/FIRST AND FINAL ADD - TO300 - PrimeWest Energy Trust Earnings/
Income and Capital Taxes Three Months Ended Six Months Ended
-------------------------------------------------- June 30, Mar 31,
June 30, June 30, June 30, ($ millions) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Income and capital taxes $ 0.5 $ 0.3 $ 1.5 $ 0.8 $ 2.7 Future
income taxes recovery (3.4) (18.2) (52.0) (21.6) (62.4)
-------------------------------------------------------------------------
Total: $ (2.9) $ (17.9) $ (50.5) $ (20.8) $ (59.7)
-------------------------------------------------------------------------
Cash taxes paid $ 1.3 $ 1.0 $ 0.8 $ 2.3 $ 0.8
-------------------------------------------------------------------------
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The Alberta Government enacted a tax rate reduction of 1% in the
first quarter of 2004, reducing the rate from 12.5% to 11.5%
effective April 1, 2004. This resulted in an additional tax
recovery during the first quarter of approximately $9 million.
During 2003, the Canadian Government enacted Federal income tax
changes for the oil and gas resource sector. The Federal income tax
changes effectively reduced the statutory tax rates for current and
future periods. Specifically, the 100% deductibility of the
resource allowance will be completely phased out by the year 2007.
During the same time frame, Crown charges will become 100%
deductible and resource tax rates will decline from the current 27%
to 21%. The reduction in statutory tax rates resulted in the large
income tax recovery in the second quarter of 2003. Cash taxes paid
include tax installments for current and prior years and payments
for taxes owing upon the filing of year end tax returns. Cash taxes
paid in the six months ending June 30, 2004 include $1.3 million
relating to prior years. Income and capital tax expense includes
the estimate of the current year's taxes and any adjustments
resulting from prior year tax assessments. The six months ended
June 30, 2004 include a recovery of $0.4 million related to prior
years. Net Income Three Months Ended Six Months Ended
-------------------------------------------------- June 30, Mar 31,
June 30, June 30, June 30, ($ millions) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Net income $ 22.4 $ 20.1 $ 61.7 $ 42.6 $ 83.8
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Cash flow from operations, as opposed to net income, is the primary
measure of performance for an energy trust. The generation of cash
flow is critical for an energy trust to continue paying its
distributions to unitholders. Conversely, net income is an
accounting measure impacted by both cash and non-cash items. The
largest non-cash items impacting PrimeWest's net income are
DD&A, future taxes and non-cash G&A. Net income for the
second quarter of 2004 was impacted by lower non-cash general and
administrative expense and a lower loss on derivatives offset by a
reduced future tax recovery compared to the first quarter of 2004.
Future income tax recoveries and foreign exchange gains contributed
approximately $52.0 million and $5.6 million respectively, to net
income in the second quarter of 2003. Net income for the six months
ended June 30, 2004 is lower than the same period in 2003 due to
lower net revenues and reduced future income tax recovery offset by
lower DD&A. Liquidity & Capital Resources Long Term Debt As
at --------------------------------------------- ($ millions) June
30, 2004 Mar 31, 2004 June 30, 2003
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Long-term debt $ 179.7 $ 299.9 $ 298.4 Deficit/(working capital)
(10.5) 5.8 (12.0)
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Net debt $ 169.2 $ 305.7 $ 286.4 Market value of Trust Units and
Exchangeable Shares outstanding(1) $ 1,321.6 1,355.7 1,151.7
-------------------------------------------------------------------------
Total capitalization $ 1,490.8 $ 1,661.4 $ 1,438.1
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Net debt as a % of total capitalization 11.3% 18.4% 19.9%
-------------------------------------------------------------------------
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(1) Based on June 30, 2004 Trust Unit closing price of $23.25 and
exchange ratio of 0.47310:1 Long term debt is comprised of bank
credit facilities and senior secured notes of $13.0 million and
$166.7 million, respectively. PrimeWest had a borrowing base of
$400 million at June 30, 2004, as established by the lenders. The
bank credit facilities consist of a revolving term loan of $212.5
million, an operating facility of $25 million, and the balance of
$162.5 million of senior secured notes. PrimeWest's second quarter
2004 net debt totaled $169.2 million, 41% lower than the same
period in 2003 and 45% lower than the previous quarter. The year
over year and quarter over quarter decrease is primarily due to the
equity offering proceeds which were used to reduce indebtedness
during the quarter. Being in a cyclical business, it is important
that PrimeWest maintain financial flexibility to ensure we can
operate without any restrictions regardless of where commodities
are in the price cycle. PrimeWest's objective is to have
conservative debt levels. Our internal targets are to keep debt at
2 times or less than our annual cash flow and less than 25% of
total capitalization. For the second quarter of 2004, PrimeWest's
debt to annualized cash flow is approximately 0.7 times, and 11.3%
of our total capitalization. In 2003, PrimeWest expanded its debt
financing strategy by undertaking a U.S. private placement and thus
reducing its total dependence on bank financing. In addition,
PrimeWest's lower payout ratio of 72% for the second quarter 2004
versus 92% for the second quarter 2003 enabled the Trust to use
internally generated cash to invest in development opportunities
and pay down bank debt. Unitholders' Equity At the end of the
second quarter 2004, the Trust had 56,218,322 Trust Units
outstanding, compared to 44,172,254 Trust Units outstanding at the
end of the second quarter 2003. In addition, PrimeWest had
1,320,297 (2003 - 4,435,216) Exchangeable Shares outstanding which
are exchangeable into a total of 624,629 (2003 - 1,821,543) Trust
Units using the June 15, 2004 exchange ratio of 0.47310:1 (2003 -
0.41070:1). For Canadian resident unitholders, PrimeWest offers a
Distribution Reinvestment Plan (DRIP), and components of it include
the Optional Trust Unit Purchase Plan (OTUPP) and the Premium
Distribution Plan (PREP). The DRIP gives Canadian unitholders the
chance to reinvest their monthly distributions at a 5% discount to
the volume weighted average market price, while the OTUPP gives
Canadian unitholders an opportunity to purchase additional Trust
Units directly from PrimeWest at the same 5% discount to the volume
weighted average market price. The PREP allows eligible Canadian
unitholders to elect to receive a premium cash distribution of up
to 102% of the cash that the unitholder would otherwise have
received on the distribution date, subject to proration in certain
events. The DRIP and PREP components are mutually exclusive.
Participation in the OTUPP requires enrollment in either the DRIP
or PREP. For further details on these plans or to obtain the
enrolment forms, please contact PrimeWest's Plan Agent,
Computershare Trust Company of Canada at 1-800-564-6253, or visit
PrimeWest's website at http://www.primewestenergy.com/. These plan
components benefit unitholders by offering alternatives to maximize
their investment in PrimeWest while providing the Trust with an
inexpensive method to raise additional capital. Proceeds from these
plans are used for debt reduction of PrimeWest's credit facility
and to help fund ongoing capital development programs. Exchangeable
Shares Exchangeable Shares were issued in connection with both the
Venator Petroleum Company Ltd. acquisition in April 2000 and the
Cypress Energy Inc. acquisition in March 2001. These shares were
issued to provide a tax deferred rollover of the adjusted cost base
from the shares being exchanged to the Exchangeable Shares of
PrimeWest. A tax deferral is not permitted by Canadian tax law when
shares are exchanged for Trust Units. The Exchangeable Shares do
not receive cash distributions. In lieu of receiving cash
distributions, the number of Trust Units that the exchangeable
shareholder will receive upon exchange increases each month based
on the distribution amount divided by the market price of the Trust
Units on the 15th day of each month. At June 30, 2004, there were
1,320,297 Exchangeable Shares outstanding. The exchange ratio on
these shares was 0.47310:1 Trust Units for each exchangeable share
as at the end of the second quarter. For purposes of calculating
basic per Trust Unit amounts, these Exchangeable Shares have been
assumed to be exchanged into Trust Units at the current exchange
ratio. Cash Distributions Cash distributions to unitholders are at
the discretion of the Board of Directors and can fluctuate
depending on the cash flow generated from operations. As discussed
previously, the cash flow available for distribution is dependent
upon many factors including commodity prices, production levels,
debt levels, capital spending requirements, and factors in the
overall industry environment. In order to increase PrimeWest's
financial flexibility, the Board of Directors maintains a longer
term target distribution payout ratio of approximately 70-90% of
cash flow from operations. In the second quarter of 2004, cash
distributions totaled $42.0 million, or $0.75 per Trust Unit
representing a payout ratio of 72%, compared to $52.8 million, or
$1.20 per Trust Unit (92% payout ratio) for the same period in
2003. In the first quarter of 2004 cash distributions totaled $41.1
million, or $0.82 per Trust Unit representing a payout ratio of
approximately 70% in that quarter. Distribution payments to U.S.
unitholders are subject to 15% Canadian withholding tax, which is
deducted from the distribution amount prior to deposit into
accounts. For Trust Units held in tax sheltered accounts,
withholding tax should not apply. Contractual Obligations PrimeWest
enters into many contract obligations as part of conducting
day-to-day business. Material contract obligations that PrimeWest
has currently in place are lease rental commitments that run from
2004 through 2009 and require annual payments after deducting
sub-lease income of $1.2 million in 2004, $1.1 million in 2005 and
2006, and $2.4 million in 2007 through 2009, the remaining term of
the lease. In addition, PrimeWest also has a pipeline
transportation commitment that runs to October 31, 2007 and has
minimum annual payment requirements of $U.S. 2.1 million. As part
of PrimeWest's internalization transaction (see Note 11 in the
Consolidated Financial Statements of the 2003 Annual Report),
PrimeWest agreed to pay $3.5 million in Exchangeable Shares
pursuant to a special employee retention plan. One quarter of the
Exchangeable Shares will be issuable to the senior managers of
PrimeWest on each of the second, third, fourth and fifth
anniversary of transaction closing, November 6, 2002. As at June
30, 2004 $0.7 million has been accrued in non-cash general and
administrative expenses related to the special employee retention
plan. As at June 30, 2004 Payments due by period ($ millions)
-------------------------------------------------------------------------
Less than 1-3 4-5 More than Total 1 year years years 5 years
----------------------------------------------- Long-term debt
obligations $ 179.7 $ 13.0 $ 41.7 $ 83.4 $ 41.6 Lease rental
obligations 5.1 0.9 3.4 0.8 - Pipeline transportation obligations
8.9 2.7 5.4 0.8 - Derivative liabilities 15.6 14.3 1.3 - -
-------------------------------------------------------------------------
Total contractual obligations $209.3 $ 30.9 $ 51.8 $ 85.0 $ 41.6
--------------------------------------------------------------------------
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Critical Accounting Estimates PrimeWest's financial statements have
been prepared in accordance with generally accepted accounting
principles. Certain accounting policies require that management
make appropriate decisions with respect to the formulation of
estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses. The following
discussion reviews such accounting policies and is included in
Management's Discussion and Analysis to aid the reader in assessing
the critical accounting policies and practices of the Trust and the
likelihood of materially different results being reported.
PrimeWest's management reviews its estimates regularly, but new
information and changed circumstances may result in actual results
or changes to estimated amounts that differ materially from current
estimates. The following assessment of significant accounting
policies is not meant to be exhaustive. The Trust may realize
different results from the application of new accounting standards
proposed and / or implemented, from time to time, by various
rule-making bodies. Proved and Probable Oil and Gas Reserves Proved
oil and gas reserves, as defined by the Canadian Securities
Administrators' National Instrument 51-101 (NI 51-101), are the
estimated quantities of crude oil, natural gas liquids, including
condensate, and natural gas that geological and engineering data
demonstrate with reasonable certainty can be recovered 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. Proved reserves are those reserves that can be estimated with
a high degree of certainty to be recoverable (i.e. it is likely
that the actual remaining quantities recovered will exceed the
estimated proved reserves). In accordance with this definition, the
level of certainty targeted by the reporting company should result
in at least a 90% probability that the quantities actually
recovered will equal or exceed the estimated proved reserves. For
probable reserves, which are by definition less certain to be
recovered than proved reserves, NI 51-101 states that it must be
equally likely that the actual remaining quantities recovered will
be greater or less than the sum of the estimated proved plus
probable reserves. With respect to the consideration of certainty,
in order to report reserves as proved plus probable, the level of
certainty targeted by the reporting company should result in at
least a 50% probability that the quantities actually recovered will
equal or exceed the sum of the estimated proved plus probable
reserves. The oil and gas reserve estimates are made using all
available geological and reservoir data as well as historical
production data. Estimates are reviewed and revised as appropriate.
Revisions occur as a result of changes in prices, costs, fiscal
regimes, reservoir performance or a change in PrimeWest's plans.
The effect of changes in proved oil and gas reserves on the
financial results and position of PrimeWest is described under the
heading "Full Cost Accounting for Oil and Gas Activities". Full
Cost Accounting For Oil and Gas Activities PrimeWest has adopted
CICA Accounting Guideline 16 (AcG-16), "Oil and Gas Accounting -
Full Costs". The new guideline modifies how the ceiling test is
performed and requires cost centers be tested for recoverability
using undiscounted future cash flows from proved reserves which are
determined by using forward indexed prices. When the carrying
amount of a cost center is not recoverable, the cost center would
be written down to its fair value. Fair value is estimated using
accepted present value techniques which incorporate risks and other
uncertainties when determining expected cash flows. Depletion
Expense PrimeWest uses the full cost method of accounting for
exploration and development activities. In accordance with this
method of accounting, all costs associated with exploration and
development are capitalized whether successful or not. The
aggregate of net capitalized costs and estimated future development
costs less estimated salvage values is amortized using the unit of
production method based on estimated proved oil and gas reserves.
An increase in estimated proved oil and gas reserves would result
in a corresponding reduction in depletion expense. A decrease in
estimated future development costs would result in a corresponding
reduction in depletion expense. Fair Value of Derivative
Instruments As part of its financial management strategy, PrimeWest
utilizes financial derivatives to manage market risk. The purpose
of the hedge is to provide an element of stability to PrimeWest's
cash flow in a volatile commodity price environment. Effective
January 1, 2004 PrimeWest adopted CICA Accounting Guideline 13,
"Hedging Relationships" ("AcG-13"). The estimation of the fair
value of certain hedging derivatives requires considerable
judgment. The estimation of the fair value of commodity price
hedges requires sophisticated financial models that incorporate
forward price and volatility data and, which when compared with
PrimeWest's outstanding hedging contracts, produce cash inflow or
outflow variances over the contract period. The estimate of fair
value for interest rate and foreign currency hedges is determined
primarily through quotes from financial institutions. Asset
Retirement Obligations Effective January 1, 2004 PrimeWest changed
its accounting policy with respect to accounting for asset
retirement obligations. CICA section 3110 requires the fair value
of asset retirement obligations to be recorded when they are
incurred rather than merely accumulated or accrued over the useful
life of the respective asset. PrimeWest, under the current policy,
is required to provide for future removal and site restoration
costs. PrimeWest must estimate these costs in accordance with
existing laws, contracts or other policies. These estimated costs
are charged to earnings and the appropriate liability account over
the expected service life of the asset. When the future removal and
site restoration costs cannot be reasonably determined, a
contingent liability may exist. Contingent liabilities are charged
to earnings when management is able to determine the amount and the
likelihood of the future obligation. Legal, Environmental
Remediation and Other Contingent Matters The Trust is required to
both determine whether a loss is probable based on judgment and
interpretation of laws and regulations and whether that loss can
reasonably be estimated. When the loss is determined, it is charged
to earnings. PrimeWest's management must continually monitor known
and potential contingent matters and make appropriate provisions by
charges to earnings when warranted by circumstance. Income Tax
Accounting The determination of the Trust's income and other tax
liabilities requires interpretation of complex laws and
regulations. All tax filings are subject to audit and potential
reassessment after the lapse of considerable time. Accordingly, the
actual income tax liability may differ significantly from that
estimated and recorded by management. Business Combinations Since
inception, PrimeWest has grown considerably through combining with
other businesses. PrimeWest acquired Seventh Energy Ltd in the
first quarter of 2004. This transaction was accounted for using
what is now the only accounting method available, the purchase
method. Under the purchase method, the acquiring company includes
the fair value of the assets of the acquired entity on its balance
sheet. The determination of fair value necessarily involves many
assumptions. The valuation of oil and gas properties primarily
involves placing a value on the oil and gas reserves. The valuation
of oil and gas reserves entails the process described above under
the caption "Proved and Probable Oil and Gas Reserves" but also
incorporates the use of economic forecasts that estimate future
changes in prices and costs. This methodology is also used to value
unproved oil and gas reserves. The valuation of these reserves, by
their nature, is less certain than the valuation of proved
reserves. Goodwill The process of accounting for the purchase of a
company, described above, results in recognizing the fair value of
the acquired company's assets on the balance sheet of the acquiring
company. Any excess of the purchase price over fair value is
recorded as goodwill. Since goodwill results from the culmination
of a process that is inherently imprecise, the determination of
goodwill is also imprecise. In accordance with the recent issuance
of CICA section 3062, "Goodwill and Other Intangible Assets",
goodwill is no longer amortized but assessed periodically for
impairment. The process of assessing goodwill for impairment
necessarily requires PrimeWest to determine the fair value of its
assets and liabilities. Such a process involves considerable
judgment. Business Risks PrimeWest's operations are affected by a
number of underlying risks, both internal and external to the
Trust. These risks are similar to those affecting others in both
the conventional oil and gas royalty trust sector and the
conventional oil and gas producers sector. The Trust's financial
position, results of operations, and cash available for
distribution to unitholders are directly impacted by these factors.
These factors are discussed under two broad categories - Commodity
Price, Foreign Exchange and Interest Rate Risk, and Operational and
Other Business Risks. Commodity Price, Foreign Exchange And
Interest Rate Risk The primary objective of our commodity risk
management program is to reduce the volatility of our cash
distributions, to lock in the economics on major acquisitions and
to protect our capital structure when commodity prices cycle
downwards. In the second quarter of 2004, PrimeWest lost $7.5
million from commodity hedges, but has added $26.0 million to
revenue from its hedging program from January 1, 2001 to the end of
the second quarter of 2004. The two most important factors
affecting the level of cash distributions available to unitholders
are the level of production achieved by PrimeWest, and the price
received for its products. These prices are influenced in varying
degrees by factors outside the Trust's control. Some of these
factors include: - World market forces, specifically the actions of
OPEC and other large crude oil producing countries including
Russia, and their implications on the supply of crude oil; - World
and North American economic conditions which influence the demand
for both crude oil and natural gas and the level of interest rates
set by the governments of Canada and the U.S.; - weather conditions
that influence the demand for natural gas and heating oil; - the
Canadian/U.S. dollar exchange rate that affects the price received
for crude oil as the price of crude oil is referenced in U.S.
dollars; - transportation availability and costs; and - price
differentials among World and North American markets based on
transportation costs to major markets and quality of production. To
mitigate these risks, PrimeWest has an active hedging program in
place based on an established set of criteria that has been
approved by the Board of Directors. The results of the hedging
program are reviewed against these criteria and the results
actively monitored by the Board. Beyond our hedging strategy,
PrimeWest also mitigates risk by having a well-diversified
marketing portfolio and by transacting with a number of
counter-parties and limiting exposure to each counter-party. In
2003, approximately 25% of natural gas production was sold to
aggregators and 75% into the Alberta short-term or export long-term
markets, and for 2004 we do not anticipate any material change to
this breakdown. The contracts that PrimeWest has with aggregators
vary in length. They represent a blend of domestic and U.S. markets
and fixed and floating prices designed to provide price
diversification to our revenue stream. Operational And Other
Business Risks PrimeWest is also exposed to a number of risks
related to its activities within the oil and gas industry that have
an impact on the amount of cash available to unitholders. These
risks, and the manner in which PrimeWest seeks to mitigate these
risks include, but are not limited to: Risk: Production ----------
Risk associated with the production of oil and gas - includes well
operations, processing and the physical delivery of commodities to
market. We mitigate by: Performing regular and proactive protective
well, facility and pipeline maintenance supported by telemetry,
physical inspection and diagnostic tools. Commodity Price
--------------- Fluctuations in natural gas, crude oil and natural
gas liquid prices. We mitigate by: Hedging. See page 11 of this
press release. Transportation -------------- Market risk related to
the availability of transportation to market and potential
disruption in delivery systems. We mitigate by: Diversifying the
transportation systems on which we rely to get our product to
market. Natural decline --------------- Development risk associated
with capital enhancement activities undertaken - the risk that
capital spending on activities such as drilling, well completions,
well workovers and other capital activities will not result in
reserve additions or in quantities sufficient to replace annual
production declines. We mitigate by: Diversifying our capital
spending program over a large number of projects so that
significant capital is not risked on any one activity. We also have
a highly skilled technical team of geologists, geophysicists and
engineers working to apply the latest technology in planning and
executing capital programs. Capital is spent only after strict
economic criteria for production and reserve additions are
assessed. Acquisitions ------------ Acquisition risk associated
with acquiring producing properties at low cost to renew our
inventory of assets. We mitigate by: Continually scanning the
marketplace for opportunities to acquire assets. Our technical
acquisition specialists evaluate potential corporate or property
acquisitions and identify areas for value enhancement through
operational efficiencies or capital investment. All prospects are
subjected to rigorous economic review against established
acquisition and economic hurdle rates. In some cases we may also
hedge commodity prices to protect the acquisition economics in the
near term period. Reserves -------- Reserve risk in respect of the
quantity and quality of recoverable reserves. We mitigate by:
Contracting our reserves evaluation to a reputable third party
consultant, Gilbert Laustsen Jung (GLJ). The work and independence
of GLJ is reviewed by the Operations and Reserves Committee of the
Board of Directors of PrimeWest. Our strategy is to invest in
mature, longer life properties having a higher proved producing
component where the reserve risk is generally lower and cash flows
are more stable and predictable. Environmental Health and Safety
(EH&S) -------------------------------------- Environmental,
health and safety risks associated with oil and gas properties and
facilities. We mitigate by: Establishing and adhering to strict
guidelines for EH&S including training, proper reporting of
incidents, supervision and awareness. PrimeWest has active
community involvement in field locations including regular meetings
with stakeholders in the area. PrimeWest carries adequate insurance
to cover property losses, liability and business interruption.
These risks are reviewed regularly by the Corporate Governance and
EH&S Committee of the Board, which acts as PrimeWest's
Environmental, Health and Safety Committee. Regulation, Tax and
Royalties ----------------------------- Changes in government
regulations including reporting requirements, income tax laws,
operating practices, environmental protection requirements and
royalty rates. We mitigate by: Keeping informed of proposed changes
in regulations and laws to properly respond to and plan for the
effects that these changes may have on our operations. Liability to
unitholders ------------------------ There is no statutory
protection for unitholders from liabilities of the Trust. We
mitigate by: Limiting the business of the Trust to the right to
receive the net cash flow of PrimeWest Energy Inc. and its
subsidiaries. All of the oil and gas business operations of
PrimeWest are conducted by PrimeWest Energy Inc. and its
subsidiaries. PrimeWest Energy Inc. has a vigorous EH&S program
as well as significant insurance protection. Additional Information
Additional information pertaining to PrimeWest, including the
Trust's most recently filed Annual Report and Annual Information
Form, is available on SEDAR at http://www.sedar.com/ and on the
PrimeWest website at http://www.primewestenergy.com/. PrimeWest
welcomes questions from unitholders and potential investors; call
Investor Relations at 403-234-6600 or toll-free in Canada and the
U.S. at 1-877-968-7878; or visit us at our website,
http://www.primewestenergy.com/. We make every effort to respond to
queries as quickly as possible, but during periods of heavy call
volume, our response time may take up to 2 business days. PrimeWest
Energy Trust
-------------------------------------------------------------------------
Consolidated Balance Sheet (Unaudited) (Audited) (millions of
dollars) June 30, 2004 Dec 31, 2003
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(Restated - Note 2) ASSETS Current assets Cash and short term
deposits $ 12.5 $ 2.5 Accounts receivable 66.5 65.4 Derivative loss
(Note 4) 1.5 - Prepaid expenses 7.1 6.5 Inventory 2.5 2.1
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90.1 76.5 Cash reserved for site restoration and reclamation 9.8
8.2 Other assets and deferred charges 1.7 1.5 Property, plant and
equipment 1,255.8 1,548.2 Goodwill 68.8 56.1
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$ 1,426.2 $ 1,690.5
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LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities Accounts
payable $ 18.5 $ 26.7 Accrued liabilities 47.8 45.3 Derivative
liabilities (Note 4) 14.3 - Accrued distributions to unitholders
11.8 10.3
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92.4 82.3 Derivative liabilities (Note 4) 1.3 - Long-term debt
(Note 6) 179.7 250.1 Future income taxes 227.6 313.2 Asset
retirement obligation (Note 5) 19.9 19.7
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520.9 665.3 UNITHOLDERS' EQUITY Net capital contributions (Note 7)
1,732.0 1,565.9 Capital issued but not distributed 2.3 5.2
Long-term incentive plan equity 5.3 14.6 Accumulated income 28.4
219.1 Accumulated cash distributions (854.7) (771.6) Accumulated
dividends (8.0) (8.0)
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905.3 1,025.2
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$ 1,426.2 $ 1,690.5
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The accompanying notes form an integral part of these financial
statements. Consolidated Statements of Unitholders' Equity
(Unaudited) For the six months ended (millions of dollars) June 30,
2004 June 30, 2003
-------------------------------------------------------------------------
(Restated - Note 2) Unitholders' equity, beginning of period $
1,019.6 $ 847.2 Adjustment to Unitholders' equity at beginning of
period to adopt: New Asset Retirement Obligation (Note 2) 5.6 - New
Oil and Gas Accounting Standard (Note 2) (233.3) - Net income for
the period 42.6 83.2 Net capital contributions 166.1 168.0 Capital
issued but not distributed (2.9) 0.2 Long-term incentive plan
equity (9.3) 1.6 Cash distributions (83.1) (102.6)
-------------------------------------------------------------------------
Unitholders' equity, end of period $ 905.3 $ 997.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated Statements of Cash Flow (Unaudited) Three Months Ended
Six Months Ended --------------------------------------- June 30,
June 30, June 30, June 30, (millions of dollars) 2004 2003 2004
2003
-------------------------------------------------------------------------
(Restated - (Restated - Note 2) Note 2) OPERATING ACTIVITIES Net
income for the period $ 22.4 $ 61.4 $ 42.6 $ 83.2 Add/(deduct):
Items not involving cash from operations Depletion, depreciation
and amortization 41.4 49.9 83.0 102.6 Non-cash general &
administrative (7.3) 3.2 (6.8) 3.6 Non-cash foreign exchange loss
(gain) 2.9 (5.6) 4.7 (5.6) Accretion on asset retirement obligation
0.4 0.3 0.7 0.6 Future income taxes recovery (3.4) (52.0) (21.6)
(62.4) Unrealized loss on derivatives 1.8 - 14.1 -
-------------------------------------------------------------------------
Cash flow from operations 58.2 57.2 116.7 122.0 Expenditures on
site restoration and reclamation (0.3) (0.3) (1.3) (0.4) Change in
non-cash working capital (8.0) 5.7 (6.8) (5.3)
-------------------------------------------------------------------------
49.9 62.6 108.6 116.3
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FINANCING ACTIVITIES Proceeds from issue of Trust Units, net of
issue costs 140.0 7.0 142.8 160.2 Net cash distributions to
unitholders (35.1) (49.4) (65.0) (96.5) Decrease in bank credit
facilities (123.1) (170.0) (84.9) (95.0) Increase in senior secured
notes - 174.0 - 174.0 Increase in deferred charges - (1.4) - (1.4)
Change in non-cash working capital 1.6 0.2 1.4 2.9
-------------------------------------------------------------------------
(16.6) (39.6) (5.7) 144.2
-------------------------------------------------------------------------
INVESTING ACTIVITIES Expenditures on property, plant &
equipment (22.2) (18.8) (53.6) (44.2) Corporate acquisitions (Note
3) - (2.9) (34.8) (200.4) Acquisition of capital assets (0.4) (3.5)
(4.2) (3.8) Proceeds on disposal of property, plant & equipment
1.6 - 5.1 0.2 Increase in cash reserved for future site restoration
and reclamation (1.1) (1.3) (1.7) (2.7) Change in non-cash working
capital (5.1) (4.1) (3.7) 2.7
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(27.2) (30.6) (92.9) (248.2)
-------------------------------------------------------------------------
INCREASE IN CASH FOR THE PERIOD 6.1 (7.6) 10.0 12.3 CASH (BANK
OVERDRAFT) BEGINNING OF THE PERIOD 6.4 16.8 2.5 (3.1)
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CASH END OF THE PERIOD $ 12.5 $ 9.2 $ 12.5 $ 9.2
-------------------------------------------------------------------------
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CASH INTEREST PAID $ 4.2 $ 2.5 $ 5.4 $ 4.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CASH TAXES PAID $ 1.3 $ 0.8 $ 2.3 $ 0.8
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-------------------------------------------------------------------------
Consolidated Statements of Income (Unaudited) Three Months Ended
Six Months Ended
-------------------------------------------------------------------------
(millions of dollars, June 30, June 30, June 30, June 30, except
per Trust Unit amounts) 2004 2003 2004 2003
-------------------------------------------------------------------------
(Restated - (Restated - Note 2) Note 2) REVENUES Sales of crude
oil, natural gas and natural gas liquids $ 112.2 $ 112.7 $ 222.8 $
241.4 Transportation expenses (1.8) (2.3) (3.7) (4.2) Crown and
other royalties, net of ARTC (25.7) (25.0) (49.0) (57.7) Other
income 0.2 0.2 0.5 0.2
-------------------------------------------------------------------------
84.9 85.6 170.6 179.7
-------------------------------------------------------------------------
EXPENSES Operating 19.6 20.3 39.2 41.0 Cash general and
administrative 3.5 3.2 7.7 7.0 Non-cash general and administrative
(7.3) 3.2 (6.8) 3.6 Interest 2.8 3.4 6.0 7.0 Accretion on asset
retirement obligation 0.4 0.3 0.7 0.6 Unrealized loss on
derivatives 1.8 - 14.1 - Foreign exchange loss (gain) 3.2 (5.6) 4.9
(5.6) Depletion, depreciation and amortization 41.4 49.9 83.0 102.6
-------------------------------------------------------------------------
$ 65.4 $ 74.7 $ 148.8 $ 156.2
-------------------------------------------------------------------------
Income before taxes for the period $ 19.5 $ 10.9 $ 21.8 $ 23.5
-------------------------------------------------------------------------
Income and capital taxes 0.5 1.5 0.8 2.7 Future income taxes
recovery (3.4) (52.0) (21.6) (62.4)
-------------------------------------------------------------------------
(2.9) (50.5) (20.8) (59.7)
-------------------------------------------------------------------------
Net income for the period $ 22.4 $ 61.4 $ 42.6 $ 83.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust Unit - basic $ 0.41 $ 1.34 $ 0.80 $ 1.89 Net
income per Trust Unit - diluted $ 0.40 $ 1.33 $ 0.80 $ 1.88
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Notes to Consolidated Financial Statements For the six months ended
June 30, 2004 (millions of dollars except per Trust Unit/share
amounts). All amounts are expressed in millions of Canadian dollars
unless otherwise indicated. 1. Significant Accounting Policies
----------------------------------- These interim consolidated
financial statements of PrimeWest Energy Trust have been prepared
in accordance with Canadian generally accepted accounting
principles. The specific accounting principles used are described
in the annual consolidated financial statements of the Trust
appearing on pages 69 through 91 of the Trust's 2003 annual report
and should be read in conjunction with these interim financial
statements. 2. Changes in Accounting Policies
---------------------------------- Full Cost Accounting The
adoption of AcG-16 modifies how the ceiling test is performed
resulting in a two stage process. The first stage requires the
carrying amount of the cost centers to be tested for recoverability
using undiscounted future cash flows from proved reserves using
management's best estimate of forward indexed prices. When the
carrying amount of a cost center is not recoverable, the second
stage of the process will determine the impairment whereby the cost
center would be written down to its fair value. The second stage
requires the calculation of discounted future cash flows from
proved plus probable reserves. The fair value is estimated using
accepted present value techniques, which incorporate risks and
other uncertainties when determining expected cash flows. PrimeWest
has performed the ceiling test under AcG-16 as of January 1, 2004.
The impairment test was calculated using the consultant's average
prices at January 1 for the years 2004 to 2008 as follows:
Consultant's Average Price Forecasts Year
-------------------------------------------------------------------------
2004 2005 2006 2007 2008
-------------------------------------------------------------------------
WTI ($U.S./bbl) 29.21 26.43 25.42 25.38 25.51 AECO ($Cdn/mcf) 5.90
5.33 4.98 4.95 4.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The ceiling test resulted in a before tax impairment of $308.9
million and an after tax impairment of $233.2 million. This write
down was recorded to accumulated income in the first quarter of
2004 with the adoption of AcG-16. Asset Retirement Obligation
Effective January 1, 2004, the Trust retroactively adopted the CICA
Handbook section 3110, "Asset Retirement Obligations". The new
standard requires the recognition of the liability associated with
the future site reclamation costs of tangible long-lived assets.
This liability would be comprised of the Trust's net ownership
interest in producing wells and processing plant facilities. The
liability for future retirement obligations is to be recorded in
the financial statements at the time the liability is incurred. The
asset retirement obligation is initially recorded at the estimated
fair value as a long-term liability with a corresponding increase
to property, plant and equipment. The depreciation of property,
plant and equipment is allocated to expense on the
unit-of-production basis. The liability is increased each reporting
period for the fair value of any new future site reclamation costs
and the corresponding accretion on the original provision. The
accretion is charged to earnings in the period incurred. The
provision will also be revised for any changes to timing related to
cash flows or undiscounted reclamation costs. Actual expenditures
incurred for the purpose of site reclamation are charged to the
asset retirement obligation to the extent that the liability exists
on the balance sheet. Differences between the actual costs incurred
and the fair value of the liability recorded are recognized to
earnings in the period incurred. The Trust previously estimated the
costs of dismantlement, removal, abandonment and site reclamation
on a unit-of-production basis over the remaining life of the
estimated proved reserves. This estimate was charged to earnings
with a corresponding offset to the accumulated site provision
liability on the balance sheet. The adoption of CICA Handbook
section 3110 allows for the cumulative effect of the change in
accounting policy to be recorded to accumulated income with
retroactive restatement of prior period comparatives. At January 1,
2004, this resulted in an increase to the asset retirement
obligation of $19.7 million (2003 - $15.3 million), an increase to
PP&E of $10.6 million (2003 - $9.0 million), a $5.6 million
(2003 - $0.04 million) increase to accumulated income, a decrease
of site restoration provision of $17.8 million (2003 - $6.2
million) and an increase to the future tax liability of $3.1
million (2003 - $(0.03) million). See Note 5 for the reconciliation
of the asset retirement obligation. Implementation of this
accounting standard did not affect the Trust's cash flow or
liquidity. Financial Derivatives Effective January 1, 2004, the
Trust has implemented CICA Accounting Guideline (AcG-13), "Hedging
Relationships", which is effective for fiscal years beginning on or
after July 1, 2003. AcG-13 addresses the identification,
designation, documentation and effectiveness of hedging
transactions for the purposes of applying hedge accounting. It also
established conditions for applying or discontinuing hedge
accounting. Under the new guideline, hedging transactions must be
documented and it must be demonstrated that the hedges are
sufficiently effective in order to continue accrual accounting for
position hedges with derivatives. The trust is not applying hedge
accounting to its hedging relationships. As of January 1, 2004, the
Trust recorded $6.0 million for the mark-to-market value of the
outstanding hedges as a derivative liability and a $6.0 million
deferred derivative loss, to be realized upon settlement of the
corresponding derivative instrument. The deferred loss at January
1, 2004 was comprised of a $3.9 million loss for crude oil, $2.1
million loss for natural gas, $0.6 million loss for interest rate
swaps and a gain of $0.6 million for electrical power. See Note 4
for the reconciliation of the derivative liability and deferred
derivative loss. 3. Corporate Acquisition -------------------------
a) On March 16, 2004, PrimeWest Gas Corp. completed the acquisition
of Seventh Energy Ltd. Subsequent to the acquisition, Seventh
Energy was amalgamated with PrimeWest Gas Corp. The acquisition was
accounted for using the purchase method of accounting with net
assets acquired and consideration paid as follows:
-------------------------------------------------------------------------
Net Assets Acquired at Assigned Values ($ millions) Consideration
Paid ($ millions)
-------------------------------------------------------------------------
Petroleum and natural gas assets $ 46.5 Goodwill 12.8 Working
capital (2.5) Long-term debt assumed (9.9) Office lease obligation
(0.1) Asset retirement obligation (0.5) Cash $ 34.6 Future income
taxes (11.5) Costs associated with acquisition 0.2
-------------------------------------------------------------------------
$ 34.8 $ 34.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. Derivative Liabilities -------------------------- Derivative
Liability ($ millions)
-------------------------------------------------------------------------
Derivative Liability, January 1, 2004 $ 6.0 Derivative instruments
settled (11.9) Mark-to-market unrealized loss 21.5
-------------------------------------------------------------------------
Derivative Liability, June 30, 2004 $ 15.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current Derivative Liability $ 14.3 Long term Derivative Liability
1.3
-------------------------------------------------------------------------
Derivative Liability, June 30, 2004 $ 15.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Derivative Loss ($ millions)
-------------------------------------------------------------------------
Derivative Loss, January 1, 2004 $ 6.0 Derivative instruments
settled that existed on January 1, 2004 or prior (4.5)
-------------------------------------------------------------------------
Derivative Loss, June 30, 2004 $ 1.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
5. Asset Retirement Obligations --------------------------------
Management has estimated the total future asset retirement
obligation based on the Trust's net ownership interest in all wells
and facilities. This includes all estimated costs to dismantle,
remove, reclaim and abandon the wells and facilities and the
estimated time period during which these costs will be incurred in
the future. The following table reconciles the asset retirement
obligation associated with the retirement of oil and gas
properties: Asset Retirement Obligation ($ millions)
-------------------------------------------------------------------------
Asset Retirement Obligation, December 31, 2003 $ 19.7 Liabilities
incurred 0.3 Liabilities settled (1.3) Accretion expense 0.7
Acquisition of Seventh Energy 0.5
-------------------------------------------------------------------------
Asset Retirement Obligation, June 30, 2004 $ 19.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at June 30, 2004, the undiscounted amount of estimated cash
flows required to settle the obligation is $124.6 million. The
estimated cash flow has been discounted using a credit-adjusted
risk free rate of 7.0 percent and an inflation rate of 1.5 percent.
Although the expected period until settlement ranges from a minimum
of 7 years to a maximum of 50 years, the costs are expected to be
paid over an average of 34 years. These future asset retirement
costs will be funded from the cash reserved for site restoration
and reclamation. This cash reserve is currently funded at $0.50 per
boe from PrimeWest's operating resources. 6. Long-Term Debt
------------------ ($ millions) June 30, 2004 Dec 31, 2003
-------------------------------------------------------------------------
Bank credit facilities $ 13.0 $ 88.0 Senior secured notes 166.7
162.1
-------------------------------------------------------------------------
$ 179.7 $ 250.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. Unitholders' Equity ----------------------- The authorized
capital of the Trust consists of an unlimited number of Trust
Units. Trust Units Number of Units ($ millions)
-------------------------------------------------------------------------
Balance, December 31, 2003 48,751,883 $ 1,537.9 Issued pursuant to
equity offering 5,400,000 134.7 Issued on exchange of Exchangeable
Shares 773,150 15.8 Issued pursuant to Distribution Reinvestment
Plan 144,910 3.5 Issued pursuant to the Premium Distribution Plan
720,102 17.6 Issued pursuant to Long-Term Incentive Plan 83,524 2.2
Issued pursuant to Optional Trust Unit Purchase Plan 344,753 8.1
-------------------------------------------------------------------------
Balance, June 30, 2004 56,218,322 $ 1,719.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The weighted average number of Trust Units and Exchangeable Shares
outstanding for the three and six months ended June 30, 2004 were
55,296,924 (2003 - 45,714,429) and 52,886,415 (2003 - 43,927,753)
respectively. For purposes of calculating diluted net income per
Trust Unit, 165,830 Trust Units (2003 - 405,357) issuable pursuant
to the Long- Term Incentive Plan were added to the weighted average
number. The per unit cash distribution amounts paid or declared
reflects distributions paid or declared to Trust Units outstanding
on the record dates. PrimeWest Exchangeable Class A Shares The
Exchangeable Shares are exchangeable into PrimeWest Trust Units at
any time up to March 29, 2010 based on an exchange ratio that
adjusts each time the Trust makes a distribution to its
unitholders. The exchange ratio, which was 1:1 on the date that the
Exchangeable Shares were first issued, is based on the total
monthly distribution, divided by the closing unit price on the
distribution payment date. The exchange ratio effective June 15,
2004 was 0.47310:1 and December 31, 2003 was 0.44302:1.
Exchangeable Shares No. of shares ($ millions)
-------------------------------------------------------------------------
Balance, December 31, 2003 3,041,123 $ 28.0 Exchanged for Trust
Units (1,720,826) (15.8)
-------------------------------------------------------------------------
Balance, June 30, 2004 1,320,297 $ 12.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
8. Long-Term Incentive Plan ---------------------------- Under the
terms of the Long Term Incentive Plan, a maximum of 1,800,000 Trust
Units are reserved for issuance pursuant to the exercise of Unit
Appreciation Rights (UARs) granted to employees of PrimeWest.
Payouts under the plan are based on total unitholder return,
calculated using both the change in the Trust Unit price as well as
cumulative distributions paid. The plan requires that a hurdle
return of 5% per annum be achieved before payouts accrue. UARs have
a term of up to six years and vest equally over a three-year
period, except for the members of the Board, whose UARs vest
immediately. The Board of Directors has the option of settling
payouts under the plan in PrimeWest Trust Units or in cash. To
date, all payouts under the plan have been in the form of Trust
Units. As at June 30, 2004
-------------------------------------------------------------------------
Current UARs return per issued & UARs "in the Total Trust Unit
Year of Grant outstanding vested money" UARs equity dilution
-------------------------------------------------------------------------
1999 grants 38,331 38,331 $ 26.88 $ 1.0 44,317 2000 grants 111,318
111,318 9.32 1.0 44,602 2001 grants 355,297 294,750 3.28 1.2 35,772
2002 grants 871,819 456,961 2.23 1.4 25,232 2003 grants 1,018,043
263,861 1.13 0.7 15,907 2004 grants 632,305 72,489 $ 0.01 - -
-------------------------------------------------------------------------
Total grants 3,027,113 1,237,710 $ 5.3 165,830
-------------------------------------------------------------------------
-------------------------------------------------------------------------
9. Cash Distributions ---------------------- Three Months Ended Six
Months Ended
-------------------------------------------------------------------------
(millions of dollars, June 30, June 30, June 30, June 30, except
per Trust Unit amounts) 2004 2003 2004 2003
-------------------------------------------------------------------------
Net income for the period Add back (deduct) amounts to reconcile to
distribution: $ 22.4 $ 61.4 $ 42.6 $ 83.2 Depletion, depreciation
and amortization 41.4 49.9 83.0 102.6 Cash retained from cash
available for distribution (14.7) (2.8) (30.6) (16.3) Contribution
to reclamation fund (1.5) (1.6) (3.0) (3.1) Non-cash general and
administrative (7.3) 3.2 (6.8) 3.6 Unrealized loss on derivatives
1.8 - 14.1 - Non-cash foreign exchange loss (gain) 2.9 (5.6) 4.7
(5.6) Accretion on asset retirement obligation 0.4 0.3 0.7 0.6
Future income taxes recovery (3.4) (52.0) (21.6) (62.4)
-------------------------------------------------------------------------
$ 42.0 $ 52.8 $ 83.1 $ 102.6
-------------------------------------------------------------------------
Cash Distributions to Trust Unitholders $ 42.0 $ 52.8 $ 83.1 $
102.6
-------------------------------------------------------------------------
Cash Distributions per Trust Unit $ 0.75 $ 1.20 $ 1.57 $ 2.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Trading Performance For the quarter ended Jun 30/04 Mar 31/04 Dec
31/03 Sep 30/03 Jun 30/03
-------------------------------------------------------------------------
TSX Trust Unit prices ($ per Trust Unit) High 26.80 28.35 28.15
26.80 27.75 Low 22.18 22.70 23.40 25.19 23.40 Close 23.25 26.65
27.56 25.19 25.04
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Average daily traded volume 187,767 256,922 202,661 149,148 234,477
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the quarter ended Jun 30/04 Mar 31/04 Dec 31/03 Sep 30/03 Jun
30/03
-------------------------------------------------------------------------
TSX Trust Unit prices ($U.S. per Trust Unit) High 20.44 22.14 21.48
19.29 20.60 Low 16.00 17.31 18.67 18.08 15.97 Close 17.43 20.31
21.27 18.68 18.53
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Average daily traded volume 279,882 469,694 243,921 151,813 166,722
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of Trust Units outstanding including Exchangeable Shares
(millions of units) 56.8 50.87 50.10 49.52 45.99
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Distribution paid per Trust Unit $0.75 $0.82 $0.96 $0.96 $1.20
-------------------------------------------------------------------------
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END FIRST AND FINAL ADD DATASOURCE: PrimeWest Energy Trust CONTACT:
PR Newswire -- Aug. 3
Copyright