted below. All amounts are stated in
thousands of dollars.
FORECAST PRICES AND COSTS CONSTANT PRICES AND COSTS
--------------------------------------- -------------------------------------
PROVED PLUS PROVED PLUS
PROVED RESERVES PROBABLE RESERVES PROVED RESERVES PROBABLE RESERVES
--------------- ----------------- --------------- -----------------
YEAR 0% 10% 0% 10% 0% 10% 0% 10%
- ---- -- --- -- --- -- --- -- ---
2005.................................. 812 809 812 809 812 809 812 809
2006.................................. 25,282 23,317 39,472 36,405 24,750 22,860 38,641 35,691
2007.................................. 8,737 7,308 17,667 14,777 8,365 7,024 16,915 14,203
Thereafter............................ 29,885 9,353 31,512 1,039 24,044 7,698 29,091 7,886
------ ----- ------ ----- ------ ----- ------ -----
Total................................. 64,716 40,787 89,463 53,030 57,971 38,391 85,459 58,589
====== ====== ====== ====== ====== ====== ====== ======
These future development costs will be financed with undrawn capacity
under the Trust's credit facilities.
CAPITAL EXPENDITURES
The following tables summarizes capital expenditures made by the Vendor
on acquisitions, development and exploration drilling and production facilities
and other equipment in respect of the New Properties for the periods indicated.
YEAR ENDED
DECEMBER 31,(1)
SIX MONTHS ENDED ------------------------------
JUNE 30, 2005(1) 2004 2003
---------------- ---- ----
(unaudited) (unaudited) (unaudited)
($000's) ($000's) ($000's)
Property acquisitions(2).................. -- -- --
Development expenditures(3)............... 15,433 34,457 51,784
Production equipment(4)................... -- -- --
Exploration expenditures(5)............... 39 359 375
------ ------ ------
TOTAL..................................... 15,472 34,816 52,159
====== ====== ======
- ---------------------------
NOTES:
(1) Based on information provided to the Corporation by the Vendor.
(2) Property acquisitions include production lease/royalty purchases and
property exchanges of lease and royalty interests.
C - 13
(3) Development expenditures include development drilling and miscellaneous
intangible expenditures.
(4) Production equipment includes production and facility equipment and
miscellaneous tangible assets.
(5) Exploration expenditures include exploration drilling, geological and
geophysical costs and miscellaneous intangible expenditures.
PRODUCTION HISTORY AND PRICES RECEIVED
The following table sets forth certain information in respect of
production, product prices received, royalties, production expenses and netbacks
received by the Vendor in respect of the New Properties for the period
indicated.
OIL OIL PRICE ROYALTY PRODUCTION NETBACK
PRODUCTION(1) RECEIVED(2) EXPENSE EXPENSES(3) RECEIVED
------------- ----------- ------- ----------- --------
(bbls/d) ($/bbl) ($/bbl) ($/bbl) ($/bbl)
2005
Second Quarter............... 5,849 55.67 14.01 6.02 35.64
First Quarter................ 5,267 53.57 12.55 13.53 27.49
2004
First Quarter................ 5,791 39.14 9.09 10.00 20.04
Second Quarter 7,508 44.96 11.28 5.53 28.15
Third Quarter................ 5,998 50.08 12.37 4.42 33.29
Fourth Quarter............... 5,551 51.30 12.54 4.56 34.20
2003
First Quarter................ 4,705 48.08 12.48 12.24 23.36
Second Quarter............... 9,812 31.14 7.69 1.53 21.92
Third Quarter................ 7,152 37.13 8.93 3.25 24.95
Fourth Quarter............... 4,475 51.14 11.70 4.89 34.55
- ---------------------
NOTES:
(1) Before deduction of royalties.
(2) Product prices are net of costs to transport the product to market.
(3) This figure includes all field operating expenses.
C - 14
EFFECT OF THE ACQUISITION ON THE TRUST
The following table sets out certain operational information for the
Trust and the New Properties and certain pro forma combined operational
information after giving effect to the Acquisition.
SELECTED PRO FORMA COMBINED OPERATIONAL INFORMATION
PRO FORMA
TRUST NEW PROPERTIES COMBINED
----- -------------- --------
AVERAGE DAILY PRODUCTION(1)
(before royalties, for the 6 months ended June 30, 2005)
Crude oil and NGL (bbls/d)......................................... 30,256 5,560 35,816
Natural gas (mcf/d)................................................ 27,990 -- 27,990
Oil equivalent (boe/d)............................................. 34,921 5,560 40,481
AVERAGE DAILY PRODUCTION(1)
(before royalties, for the year ended December 31, 2004)
Crude oil and NGL (bbls/d)......................................... 21,201 6,210 27,411
Natural gas (mcf/d)................................................ 10,903 -- 10,903
Oil equivalent (boe/d)............................................. 23,019 6,210 29,229
PROVED RESERVES(2)(3)
(before royalties)
Crude oil and NGL (mbbls).......................................... 64,432.8 15,435.6 79,868.4
Natural gas (mmcf)................................................. 64,497.9 6,512.0 71,009.9
Oil equivalent (mboe).............................................. 75,182.5 16,520.9 91,703.4
PROVED PLUS PROBABLE RESERVES(2)(3)
(before royalties)
Crude oil and NGL (mbbls).......................................... 88,098.2 19,103.5 107,201.7
Natural gas (mmcf)................................................. 83,010.2 7,656.0 90,666.2
Oil equivalent (mboe).............................................. 101,933.2 20,379.5 122,312.7
- --------------------
NOTES:
(1) Average daily production for the Trust for the year ended December 31, 2004
includes production from the Storm acquisition as well as the acquisition
of the EnCana Properties from the date of closing of the acquisitions (each
as described in Note 1 to the unaudited pro forma consolidated financial
statements of the Trust included in Schedule A to this Report).
(2) New Properties reserve information is as at March 31, 2005, based on the
Sproule Report and constant price and cost assumptions.
(3) The Trust reserve information is as of December 31, 2004, based on the
Trust's reserve report and constant price and cost assumptions.
SELECTED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION
Certain selected pro forma consolidated financial information is set
forth in the following tables. Such information should be read in conjunction
with the unaudited pro forma consolidated financial statements of the Trust
after giving effect to the Acquisition as at and for the six months ended June
30, 2005 and the year ended December 31, 2004 included in Schedule A to this
Report.
C - 15
The pro forma adjustments are based upon the assumptions described in
the notes to the unaudited pro forma consolidated financial statements. The pro
forma consolidated financial statements are presented for illustrative purposes
only and are not necessarily indicative of the operating or financial results
that would have occurred had the Acquisition actually occurred at the times
contemplated by the notes to the unaudited pro forma consolidated financial
statements or of the results expected in future periods.
AS AT AND FOR THE SIX MONTHS ENDED
JUNE 30, 2005
-------------------------------------------
NEW PRO FORMA
TRUST(4) PROPERTIES(7) CONSOLIDATED(8)
-------- ------------- ---------------
(stated in thousands
of dollars, except unit amounts)
Revenue - net(1)................................................... 230,194 41,621 271,815
Net income (loss).................................................. (23,554) 12,836 (8,520)
Funds flow from operations before changes in working capital and
settlement of asset retirement obligations(2).................... 109,904 26,352 138,990
Total Assets....................................................... 1,117,792 217,600 1,338,428
Net debt (including working capital)(3)............................ 436,643 213,500 484,338
Equity............................................................. 347,685 -- 516,526
Units outstanding (000s)(9)........................................ 43,772 N/A 50,278
FOR THE YEAR ENDED DECEMBER 31, 2004
----------------------------------------------------------------------
STORM ENCANA NEW PRO FORMA
TRUST(4) PROPERTIES(5) PROPERTIES(6) PROPERTIES(7) CONSOLIDATED(8)
-------- ------------- ------------- ------------- ---------------
(stated in thousands of dollars)
Revenue - net(1)....................... 277,095 28,504 164,397 79,650 549,646
Net income (loss)...................... 11,241 (1,302) 31,218 26,887 74,800
Funds flow from operations before
changes in working capital and
settlement of asset retirement
obligations(2)....................... 123,710 14,340 109,219 53,015 308,249
- -------------------------
NOTES:
(1) Revenue - net consists of gross revenue net of applicable royalties.
(2) Funds flow from operations before changes in working capital and settlement
of asset retirement obligations is before changes in non-cash working
capital. As such, it is not a measure recognized by Canadian generally
accepted accounting principles ("GAAP") and does not have a standardized
meaning prescribed by GAAP. Therefore, funds flow from operations before
changes in working capital and settlement of asset retirement obligations
of the Trust may not be comparable to similar measures presented by other
issuers, and subscribers are cautioned that it should not be construed as
an alternative to net earnings, cash flow from operating activities or
other measures of financial performance calculated in accordance with GAAP.
For the Trust's six months ended June 30, 2005 and year ended December 31,
2004, funds flow from operations before changes in working capital and
settlement of asset retirement obligations is reconciled to its closest
GAAP measure of cash flow from operating activities as follows:
C - 16
SIX MONTHS ENDED YEAR ENDED
JUNE 30, 2005 DECEMBER 31, 2004
------------- -----------------
Funds flow from operations before changes in working
capital and settlement of asset retirement obligations 109,904 123,710
Changes in non-cash working capital................... (55,677) (11,103)
Settlement of asset retirement obligations............ (1,164) (929)
------- -------
Cash flow from operating activities................... 53,063 111,678
======= =======
(3) Net debt is bank debt, senior notes, equity bridge notes, convertible
debentures and any working capital deficit excluding the current portion of
derivative contracts, the current portion of future tax and the accounting
liability related to the Trust's unit incentive plan. For the New
Properties the net debt includes the increase in the new credit facility
and the associated financing fees.
(4) The Trust financial information for the year ended December 31, 2004 was
obtained from the Trust's restated consolidated financial statements for
the year ended December 31, 2004 and for the six months ended June 30, 2005
was obtained from the Trust's unaudited consolidated financial statements
for the six months ended June 30, 2005.
(5) The Storm Properties financial information for the year ended December 31,
2004 was derived from the Storm's unaudited financial statements for the
six months ended June 30, 2004, and reflects the results from the
pre-acquisition period.
(6) The EnCana Properties financial information for the year ended December 31,
2004 was derived from the unaudited statement of revenue and expenses for
the six months ended June 30, 2004 included in the short form prospectus of
the Corporation dated January 10, 2005 and the unaudited interim period
results to the date of closing.
(7) The New Properties financial information for the year ended December 31,
2004 was obtained from the audited schedules of revenues, royalties and
operating expenses for the New Properties for the year ended December 31,
2004 set forth herein and for the six months ended June 30, 2005 was
obtained from the unaudited schedules of revenues, royalties and operating
expenses for the New Properties for the six months ended June 30, 2005 set
forth herein, and reflects the pro forma adjustments as noted in the Pro
Forma Consolidated Financial Statements set forth herein. These amounts do
not reflect adjustments related to the August 2, 2005 offering as reflected
in the respective pro forma financial statements. These are reflected in
the pro forma consolidated column in each of the tables above. The $26
million deposit paid by the Trust for the New Properties is included in the
Trust's total assets at June 30, 2005.
(8) See the notes to the unaudited pro forma consolidated financial statements
set forth herein for assumptions and adjustments. The unaudited pro forma
consolidated financial statements may not be indicative of results that
actually would have occurred if the events reflected herein had been in
effect on the dates indicated or of the results expected in future periods.
(9) Pro Forma Units outstanding includes Units issued upon conversion of
6,505,600 Subscription Receipts as described in Note 2(a) to the unaudited
pro forma consolidated financial statements of the Trust in Schedule A to
this Business Acquisition Report.