PrimeWest Energy Trust announces third quarter 2004 results
CALGARY, ALBERTA--(CCNMatthews - Nov. 02, 2004) - PrimeWest Energy Trust
(TSX:PWI.UN) (TSX:PWX) (TSX:PWI.DB.A) (TSX:PWI.DB.B) (NYSE:PWI) (PrimeWest or
the Trust) today announced interim operating and financial results for the
third quarter ended September 30, 2004. Unless otherwise noted, all figures
contained in this report are in Canadian dollars.
Third Quarter Highlights:
- On September 2, 2004, PrimeWest completed the acquisition of Calpine
Canada assets at a cost of $806 million acquiring approximately
14,500 BOE per day of production and a 25% interest in Calpine Natural
Gas Trust. Transaction costs associated with the acquisition were
$8.7 million. PrimeWest entered into a series of transactions that
hedged up to 90% of the volumes acquired from Calpine. This was
achieved through the use of wide costless collar instruments that
continue through to the first quarter of 2006.
- In the third quarter, PrimeWest increased the monthly cash
distributions by approximately 20% or $0.05 per month to $0.30 per
unit effective with the October 15, 2004 distribution.
- During the quarter, PrimeWest concluded a financing of $550 million
comprised of a $300 million equity issuance and $250 million of
convertible unsecured subordinated debentures. These funds, together
with additional bank borrowings, were used to acquire the Calpine
assets.
- Debt to annualized third quarter 2004 cash flow is 1.7 times.
- Third quarter production averaged 35,460 barrels of oil equivalent
(BOE) per day, compared to the second quarter 2004 rate of 31,185 BOE
per day.
- Distributions of $0.83 per unit represent a payout ratio of
approximately 74%, compared to second quarter 2004 distributions of
$0.75 per unit, representing a payout ratio of 72%.
- Cash flow from operations of $68.3 million ($1.06 per unit) compared
to $58.2 million ($1.05 per unit) in the second quarter of 2004,
primarily due to a continued strong commodity price environment and
increased production volumes for the month of September from the
Calpine asset acquisition.
- Following the completion of the Calpine transaction where
the assets were acquired with full tax pools, PrimeWest has
re-evaluated its taxability of the 2004 distributions. For unitholders
resident in Canada, PrimeWest anticipates that approximately 55% of
2004 distributions will be taxable and 45% will be deemed a return of
capital.
Subsequent Events
- On October 4, 2004, PrimeWest commenced an asset divestiture program
targeting to sell approximately $100 million of non-core assets. Bids
are due on November 4, 2004 and the targeted closure of successful
asset sales is December 31, 2004.
Management's Discussion and Analysis
The following is management's discussion and analysis (MD&A) of
PrimeWest's operating and financial results for the quarter ended
September 30, 2004, compared with the preceding quarter and the corresponding
period in the prior year as well as information and opinions concerning the
Trust's future outlook based on currently available information. This
discussion should be read in conjunction with the Trust's audited consolidated
financial statements for the years ended December 31, 2003 and 2002, together
with accompanying notes, as contained in the Trust's 2003 Annual Report.
/T/
Financial and Operating Highlights - Third Quarter
Financial Highlights Three Months Ended Nine Months Ended
(millions of dollars, ------------------------------------------------
except per BOE and Sep 30, June 30, Sep 30, Sep 30, Sep 30,
per Trust Unit amounts) 2004 2004 2003 2004 2003
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Net revenue 97.2 84.9 77.2 267.8 256.9
per BOE(1) 29.79 29.91 25.70 29.96 27.91
Cash flow from operations 68.3 58.2 51.8 185.0 173.7
per BOE 20.93 20.52 17.25 20.69 18.88
per Trust Unit(2) 1.06 1.05 1.11 3.24 3.85
Royalty expense 28.9 25.7 23.1 78.0 80.8
per BOE 8.86 9.06 7.70 8.72 8.77
Operating expenses 21.4 19.6 17.2 60.6 58.2
per BOE 6.56 6.89 5.73 6.78 6.32
G&A expenses - Cash 3.4 3.5 3.5 11.1 10.5
per BOE 1.03 1.23 1.15 1.24 1.14
G&A expenses - Non-cash 14.1 (7.3) 2.3 7.2 5.9
per BOE 4.31 (2.57) 0.76 0.80 0.64
Interest expense 2.9 2.8 4.0 8.9 11.0
per BOE 0.90 1.00 1.32 1.00 1.20
Distributions to
unitholders 50.4 42.0 43.7 133.5 146.3
per Trust Unit(3) 0.83 0.75 0.96 2.40 3.36
Net debt(4) 464.8 169.2 233.4 464.8 233.4
per Trust Unit(5) 5.84 2.97 4.68 5.84 4.68
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(1) All calculations required to convert natural gas to a crude oil
equivalent (BOE) have been made using a ratio of 6,000 cubic feet of
natural gas to one barrel of crude oil. BOE's may be misleading,
particularly if used in isolation. The BOE conversion ratio 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) Weighted Average Trust Units, Exchangeable Shares, Convertible
Unsecured Debentures and Trust Units issueable pursuant to Long-Term
Incentive Plan (diluted).
(3) Based on Trust Units outstanding at date of distribution.
(4) Net debt is long-term debt adjusted for working capital excluding
financial derivative assets and liabilities.
(5) Trust Units, Exchangeable Shares outstanding, Convertible Unsecured
Debentures and Trust Units issueable pursuant to the Long-Term
Incentive Plan (diluted) at end of period.
Operating Highlights Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30, June 30, Sep 30, Sep 30, Sep 30,
2004 2004 2003 2004 2003
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Daily Sales Volumes
Natural gas (mmcf/day) 143.5 125.5 131.4 131.0 136.5
Crude oil (bbls/day) 8,447 7,699 7,913 8,005 8,091
Natural gas liquids
(bbls/day) 3,096 2,569 2,811 2,788 2,879
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Total (BOE/day) 35,460 31,185 32,623 32,626 33,722
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Realized Commodity
Prices(1) (Cdn $)
Natural gas ($/mcf) 6.14 6.59 5.59 6.42 6.21
Without hedging 6.31 6.82 5.93 6.57 6.83
Crude oil ($/bbl) 39.95 35.83 32.65 36.98 34.85
Without hedging 48.58 43.20 34.40 43.86 37.61
Natural gas liquids
($/bbl) 45.30 41.22 33.06 41.92 35.62
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Total ($ per BOE) 38.31 38.77 33.29 38.42 36.55
Without hedging 41.06 41.51 35.07 40.73 39.72
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(1) Includes hedging gains (losses)
Forward Looking Information
This MD&A contains forward-looking or outlook information with respect to
PrimeWest.
The use of any of the words "anticipate, "continue, "estimate", "expect",
"may", "will", "project", "should", "believe", "outlook" and similar
expressions are intended to identify forward-looking statements. These
statements involve known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from those
anticipated in our forward-looking statements. We believe the expectations
reflected in those forward-looking statements are reasonable. However, we
cannot assure you that these expectations will prove to be correct. You should
not unduly rely on forward-looking statements included in this report. These
statements are made as of the date of this MD&A.
In particular, this MD&A contains forward-looking statements pertaining
to the following:
- The quantity and recoverability of our reserves;
- The timing and amount of future production;
- Prices for oil, natural gas, and natural gas liquids produced;
- Operating and other costs;
- Business strategies and plans of management;
- Supply and demand for oil and natural gas;
- Expectations regarding our ability to raise capital and to add to our
reserves through acquisitions and exploration and development;
- Our treatment under governmental regulatory regimes;
- The focus of capital expenditures on development activity rather than
exploration;
- The sale, farming in, farming out or development of certain
exploration properties using third party resources;
- The objective to achieve a predictable level of monthly cash
distributions;
- The use of development activity and acquisitions to replace and add to
reserves;
- The impact of changes in oil and natural gas prices on cash flow after
hedging;
- Drilling plans;
- The existence, operation and strategy of the commodity price risk
management program;
- The approximate and maximum amount of forward sales and hedging to be
employed;
- The Trust's acquisition strategy, the criteria to be considered in
connection therewith and the benefits to be derived therefrom;
- The impact of the Canadian federal and provincial governmental
regulation on the Trust relative to other oil and gas issuers of
similar size;
- The goal to sustain or grow production and reserves through prudent
management and acquisitions;
- The emergence of accretive growth opportunities; and
- The Trust's ability to benefit from the combination of growth
opportunities and the ability to grow through the capital markets.
Our actual results could differ materially from those anticipated in
these forward-looking statements as a result of the risk factors set forth
below and elsewhere in this MD&A:
- Volatility in market prices for oil, natural gas and natural gas
liquids;
- Risks inherent in our oil and gas operations;
- Uncertainties associated with estimating reserves;
- Competition for, among other things: capital, acquisitions of
reserves, undeveloped lands and skilled personnel;
- Incorrect assessments of the value of acquisitions;
- Geological, technical, drilling and processing problems;
- General economic conditions in Canada, the United States and globally;
- Industry conditions, including fluctuations in the price of oil,
natural gas and natural gas liquids;
- Royalties payable in respect of PrimeWest's oil and gas production;
- Governmental regulation of the oil and gas industry, including
environmental regulation;
- Fluctuation in foreign exchange or interest rates;
- Unanticipated operating events that can reduce production or cause
production to be shut-in or delayed;
- Failure to obtain industry partner and other third party consents and
approvals, when required;
- Stock market volatility and market valuations;
- The need to obtain required approvals from regulatory authorities, and
- The other factors discussed under "Operational and Other Business
Risks" in this MD&A.
These factors should not be construed as exhaustive.
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer, Don Garner, and Chief Financial Officer,
Dennis Feuchuk, evaluated the effectiveness of PrimeWest Energy's disclosure
controls and procedures as of September 30, 2004 and concluded that PrimeWest
Energy's disclosure controls and procedures were effective to ensure that
information PrimeWest is required to disclose in its filings with the
Securities and Exchange Commission (SEC) under the Securities Exchange Act of
1934 (Exchange Act) is recorded, processed, summarized and reported, within
the time periods specified in the SEC's rules and forms, and to ensure that
information required to be disclosed by PrimeWest in the reports that it files
under the Exchange Act is accumulated and communicated to PrimeWest's
management, including its principal executive officer and principal financial
officer, as appropriate to allow timely decisions regarding required
disclosure.
Changes to Internal Controls and Procedures for Financial Reporting
There were no significant changes to PrimeWest's internal controls or in
other factors that could significantly affect these controls subsequent to the
evaluation date.
Vision, Core Business and Strategy
PrimeWest Energy Trust is a conventional oil and gas royalty trust
actively managed to generate monthly cash distributions for unitholders. The
Trust's operations are focused in Canada, with its assets concentrated in the
Western Canadian Sedimentary Basin. PrimeWest is one of North America's
largest natural gas weighted energy trusts.
Maximizing total return to unitholders, in the form of cash distributions
and change in unit price, is PrimeWest's overriding objective. Our strategies
for asset management and growth, financial management and corporate governance
are outlined in this MD&A, along with a discussion of our performance in the
third quarter of 2004 and our goals for the remainder of 2004 and beyond.
We believe that PrimeWest can maximize total return to unitholders
through the continued development of our core properties, making opportunistic
acquisitions that emphasize value creation, exercising disciplined financial
management which broadens access to capital while minimizing risk to
unitholders, and complying with strong corporate governance to protect the
interests of all stakeholders.
Asset Management and Growth
PrimeWest has a strategy to focus our expansion efforts on existing
Canadian core areas, and pursue field optimization within those core areas to
maximize asset value. We strive to control our operations whenever possible,
and maintain high working interests. Maintaining control of 80% of operations
allows us to use existing infrastructure and synergies within our core areas.
We believe this high level of operatorship can translate into control over
costs and timing of capital outlays and projects. We will continue to be an
opportunistic acquirer who uses the business cycles to make accretive
acquisitions. The current size of the Trust gives us the ability and critical
mass to make acquisitions of significant size, while still being able to add
value by transacting smaller acquisitions.
The acquisition of the Calpine assets, with current production volumes of
approximately 14,500 BOE per day added the equivalent of 4,700 BOE per day in
the third quarter of 2004. In addition, the 2004 capital program has been
increased by $35 million to develop some of the opportunities on Calpine lands
by year-end.
Assets acquired from Seventh Energy Ltd (Seventh) contributed 1,412 BOE
per day to production volumes in the third quarter of 2004. PrimeWest plans to
invest approximately $7 million during 2004 to develop the Seventh assets.
Financial Management
PrimeWest strives to maintain a conservative debt position, to allow us
to take advantage of opportunities that arise in the acquisition market, as
well as fund development activities. Our diversified debt instruments help to
reduce our reliance on the bank syndicate, as well as afford additional
foreign exchange protection because a portion of our debt, the secured notes,
are denominated in U.S. dollars. PrimeWest's commodity hedging approach helps
to stabilize cash flow, reduce volatility, and protect transaction economics.
PrimeWest continues to target a payout ratio between 70% and 90% of
annual cash flow to increase the Trust's financial flexibility. The third
quarter 2004 payout ratio was approximately 74%, and the retained cash flow
was utilized to fund the Trust's capital spending program. PrimeWest's debt to
cash flow level of 1.7 times for the third quarter is less than our internal
limit of 2.0 times.
PrimeWest's dual listing on both the Toronto Stock Exchange (TSX) and New
York Stock Exchange (NYSE) provide increased liquidity and a broadened
investor base. The NYSE listing enables U.S. unitholders to conveniently trade
in our Trust Units, and allows us to access the U.S. capital markets in the
future. Our status as a corporation for U.S. tax purposes simplifies tax
reporting for our U.S. unitholders.
For eligible Canadian unitholders, PrimeWest offers participation in the
Distribution Reinvestment Plan (DRIP), Premium Distribution Plan (PREP), and
Optional Trust Unit Purchase Plan (OTUPP), which represent a convenient way to
maximize an investment in PrimeWest. For alternate investment styles,
PrimeWest also has Exchangeable Shares available, which permit participation
in PrimeWest without the ongoing tax implications associated with receiving a
distribution.
Corporate Governance
PrimeWest remains committed to the highest standards of corporate
governance and upholds the rules of the governing regulatory bodies under
which it operates. Full disclosure of our compliance with existing corporate
governance rules and regulations is available on our website at
www.primewestenergy.com. PrimeWest actively monitors the corporate governance
and disclosure environment to ensure compliance with current and future
requirements.
Our high standards of corporate governance are not limited to the
boardroom. At the field level PrimeWest proactively manages environmental,
health and safety issues. We place a great deal of importance on community
involvement and maintaining good relationships with landowners.
Outlook - 2004
PrimeWest expects full year 2004 production volumes to average
approximately 35,500 BOE per day. Full year operating costs are expected to be
approximately $6.70 per BOE. PrimeWest expects to invest approximately
$125 million in its capital development program, with the focus primarily in
the core areas of Caroline, Valhalla, Brant/Farrow and Princess/Hays.
The taxability of 2004 distributions for U.S. unitholders cannot be
accurately estimated at this time, but will be confirmed after year-end. For
residents of the U.S., Canadian withholding tax of 15% applies to the
distribution. In addition, the Canadian Federal Government announced a
proposal on March 23, 2004, that would expand Canadian withholding tax on
non-Canadian residents (15% for U.S. unitholders) by applying it to both the
"taxable income" portion, as well as the return of capital portion of the
distributions effective January 1, 2005. A withholding tax of 15% has always
been applied by PrimeWest to the total value of distributions paid to U.S.
unitholders, however, the tax withheld on the return of capital portion has
been refundable. As of September 30, 2004, non-resident ownership of PrimeWest
was approximately 60%. For more details on withholding tax, please visit our
website at www.primewestenergy.com.
On September 16, 2004, the Canadian Federal Government tabled specific
legislation relevant to the budget announcement of March 23, 2004, which
proposed changes to non-resident withholding taxes and the placement of
non-resident ownership restrictions upon the income trust sector. These
legislative proposals would require a Canadian income trust to maintain at
least 50% Canadian ownership on the basis of fair market value. Under the
terms of the proposed legislation because PrimeWest's non-resident ownership
exceeded 50% as at March 22, 2004, PrimeWest has until January 1, 2007 to
conform to the new proposed requirements. PrimeWest is actively supporting the
efforts of the Canadian Association of Income Funds to have the proposed
legislation modified or withdrawn. We will endeavor to keep our unitholders
informed of the status of this legislation.
Cash Flow Reconciliation
($ millions)
-----------------------------------------------------------------
Second quarter 2004 cash flow from operations $ 58.2
Volumes 17.6
Commodity prices (1.4)
Net hedging change from prior quarter (1.2)
Operating expenses (1.8)
Royalties (3.2)
Other 0.1
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Third quarter 2004 cash flow from operations $ 68.3
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The above table includes non-GAAP measurements which may not be
comparable to other companies.
A key performance driver for the Trust is cash flow from operations,
which directly affects PrimeWest's ability to pay monthly distributions. Cash
flow is generated through the production and sale of crude oil, natural gas
and natural gas liquids, and is dependent on production levels, commodity
prices, operating expenses, hedging gains or losses, royalties and currency
exchange rates. Some of these factors are uncontrollable from PrimeWest's
perspective such as commodity prices, the currency exchange rate and
royalties. Other factors that are controllable by PrimeWest are production
levels and operating expenses, as well as interest and general and
administrative (G&A) expenses. It is expected that these factors will impact
cash flows in the future.
Quarterly Performance
($ millions, 2004 2003 2002
except per Trust -------------------------------------------------------
Unit amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
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Net Revenues 97.2 84.9 85.7 73.0 77.2 85.6 94.0 68.8
Net Income 20.2 22.4 20.1 (0.7) 7.0 61.4 22.4 (7.3)
Net Income Per
Unit - Basic 0.31 0.41 0.40 (0.01) 0.15 1.34 0.53 (0.20)
Net Income Per
Unit - Diluted 0.31 0.40 0.40 (0.01) 0.15 1.33 0.53 (0.20)
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The above table highlights PrimeWest's performance for the third quarter
ended 2004, and the preceding seven quarters through 2003 and 2002.
Net revenues are primarily impacted by commodity prices, production
volumes and royalties.
Net income and net income per unit are secondary measures for a royalty
trust because they include both cash and non-cash items. The non-cash items
such as depletion, depreciation and amortization (DD&A), future income taxes,
unrealized foreign exchange gains or losses, and unrealized gains or losses on
derivatives will not affect PrimeWest's ability to pay a monthly distribution.
Capital Expenditures
Three Months Ended Nine Months Ended
------------------------------------------------
($ millions, Sep 30, June 30, Sep 30, Sep 30, Sep 30,
except per BOE) 2004 2004 2003 2004 2003
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Land & lease
acquisitions $ 2.0 $ 2.7 $ 1.6 $ 6.5 $ 3.9
Geological and geophysical 3.3 0.8 0.4 5.8 1.4
Drilling and completions 12.0 9.0 18.9 39.8 41.5
Investment in facilities
Equipping & tie-in 1.0 2.8 - 7.8 6.7
Compression & processing 1.3 0.5 2.0 3.8 4.7
Gas gathering 1.8 0.2 3.0 2.5 7.0
Production facilities 3.6 5.1 4.6 10.8 7.4
Capitalized G&A 0.4 0.6 0.3 1.4 0.8
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Development capital 25.4 21.7 30.8 78.4 73.4
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Corporate/property
acquisitions 767.0 0.4 1.3 806.0 207.0
Dispositions (6.3) (1.6) (0.6) (11.3) (0.8)
Head office equipment 0.6 0.5 - 1.2 0.1
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Total $ 786.7 $ 21.0 $ 31.5 $ 874.3 $ 279.7
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During the third quarter of 2004, PrimeWest's capital expenditures
totaled $786.7 million, compared to $31.5 million invested in the same quarter
the previous year. Development capital of $25.4 million invested in the third
quarter 2004 was lower than the third quarter 2003 investment of
$30.8 million. Of the $25.4 million in development capital, $13.0 million or
51% was spent on drilling, completions and tie-ins that contribute to new
reserve additions and help offset natural production decline. In the third
quarter, PrimeWest's capital spending was focused primarily in the areas of
Caroline, Brant Farrow, and Valhalla. Gross wells drilled in the third quarter
totaled 23 (15 net wells), with a success rate of approximately 91%. Year to
date 70 gross wells (46 net wells) have been drilled with a success rate of
approximately 90%.
Compared to the second quarter of 2004, development capital spending of
$25.4 million in the third quarter of 2004 was higher due to a higher level of
drilling activity. Corporate acquisitions in 2003 included the purchase of two
private Canadian companies. In 2004 PrimeWest completed the corporate
acquisition of Seventh Energy and the asset acquisition of Calpine Canada.
Through acquisitions as well as development drilling, workovers, and
recompletion activities, PrimeWest strives to offset the natural production
decline and add to reserves in an effort to sustain cash flows. Capital
resources are allocated by projects on the basis of anticipated rate of
return. At PrimeWest, every capital project is measured against stringent
economic evaluation criteria prior to approval that include expected return,
risks and further development opportunities.
Assets
Since inception, PrimeWest has focused on the conventional oil and
natural gas plays of the Western Canadian Sedimentary Basin. Within this
focused area, we have a diversified, multi-zone suite of assets stretching
from northeast B.C., across much of Alberta and down through southwest
Saskatchewan. We believe this diversity reduces risks to overall corporate
production and cash flow, while the core area focus allows us to capitalize on
our existing technical knowledge in each of the core areas.
Production Volumes
Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30, June 30, Sep 30, Sep 30, Sep 30,
2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Natural gas (mmcf/day) 143.5 125.5 131.4 131.0 136.5
Crude oil (bbls/day) 8,447 7,699 7,913 8,005 8,091
Natural gas liquids
(bbls/day) 3,096 2,569 2,811 2,788 2,879
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Total (BOE/day) 35,460 31,185 32,628 32,626 33,722
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Gross Overriding Royalty
volumes included above
(BOE/day) 1,404 1,355 1,270 1,371 1,607
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All production information is reported before the deduction of crown and
freehold royalties.
PrimeWest's production volumes in the third quarter increased when
compared with the second quarter of 2004 due to additional volumes contributed
by the Calpine assets. PrimeWest's development activity also added volumes,
which partially offset natural production decline. Compared to the first nine
months of 2003, production was 3% lower, attributable to production decline,
and offset by development and acquisition volume additions.
In the second quarter of 2004, the Alberta Energy and Utilities Board
ruled on the natural gas over bitumen issue, which resulted in approximately
330 BOE per day of production at Ells being permanently shut-in effective
July 1, 2004. The impact of this shut-in has been factored into PrimeWest's
2004 full year production guidance. Working with the operator, PrimeWest
intends to seek compensation for the shut-in production from the Province of
Alberta.
Production at PrimeWest's non-operated Whiskey Creek area is expected to
remain restricted for the remainder of 2004 due to capacity constraints in
third party facilities.
PrimeWest expects full year 2004 production to average approximately
35,500 BOE per day. This estimate incorporates PrimeWest's expected natural
production decline and the production volume shut-ins described above, offset
by production additions from the capital development program, acquired
production from the Calpine and Seventh Energy acquisitions and other property
acquisitions.
Commodity Prices
Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30, June 30, Sep 30, Sep 30, Sep 30,
Benchmark Prices 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Natural gas ($/Mcf AECO) 6.66 6.80 6.29 6.69 7.07
Crude oil (U.S.$/bbl WTI) 43.88 38.32 30.20 39.11 30.99
-------------------------------------------------------------------------
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Average realized prices in the market place are indicated by these
benchmark prices
Average Realized Sales Prices
Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30, June 30, Sep 30, Sep 30, Sep 30,
(Canadian Dollars) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Natural gas ($/Mcf)(1)(2) 6.14 6.59 5.59 6.42 6.21
Without hedging 6.31 6.82 5.93 6.57 6.83
Crude oil ($/bbl)(1) 39.95 35.83 32.65 36.98 34.85
Without hedging 48.58 43.20 34.40 43.86 37.61
Natural gas liquids
($/bbl) 45.30 41.22 33.06 41.92 35.62
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Total Oil Equivalent(2)
($/BOE) 38.31 38.77 33.29 38.42 36.55
Without hedging 41.06 41.51 35.07 40.73 39.72
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Realized hedging loss
included in prices
above ($/BOE) (2.75) (2.74) (1.78) (2.31) (3.17)
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(1) Includes hedging gains / losses.
(2) Excludes sulphur.
Canadian commodity prices were higher in the third quarter 2004 than
during the same period in 2003 resulting in higher average realized selling
prices per BOE.
The realized selling price in Canadian dollars is impacted by currency
exchange rates. Oil and gas prices are denominated in U.S. dollars, therefore,
a strengthened Canadian dollar translates into lower realized prices and lower
Canadian revenue for producers.
Compared to the second quarter 2004, average realized sales prices per
BOE decreased marginally in the third quarter 2004 due to lower average price
for natural gas, partially offset by higher crude oil and natural gas liquids
prices.
PrimeWest's cash flow from operations is directly impacted by commodity
prices, but the use of hedging can increase or decrease the prices realized by
the Trust. In the third quarter of 2004, PrimeWest had a $9.0 million hedging
loss compared to a loss of $5.4 million for the same period in 2003.
As of the end of the third quarter 2004 year-to-date, hedging losses
total $20.6 million compared to hedging losses of $29.2 million for the same
period of 2003.
The following table sets forth benchmark historical and estimated future
commodity prices.
Benchmark
Commodity Prices Past Four Quarters Next Four Quarters
(Actual) (Forward Markets)(1)
-------------------------------------------- ---------------------------
Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
2003 2004 2004 2004 2004 2005 2005 2005
-------------------------------------------- ---------------------------
Natural gas
NYMEX
($U.S./mcf) 4.58 5.69 5.97 5.84 6.63 7.92 6.49 6.46
AECO ($Cdn/mcf) 5.59 6.61 6.80 6.66 7.09 8.74 7.07 7.17
Crude oil WTI
($U.S./bbl) 31.18 35.15 38.32 43.88 48.96 47.08 45.17 43.59
-------------------------------------------- ---------------------------
-------------------------------------------- ---------------------------
(1) As at September 30, 2004
Sales Revenue
Three Months Ended Nine Months Ended
-------------------------------------------------------------
Revenue Sep 30, % of June 30, % of Sep 30, % of Sep 30, Sep 30,
($ millions) 2004 total 2004 total 2003 total 2004 2003
-------------------------------------------------------------------------
Natural
gas(1) $ 81.0 65% $ 75.3 68% $ 67.6 68% $ 230.4 $ 231.5
Crude oil 31.1 25% 25.1 23% 23.8 24% 81.1 77.0
Natural gas
liquids 12.9 10% 9.6 9% 8.6 8% 32.0 28.0
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Total $ 125.0 100% $ 110.0 100% $ 100.0 100% $ 343.5 $ 336.5
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Hedging
(losses)/
gains
included
above(2) $ (9.0) $ (7.8) $ (5.4) $(20.6) $(29.2)
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(1) Excludes sulphur.
(2) Net of amortized premiums.
Third quarter 2004 revenues were 25% higher than the same period in 2003,
due to higher commodity prices and increased production volumes. Revenues are
higher in the third quarter 2004 compared to the second quarter 2004 due to
the higher volumes from the Calpine acquisition partially offset by lower
natural gas prices. Revenues are higher in the first nine months of 2004
compared to the same period in 2003 due to higher commodity prices, partially
offset by reduced production volumes.
Since a greater portion of PrimeWest's revenues (65%) are derived from
natural gas, the Trust has greater sensitivity to changes in natural gas
prices than crude oil prices.
Financial Derivatives
As part of our financial management strategy, PrimeWest uses a consistent
commodity hedging approach. The purpose of the hedging program is to reduce
volatility in cash flows, protect acquisition economics and to stabilize cash
flow against the unpredictable commodity price environment. PrimeWest's
hedging program delivered gains of $17 million over the period from January 1,
2001 to September 30, 2004. The hedging policy reflects a willingness to risk
forfeiting a portion of the pricing upside in return for protection against a
significant downturn in prices.
Approximate percentage of future anticipated production volumes hedged at
September 30, 2004, net of anticipated royalties, reflecting full production
declines with no offsetting additions:
---------------------------------------------------------
Q4/04 Q1/05 Q2/05 Q3/05 Q4/05 Q1/06
-------------------------------------------------------------------------
Crude Oil 60% 51% 47% 35% 30% 0%
Natural Gas 64% 58% 49% 50% 50% 35%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
PrimeWest generally sells its oil and gas under short-term market-based
contracts. Derivative financial instruments, options and swaps may be used to
hedge the impact of oil and gas price fluctuations.
A listing of these contracts in place at September 30, 2004 follows:
Crude Oil ($U.S./bbl)
-------------------------------------------------------------------------
Period Volume (bbls/d) Type WTI Price
($U.S./bbl)
-------------------------------------------------------------------------
Oct - Dec 2004 500 Swap 26.00
Oct - Dec 2004 500 Swap 27.03
Oct - Dec 2004 500 Swap 28.53
Oct - Dec 2004 500 Swap 30.10
Oct - Dec 2004 500 Costless Collar 24.00/30.00
Oct - Dec 2004 500 Costless Collar 25.00/28.30
Oct - Dec 2004 500 Costless Collar 26.00/32.72
Oct - Dec 2004 500 Costless Collar 40.00/44.75
Oct - Dec 2004 500 Costless Collar 40.00/45.90
Oct - Dec 2004 500 Costless Collar 40.00/56.25
Jan - Mar 2005 500 Swap 27.25
Jan - Mar 2005 500 Swap 28.60
Jan - Mar 2005 500 Swap 30.00
Jan - Mar 2005 500 Costless Collar 28.00/34.35
Jan - Mar 2005 500 3 Way 25.00/30.00/35.50
Jan - Mar 2005 500 Costless Collar 35.00/49.80
Jan - Mar 2005 500 Costless Collar 35.00/50.00
Jan - Mar 2005 500 Costless Collar 40.00/51.50
Apr - Jun 2005 500 Swap 27.07
Apr - Jun 2005 500 Swap 28.50
Apr - Jun 2005 500 Swap 30.00
Apr - Jun 2005 500 3 Way 25.00/30.00/36.75
Apr - Jun 2005 500 Costless Collar 35.00/47.00
Apr - Jun 2005 500 Costless Collar 35.00/46.90
Apr - Jun 2005 500 Costless Collar 37.50/50.90
Jul - Sep 2005 500 Swap 27.05
Jul - Sep 2005 500 Swap 28.50
Jul - Sep 2005 500 Costless Collar 35.00/44.90
Jul - Sep 2005 500 Costless Collar 35.00/44.35
Jul - Sep 2005 500 Costless Collar 35.00/51.30
Oct - Dec 2005 500 Swap 27.18
Oct - Dec 2005 500 Costless Collar 35.00/42.80
Oct - Dec 2005 500 Costless Collar 35.00/42.40
Oct - Dec 2005 500 Costless Collar 35.00/48.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural Gas (Cdn$/Mcf)
-------------------------------------------------------------------------
Period Volume (mmcf/d) Type AECO Price
(Cdn$/mcf)
-------------------------------------------------------------------------
Jan 2004 - Oct 2004 9.5 3 Way 3.17/4.22/6.09
Jan 2004 - Dec 2004 1.0 Swap 6.02
Apr 2004 - Oct 2004 4.7 Swap 5.45
Apr 2004 - Oct 2004 4.7 Swap 6.02
Apr 2004 - Oct 2004 4.7 Swap 6.06
Apr 2004 - Oct 2004 4.7 Costless Collar 5.01/6.06
Apr 2004 - Oct 2004 4.7 Costless Collar 5.28/7.39
Apr 2004 - Oct 2004 4.7 Swap 6.25
Apr 2004 - Oct 2004 4.7 Swap 6.20
Oct 2004 - Dec 2004 10.0 Costless Collar 6.33/8.20
Oct 2004 - Dec 2004 10.0 Costless Collar 6.33/7.91
Oct 2004 - Dec 2004 10.0 Costless Collar 6.33/7.68
Oct 2004 - Dec 2004 10.0 Costless Collar 6.33/8.19
Oct 2004 - Dec 2004 10.0 Costless Collar 6.33/8.65
Oct 2004 - Dec 2004 5.0 Costless Collar 5.80/6.99
Oct 2004 - Dec 2004 5.0 Costless Collar 5.80/7.29
Nov 2004 - Dec 2004 5.0 Costless Collar 6.33/9.76
Nov 2004 - Mar 2005 4.7 Costless Collar 5.80/7.91
Nov 2004 - Mar 2005 4.7 Swap 6.71
Nov 2004 - Mar 2005 4.7 Costless Collar 6.33/11.87
Nov 2004 - Mar 2005 4.7 Costless Collar 6.86/11.61
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/11.18
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/10.76
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/10.55
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/12.13
Jan 2005 - Mar 2005 5.0 3 Way 5.28/6.33/10.44
Jan 2005 - Mar 2005 5.0 3 Way 5.28/6.33/10.35
Jan 2005 - Mar 2005 5.0 3 Way 5.28/6.33/12.53
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.75
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.63
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.49
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.84
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/7.85
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/6.99
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/7.09
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/7.44
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.81
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.66
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.53
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.86
Jul 2005 - Sep 2005 2.4 Costless Collar 6.33/7.88
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/7.50
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/7.60
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/7.79
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.97
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.71
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.60
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.96
Oct 2005 - Dec 2005 5.0 3 Way 5.28/6.33/9.92
Oct 2005 - Dec 2005 5.0 3 Way 5.28/6.33/9.76
Oct 2005 - Dec 2005 5.0 3 Way 5.28/6.33/10.04
Jan 2006 - Mar 2006 10.0 Costless Collar 6.33/10.55
Jan 2006 - Mar 2006 10.0 Costless Collar 6.33/10.22
Jan 2006 - Mar 2006 10.0 Costless Collar 6.33/9.96
Jan 2006 - Mar 2006 5.0 Costless Collar 6.33/10.42
------------------------------------------------------------------------
------------------------------------------------------------------------
A 3-way option is like a traditional collar, except that PrimeWest has
resold the put at a lower price. Utilizing the first 3-way natural gas
contract above as an example, PrimeWest has sold a call at $6.09, purchased a
put at $4.22, and resold the put at $3.17. Should the market price drop below
$4.22,PrimeWest will receive $4.22 until the price is less than $3.17, at
which time PrimeWest would then receive market price plus $1.05. However,
should market prices rise above $6.09, PrimeWest would receive a maximum of
$6.09. Should the market price remain between $4.22 and $6.09, PrimeWest would
receive the market price.
Natural Gas Basis Differential
-------------------------------------------------------------------------
Period Volume (mmcf/day) Type Basis Price
($U.S./mcf)
-------------------------------------------------------------------------
Apr - Oct 2004 5 Basis Swap $0.71
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The AECO basis is the difference between the NYMEX gas price in $U.S. per
Mcf and the AECO price in $U.S. per Mcf. Using the basis swap above as an
example, PrimeWest has fixed this price difference between the two markets at
$U.S. 0.71 per Mcf from April 2004 through October 2004. If the NYMEX price
for the period turned out to be $U.S. 5.00 per Mcf, PrimeWest would receive an
AECO equivalent price of $U.S. 4.29 per Mcf.
Electrical Power
Period Power Amount (MW) Type Price ($/MW-hr)
-------------------------------------------------------------------------
Q4 2004 10 Fixed Price Swap 44.83
Calendar 2005 5 Fixed Price Swap 51.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CICA Accounting Guideline 13 (AcG-13), "Hedging Relationships," became
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
establishes 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 positions hedged with derivatives. PrimeWest is not
applying hedge accounting to its hedging relationships. As a result,
PrimeWest's derivatives are marked-to-market with the resulting gain or loss
reflected in earnings for the reporting period.
As of September 30, 2004, PrimeWest had an outstanding derivative loss of
$0.5 million, relating to transitional provisions, comprised of a $0.5 million
loss for crude oil, a $0.2 million loss for natural gas and a $0.2 million
gain for electrical power. The derivative loss is shown as a current asset on
the balance sheet. The loss will continue to be amortized to earnings upon
settlement of the corresponding hedges that are expected to expire by March
2005.
The unrealized loss on derivatives on the income statement results from
the change in the mark-to-market valuation of the derivative financial
instruments during the period. It represents the loss that would be incurred
if the contracts were settled on the period end date. The unrealized loss on
derivatives for the nine months ended September 30, 2004, was $28.8 million.
The loss was comprised of a $20.3 million loss for crude oil, an $8.6 million
loss for natural gas and a $0.1 million gain for electrical power.
The $14.7 million unrealized derivative loss for the three months ended
September 30, 2004, was comprised of a $10.0 million loss on crude oil, a
$4.4 million loss on natural gas and a $0.3 million loss on electrical power.
The mark-to-market valuation of the derivatives in place at September 30,
2004, was a $29.3 million loss consisting of a $20.8 million loss in crude
oil, an $8.9 million loss in natural gas and a $0.4 million gain on electrical
power. $26.9 million of the derivative loss is shown as a current liability on
the balance sheet as these derivatives will be settled in the next twelve
months. The remaining liability of $2.4 million is reported as a long-term
derivative liability.
For the three months ended September 30, 2004, the cash impact of
contracts settling was an $8.8 million loss consisting of a $6.7 million loss
in crude oil, a $2.3 million loss in natural gas and a $0.2 million gain on
electrical power. For the nine months ended September 30, 2004 the cash impact
of contracts settling was a $20.7 million loss comprised of a $15.1 million
loss in crude oil, a $5.5 million loss in natural gas, a $0.6 million gain on
electrical power and a $0.7 million loss in interest rate swaps.
Royalties (Net of ARTC)
Royalties are paid by PrimeWest to the owners of mineral rights with whom
PrimeWest holds leases. PrimeWest has mineral leases with the Crown
(Provincial and Federal Governments), freeholders (individuals or other
companies) and other operators. ARTC is the Alberta Royalty Tax Credit, a tax
rebate provided by the Alberta government to producers that paid eligible
Crown royalties in the year.
Three Months Ended Nine Months Ended
------------------------------------------------
($ millions, except Sep 30, June 30, Sep 30, Sep 30, Sep 30,
per BOE) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Royalty expense
(net of ARTC) $ 28.9 $ 25.7 $ 23.1 $ 78.0 $ 80.8
Per BOE $ 8.86 $ 9.06 $ 7.70 $ 8.72 $ 8.77
-------------------------------------------------------------------------
Royalties as % of
sales revenues
With hedge loss 23.1% 23.4% 23.1% 22.7% 24.0%
Excluding hedge loss 21.6% 21.8% 21.9% 21.4% 22.1%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Royalty expense in the third quarter of 2004 were approximately 25%
higher than the same period the previous year due to overall higher commodity
prices and volumes. For the first nine months of 2004, royalties were
$78 million, lower than the same period in 2003 due to lower year-to-date
production volumes and offset by higher commodity prices in 2004.
Royalty rates are based on commodity prices; therefore future changes to
prices will be accompanied by changes in royalty expense.
Operating Expenses
Three Months Ended Nine Months Ended
------------------------------------------------
($ millions, except Sep 30, June 30, Sep 30, Sep 30, Sep 30,
per BOE) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Operating expense
($ millions) $ 21.4 $ 19.6 $ 17.2 $ 60.6 $ 58.2
Per BOE $ 6.56 $ 6.89 $ 5.73 $ 6.78 $ 6.32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Compared to the second quarter of 2004, PrimeWest's total operating
expenses for the third quarter 2004 are higher as a result of the Calpine
asset acquisition, which added $2.8 million of expenses in the quarter. On a
gross and per BOE basis, operating costs are higher in the third quarter in
2004 compared to the same quarter in the previous year due to the Calpine
acquisition and well workovers of $0.7 million in 2004. Operating expenses are
higher for the nine months of 2004 compared to 2003 as a result of the Calpine
acquisition adding approximately $2.8 million and the Seventh Energy
acquisition adding approximately $2.2 million, offset by lower power costs in
2004.
Operating Expenses Outlook
Operating costs for the year are expected to be higher than in 2003, and
PrimeWest expects 2004 operating expenses to be approximately $6.70 per BOE.
Operating Margin
Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30, June 30, Sep 30, Sep 30, Sep 30,
($/BOE) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Sales price and other
revenue(1) $ 38.65 $ 38.96 $ 33.40 $ 38.68 $ 36.68
Royalties 8.86 9.06 7.70 8.72 8.77
Operating expenses 6.56 6.89 5.73 6.78 6.32
-------------------------------------------------------------------------
Operating margin $ 23.23 $ 23.01 $ 19.97 $ 23.18 $ 21.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes hedging and sulphur
Operating margin per BOE increased 16% during the third quarter 2004
compared to the same quarter in 2003. This is primarily due to higher sales
prices offset by higher operating expenses and higher royalties. Operating
margin is an important measure of our business because it gives an indication
of the amount of cash flow PrimeWest realizes per barrel of oil equivalent
that is produced, before head office expenses and financing charges.
Operating margin increased in the third quarter compared to the second
quarter of 2004, primarily as a result of slightly lower operating expenses
and royalties. Compared to the first nine months of 2003, operating margin for
2004 year to date is approximately 7% higher.
Based on PrimeWest's outlook on commodity prices, the Canadian/U.S.
dollar exchange rate, operating expense expectations and hedge positions,
margins are expected to be higher in 2004 than 2003. PrimeWest will continue
to focus on achieving lower than average operating expenses to maximize
margins, which can reduce the volatility of cash flows through commodity price
cycles.
General & Administrative Expense
Three Months Ended Nine Months Ended
-------------------------------------------------
($ millions, except Sep 30, June 30, Sep 30, Sep 30, Sep 30,
per BOE) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Cash G&A expense
($ millions) $ 3.4 $ 3.5 $ 3.5 $ 11.1 $ 10.5
Per BOE $ 1.03 $ 1.23 $ 1.15 $ 1.24 $ 1.14
Non-cash G&A expense
($ millions) $ 14.1 $ (7.3) $ 2.3 $ 7.2 $ 5.9
Per BOE $ 4.31 $ (2.57) $ 0.76 $ 0.80 $ 0.64
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash G&A expense in the third quarter 2004 decreased approximately 16% on
a per BOE basis from the previous quarter and 10% from the same period in 2003
due to higher production volumes as a result of the Calpine asset acquisition.
The increase in the year-to-date cash G&A compared to the same period in
2003 is mainly due to increases in salaries and information technology
expenditures offset by higher overhead recoveries.
PrimeWest's non-cash G&A expenses (on a total and per BOE basis)
increased in the third quarter of 2004 and on a year-to-date basis compared to
the same period in 2003. The increase is due to a higher average Unit
Appreciation Rights (UARs) value under PrimeWest's Long-Term Incentive Plan
(LTIP).
Non-cash G&A expense consists mainly of the change in the value of the
UARs. UARs in a trust are similar to stock options in a corporation.
Consistent with the resolution approved by unitholders at the last annual
meeting of unitholders, PrimeWest continues to pay for the exercise of UARs in
Trust Units. The program rewards employees based on total unitholder return,
which is comprised of cumulative distributions on a reinvested basis plus
growth in unit price. No benefit accrues to employees who hold UARs until the
unitholders have first achieved a 5% total annual return from the time of
grant. Expenses related to the LTIP are recorded on a mark-to-market basis,
whereby increases or decreases in the valuation of the UAR liability are
reported quarterly, as a charge to the income statement.
G&A Expense Outlook
Cash G&A expenses in 2004 are expected to be higher than in 2003 and are
expected to be approximately $1.25 per BOE for the year.
Interest Expense
Three Months Ended Nine Months Ended
------------------------------------------------
($ millions, except Sep 30, June 30, Sep 30, Sep 30, Sep 30,
per Trust Unit) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Interest expense $ 2.9 $ 2.8 $ 4.0 $ 8.9 $ 11.0
Period end net debt
level $ 464.8 $ 169.2 $ 233.4 $ 464.8 $ 233.4
Debt per Trust Unit $ 5.84 $ 2.97 $ 4.68 $ 5.84 $ 4.68
-------------------------------------------------------------------------
Average cost of debt 3.9% 4.4% 4.7% 4.2% 4.5%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest expense, representing interest on bank debt and private
placement debt, decreased in the third quarter and year-to-date 2004 compared
to the same periods in 2003, due to lower average interest rates and a lower
debt balance. Interest expense excludes any interest owing on the Convertible
Unsecured Subordinated Debentures.
The significant increase in the net debt level at September 30, 2004
compared to prior periods is due to the drawdown on the credit facility
relating to the acquisition of the Calpine assets and 25% interest in Calpine
Natural Gas Trust.
In May of 2003, PrimeWest closed a private placement debt financing of
$U.S. 125 million at a U.S. fixed coupon rate of 4.19%, successfully
diversifying its debt. The actual Canadian interest expense on the $U.S. debt
will fluctuate with any changes in the Canadian/U.S. foreign exchange rates.
Canadian interest rates are expected to be lower through 2004 compared to
2003.
Foreign Exchange Gain
The foreign exchange gain of $9.0 million for the three months ended
September 30, 2004 and $4.1 million for the nine months ended September 30,
2004, results from the translation of the U.S. dollar denominated secured
notes issued under the private placement and related interest payable in
Canadian dollars.
Depletion, Depreciation and Amortization
Three Months Ended Nine Months Ended
------------------------------------------------
($ millions, except Sep 30, June 30, Sep 30, Sep 30, Sep 30,
per BOE) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Depletion, depreciation
and amortization $ 50.2 $ 41.4 $ 50.7 $ 133.4 $ 153.3
-------------------------------------------------------------------------
$/BOE $ 15.41 $ 14.59 $ 16.91 $ 14.92 $ 16.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The third quarter 2004 DD&A rate of $15.41 per BOE is lower than the 2003
third quarter rate of $16.91 per BOE due to the January 1, 2004 ceiling test
write down of $309 million. This write down also had the same effect on the
full year rate per BOE. DD&A rate per BOE increased in the third quarter of
2004 versus the previous quarter as a result of a higher DD&A rate associated
with the Calpine asset acquisition, which closed on September 2, 2004.
Ceiling Test
Effective January 1, 2004, PrimeWest has adopted CICA Accounting
Guideline 16 (AcG-16), "Oil and Gas Accounting - Full Cost". This new standard
replaces the CICA Accounting Guideline 5 (AcG-5), "Full Cost Accounting in the
Oil and Gas Industry".
Under AcG-5, the cost recovery test is calculated based on undiscounted
future net revenues for proved reserves, less general and administrative
expenses, site restoration, future financing costs and applicable taxes. The
aggregate result is limited to capitalized costs, less accumulated depletion
and site restoration, the lower of cost and market value of unproved land and
future income taxes. The cost recovery test is based on costs and commodity
prices existing at the balance sheet date.
AcG-16 impacts the application of the cost centre impairment test
(ceiling test). The guideline is effective for fiscal years beginning on or
after January 1, 2004. The cost impairment test is now a two stage process
which is to be performed at least annually. The first stage of the test
determines if the cost pool is impaired. An impairment loss exists when the
carrying amount of an asset is not recoverable and exceeds its fair value. The
carrying amount is not recoverable if it exceeds the sum of the undiscounted
cash flows from Proved reserves plus unproved properties using management's
best estimate of future prices. The second stage determines the amount of the
impairment loss to be recorded. The impairment is measured as the amount by
which the carrying amount of capitalized assets exceeds the future discounted
cash flows from Proved plus Probable reserves. The discount rate used is the
risk free rate.
Performing this test at January 1, 2004, using consultant's average
prices as at January 1, 2004 of AECO $5.90 per Mcf for natural gas and
$U.S. 29.21 per barrel WTI for crude oil resulted in a before tax impairment
of $308.9 million, and an after tax impairment of $233.2 million. The write
down was booked to accumulated income in the first quarter of 2004.
Site Reclamation and Restoration Reserve
Since the inception of the Trust, PrimeWest has maintained a site
reclamation fund to pay for future costs related to well abandonment and site
clean up. The fund is used to pay for such costs as they are incurred. The
2004 contribution rate for the fund is unchanged from 2003 at $0.50 per BOE,
which is expected to be sufficient to meet expenditure requirements for the
future. As at September 30, 2004, $10.4 million is residing in the site
reclamation fund.
The reclamation and abandonment costs in the third quarter of 2004 were
$1.1 million, compared to $0.4 million for the same period in 2003, and
$0.3 million for the previous quarter.
Asset Retirement Obligation
PrimeWest adopted the new CICA Handbook section 3110, "Asset Retirement
Obligations" in the first quarter of 2004. This standard focuses on the
recognition and measurement of liabilities related to legal obligations
associated with the retirement of property, plant and equipment. Under this
standard, these obligations are initially measured at fair value and
subsequently adjusted for the accretion of discount and any changes in the
underlying cash flows. The asset retirement cost is capitalized to the related
asset and amortized into earnings over time.
Income and Capital Taxes
Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30, June 30, Sep 30, Sep 30, Sep 30,
($ millions) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Income and capital taxes $ 1.1 $ 0.5 $ 0.8 $ 1.9 $ 3.5
Future income taxes
recovery (22.3) (3.4) (8.7) (44.0) (71.1)
-------------------------------------------------------------------------
Total: $ (21.2) $ (2.9) $ (7.9) $ (42.1) $ (67.6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash taxes paid $ 0.8 $ 1.3 $ 2.6 $ 3.1 $ 3.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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. The increase in the future income tax recovery in
the third quarter of 2004 versus the prior quarter and the same period in 2003
is due to the increase in the derivative liability and Long-Term Incentive
Plan liability.
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 nine months ending September 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 nine months ended September 30, 2004 include a recovery of
$0.4 million related to prior years.
Net Income
Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30, June 30, Sep 30, Sep 30, Sep 30,
($ millions) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Net income $ 20.2 $ 22.4 $ 7.0 $ 62.8 $ 90.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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, the unrealized loss on derivatives, future taxes and non-cash G&A.
Net income for the third quarter of 2004 was slightly lower than the
second quarter of 2004 but higher than the third quarter of 2003. Third
quarter 2004 net income was impacted by non-cash G&A expenses of $14.1 million
and an unrealized loss on derivatives of $14.7 million offset by future income
tax recoveries of $22.3 million and foreign exchange gains of $9.0 million.
Net income for the nine months ended September 30, 2004, is lower than
the same period in 2003 due to higher operating expenses, an unrealized loss
on derivatives, reduced future income tax recoveries, offset by higher net
revenues and lower DD&A.
Liquidity & Capital Resources
Long Term Debt
As at
----------------------------------------------
($ millions) Sep 30, 2004 June 30, 2004 Sep 30, 2003
-------------------------------------------------------------------------
Long-term debt $ 461.7 $ 179.7 $ 247.7
Deficit / (working capital)
(2) 3.1 (10.5) (14.3)
-------------------------------------------------------------------------
Net debt $ 464.8 $ 169.2 $ 233.4
Market value of Trust Units
and Exchangeable Shares
outstanding(1)(3) 1,861.5 1,321.6 1,247.3
-------------------------------------------------------------------------
Total capitalization $ 2,326.3 $ 1,490.8 $ 1,480.7
-------------------------------------------------------------------------
Net debt as a % of total
capitalization 20.0% 11.3% 15.8%
-------------------------------------------------------------------------
(1) Based on September 30, 2004 Trust Unit closing price of $26.70 and
September 15, 2004 exchange ratio of 0.48773:1
(2) Does not include the derivative liabilities of $26.9 million or
the derivative loss of $0.5 million included in current
liabilities and current assets respectively
(3) Does not include the Convertible Unsecured Subordinated Debentures
Long-term debt is comprised of bank credit facilities and senior secured
notes of $304.0 million and $157.7 million, respectively. PrimeWest had a
borrowing base of $625 million at September 30, 2004 as established by the
lenders. The bank credit facilities consist of a revolving term loan of
$437.5 million, operating facility of $25 million, and the balance of
$162.5 million of senior secured notes.
PrimeWest's third quarter 2004 net debt totaled $464.8 million. The
year-over-year and quarter-over-quarter increase is due to the debt incurred
to acquire the Calpine assets and the 25% interest in the Calpine Natural Gas
Trust.
Being in a cyclical business, it is important that PrimeWest maintain
financial flexibility to ensure we can operate with the minimum of financial
restrictions regardless of where commodities are in the price cycle.
PrimeWest's objective is to maintain 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 third quarter of 2004, PrimeWest's
debt to annualized cash flow is approximately 1.7 times, and 20% 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.
Unitholders' Equity
At the end of the third quarter 2004, the Trust had 69,077,455 Trust
Units outstanding, compared to 47,821,358 Trust Units outstanding at the end
of the third quarter 2003. In addition, PrimeWest had 1,315,173 (2003 -
3,968,010) Exchangeable Shares outstanding that are exchangeable into a total
of 641,449 (2003 - 1,695,133) Trust Units using the September 15, 2004
exchange ratio of 0.48773:1 (2003 - 0.42720:1). On September 2, 2004,
PrimeWest issued Series I and Series II Convertible Unsecured Subordinated
Debentures which are convertible into 5,660,377 and 3,773,585 Trust Units
respectively at a conversion price of $26.50 per Trust Unit.
For Canadian resident unitholders, PrimeWest offers a Distribution
Reinvestment Plan (DRIP). 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 www.primewestenergy.com.
These plan components benefit unitholders by offering alternatives to
maximize their investment in PrimeWest while providing the Trust with an
efficient 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 September 30, 2004, there were 1,315,173 Exchangeable Shares
outstanding. The exchange ratio on these shares was 0.48773:1 Trust Units for
each exchangeable share as at the end of the third 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.
Convertible Debentures
PrimeWest issued 7.5% (Series I) and 7.75% (Series II) Convertible
Unsecured Subordinated Debentures on September 2, 2004 for net proceeds of
$144.0 million and $96.0 million respectively.
The Series I Debentures pay interest semi-annually on March 31 and
September 30 and have a maturity date of September 30, 2009. The Series I
Debentures are convertible at the option of the holder at a conversion price
of $26.50 per Trust Unit. PrimeWest has the option to redeem the Series I
Debentures at a price of $1,050 per Series I Debenture after September 30,
2007 and on or before September 30, 2008, and at a price of $1,025 per
Series I Debenture after September 30, 2008 and before maturity. On redemption
or maturity the Trust may elect to satisfy its obligation to repay the
principal by issuing PrimeWest Trust Units.
The Series II Debentures pay interest semi-annually on June 30 and
December 30 and have a maturity date of December 31, 2011. The Series II
Debentures are convertible at the option of the holder at conversion price of
$26.50 per Trust Unit. PrimeWest has the option to redeem the Series II
Debentures at a price of $1,050 per Series II Debenture after December 31,
2007 and on or before December 31, 2008, at a price of $1,025 per Debenture
after December 31, 2008 and on or before December 31, 2009 and after December
31, 2009 and before maturity at $1,000 per Series II Debenture. On redemption
or maturity the Trust may elect to satisfy its obligations to repay the
principal by issuing PrimeWest Trust Units.
New accounting rules will be in effect for fiscal years ending on or
after November 1, 2004, which will require the Debentures to be disclosed as
financial liabilities rather than equity on the balance sheet.
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% to 90% of cash flow from operations.
In the third quarter of 2004, cash distributions totaled $50.4 million,
or $0.83 per Trust Unit representing a payout ratio of 74%, compared to
$43.7 million, or $0.96 per Trust Unit (84% payout ratio) for the same period
in 2003. In the second quarter of 2004 cash distributions totaled
$42.0 million, or $0.75 per Trust Unit representing a payout ratio of
approximately 72% in that quarter. Cash distributions for the nine-month
period of 2004 are $2.40 per Trust Unit representing a payout ratio of
approximately 72% versus the same 2003 period amounts of $3.36 per Trust Unit
representing a payout ratio of approximately 84% for the same period in 2003.
Distribution payments to U.S. unitholders are subject to 15% Canadian
withholding tax, which is deducted from the distribution amount prior to
deposit into accounts.
Contractual Obligations
PrimeWest enters into many contractual obligations as part of conducting
day-to-day business. Material contractual obligations include lease rental
commitments that run from 2004 through 2009 and a pipeline transportation
commitment that runs to October 31, 2007. The details of the timing of these
contractual obligations are included in the following table.
As at September 30, 2004 Payments due by period ($ millions)
-------------------------------------------------------------------------
Less More
than 1-3 4-5 than
Total 1 year years years 5 years
----------------------------------------------
Long-term debt
obligations 461.7 304.0 39.4 78.9 39.4
Series I and II
debentures 250.0 - - 150.0 100.0
Lease rental obligations 7.7 1.4 5.5 0.8 -
Pipeline transportation
obligations 8.2 2.7 5.4 0.1 -
Derivative liabilities 29.3 26.9 2.4 - -
-------------------------------------------------------------------------
Total contractual
obligations 756.9 335.0 52.7 229.8 139.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 September 30,
2004, $0.8 million has been accrued in non-cash general and administrative
expenses related to the Special Employee Retention Plan.
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 adopted CICA Accounting Guideline 16 (AcG-16), "Oil and Gas
Accounting - Full Costs" on January 1, 2004. 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 through 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 and the assets of Calpine Canada in the third quarter of 2004. These
transactions were 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 third quarter of 2004, PrimeWest lost $8.8 million
from commodity hedges, but has added $17.2 million to revenue from its hedging
program from January 1, 2001 to the end of the third 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
counterparties and limiting exposure to each counterparty. 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 we do not
anticipate any material change to this breakdown in 2004.
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.
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 www.sedar.com and on the PrimeWest website at 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,
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.
Consolidated Balance Sheet
---------------------------
(Unaudited) (Audited)
(millions of dollars) Sep 30, 2004 Dec 31, 2003
-------------------------------------------------------------------------
(Restated
- Note 2)
ASSETS
Current assets
Cash and short term deposits $ - $ 2.5
Accounts receivable 75.2 65.4
Derivative loss (Note 5) 0.5 -
Prepaid expenses 8.9 6.5
Inventory 6.6 2.1
-------------------------------------------------------------------------
91.2 76.5
Cash reserved for site restoration
and reclamation 10.4 8.2
Other assets and deferred charges (Note 4) 73.3 1.5
Property, plant and equipment 2,019.4 1,548.2
Goodwill 68.5 56.1
-------------------------------------------------------------------------
$ 2,262.8 $ 1,690.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Bank overdraft $ 1.5 $ -
Accounts payable 21.1 26.7
Accrued liabilities 54.3 45.3
Derivative liabilities (Note 5) 26.9 -
Accrued distributions to unitholders 16.9 10.3
-------------------------------------------------------------------------
120.7 82.3
Derivative liabilities (Note 5) 2.4 -
Long-term debt (Note 7) 461.7 250.1
Future income taxes 204.8 313.2
Asset retirement obligation (Note 6) 46.7 19.7
-------------------------------------------------------------------------
836.3 665.3
UNITHOLDERS' EQUITY
Net capital contributions (Note 8) 2,029.8 1,565.9
Convertible unsecured subordinated
debentures (Note 8) 240.0 -
Capital issued but not distributed 3.8 5.2
Long-term incentive plan equity 18.9 14.6
Accumulated income 48.6 219.1
Accumulated cash distributions (905.1) (771.6)
Accumulated debenture interest (1.5) -
Accumulated dividends (8.0) (8.0)
-------------------------------------------------------------------------
1,426.5 1,025.2
-------------------------------------------------------------------------
$ 2,262.8 $ 1,690.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes form an integral part of these financial
statements.
Consolidated Statements of Unitholders' Equity (Unaudited)
----------------------------
For the nine months ended
(millions of dollars) Sep 30, 2004 Sep 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 62.8 90.1
Net capital contributions 463.9 253.1
Convertible unsecured subordinated debentures 240.0 -
Capital issued but not distributed (1.4) -
Long-term incentive plan equity 4.3 1.8
Cash distributions (133.5) (146.3)
Debenture interest expense (1.5) -
-------------------------------------------------------------------------
Unitholders' equity, end of period $ 1,426.5 $ 1,045.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated Statements of Cash Flow (Unaudited)
Three Months Ended Nine Months Ended
-------------------------------------------------------------------------
Sep 30, Sep 30, Sep 30, Sep 30,
(millions of dollars) 2004 2003 2004 2003
-------------------------------------------------------------------------
(Restated (Restated
- Note 2) - Note 2)
OPERATING ACTIVITIES
Net income for the period $ 20.2 $ 7.0 $ 62.8 $ 90.1
Add/(deduct):
Items not involving cash
from operations
Depletion, depreciation
and amortization 50.2 50.7 133.4 153.3
Non-cash general &
administrative 14.1 2.3 7.2 5.9
Non-cash foreign
exchange loss (gain) (9.1) 0.2 (4.4) (5.4)
Accretion on asset
retirement obligation 0.5 0.3 1.2 0.9
Future income taxes
recovery (22.3) (8.7) (44.0) (71.1)
Unrealized loss on
derivatives 14.7 - 28.8 -
-------------------------------------------------------------------------
Cash flow from operations 68.3 51.8 185.0 173.7
Expenditures on site
restoration and reclamation (1.1) (0.4) (2.4) (0.8)
Change in non-cash working
capital (3.7) 5.4 (10.5) 0.1
-------------------------------------------------------------------------
63.5 56.8 172.1 173.0
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust
Units, net of issue costs 290.4 80.1 433.3 240.3
Proceeds from issue of
Debentures, net of
issue costs 240.0 - 240.0 -
Net cash distributions to
unitholders (41.9) (40.8) (107.0) (137.3)
Increase/(decrease) in bank
credit facilities 291.0 (51.0) 206.0 (146.0)
Increase in senior secured
notes - - - 174.0
Increase in deferred charges - 0.1 - (1.3)
Change in non-cash working
capital 8.3 (2.5) 9.8 0.5
-------------------------------------------------------------------------
787.8 (14.1) 782.1 130.2
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property,
plant & equipment (26.0) (31.4) (79.6) (75.6)
Corporate acquisitions
(Note 3) - (0.5) (34.8) (200.9)
Acquisition of capital assets (767.0) (0.2) (771.2) (4.0)
Proceeds on disposal of
property, plant & equipment 6.3 0.6 11.3 0.8
Equity investment (72.7) - (72.7) -
Increase in cash reserved for
future site restoration and
reclamation (0.6) (3.7) (2.2) (6.4)
Change in non-cash working
capital (5.3) 5.2 (9.0) 7.9
-------------------------------------------------------------------------
(865.3) (30.0) (958.2) (278.2)
-------------------------------------------------------------------------
(Decrease)/increase in cash
for the period (14.0) 12.7 (4.0) 25.0
Cash (bank overdraft) beginning
of the period 12.5 9.2 2.5 (3.1)
-------------------------------------------------------------------------
(Bank overdraft)/cash end of
the period $ (1.5) $ 21.9 $ (1.5) $ 21.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash interest paid $ 1.2 $ 1.2 $ 6.6 $ 6.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash taxes paid $ 0.8 $ 2.6 $ 3.1 $ 3.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
-------------------------------------------------------------------------
(millions of dollars, except Sep 30, Sep 30, Sep 30, Sep 30,
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 $ 127.4 $ 102.3 $ 350.2 $ 343.7
Transportation expenses (2.0) (2.1) (5.7) (6.3)
Crown and other royalties,
net of ARTC (28.9) (23.1) (78.0) (80.8)
Other income 0.7 0.1 1.3 0.3
-------------------------------------------------------------------------
97.2 77.2 267.8 256.9
-------------------------------------------------------------------------
EXPENSES
Operating 21.4 17.2 60.6 58.2
Cash general and administrative 3.4 3.5 11.1 10.5
Non-cash general and
administrative 14.1 2.3 7.2 5.9
Interest 2.9 4.0 8.9 11.0
Accretion on asset retirement
obligation 0.5 0.3 1.2 0.9
Unrealized loss on derivatives 14.7 - 28.8 -
Foreign exchange loss (gain) (9.0) 0.1 (4.1) (5.4)
Depletion, depreciation and
amortization 50.2 50.7 133.4 153.3
-------------------------------------------------------------------------
$ 98.2 $ 78.1 $ 247.1 $ 234.4
-------------------------------------------------------------------------
Income before taxes for
the period $ (1.0) $ (0.9) $ 20.7 $ 22.5
-------------------------------------------------------------------------
Income and capital taxes 1.1 0.8 1.9 3.5
Future income taxes recovery (22.3) (8.7) (44.0) (71.1)
-------------------------------------------------------------------------
(21.2) (7.9) (42.1) (67.6)
-------------------------------------------------------------------------
Net income for the period $ 20.2 $ 7.0 $ 62.8 $ 90.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust Unit
- basic $ 0.31 $ 0.15 $ 1.10 $ 2.01
Net income per Trust Unit
- diluted $ 0.31 $ 0.15 $ 1.10 $ 2.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Notes to Consolidated Financial Statements
For the nine months ended September 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
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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
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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
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2004 2005 2006 2007 2008
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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
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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 6 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 $0.6 million for electrical power. See Note 5 for the
reconciliation of the derivative liability and deferred derivative loss.
3. Asset and Corporate Acquisitions
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a) On September 2, 2004, PrimeWest Gas Corp. acquired oil and gas assets
from Calpine Canada. The acquisition was accounted for using the
purchase method of accounting with the net assets acquired and
consideration paid as follows:
Net Assets Acquired
at Assigned Values ($ millions) Consideration Paid ($ millions)
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Petroleum and natural
gas assets $ 762.3
Inventory 4.2 Cash $ 747.0
Working capital 2.9 Net closing adjustments (10.3)
Asset Retirement Costs associated with
Obligation (27.4) acquisition 5.3
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$ 742.0 $