PrimeWest Energy Trust Announces Fourth Quarter and Full Year 2005 Results
FEB 23, 2006 - 17:20 ET
CALGARY, ALBERTA--(CCNMatthews - Feb. 23, 2006) - PRIMEWEST ENERGY TRUST (TSX:PWI.UN)
(TSX:PWI.DB.A) (TSX:PWI.DB.B) (TSX:PWX) (NYSE:PWI) (PRIMEWEST OR THE TRUST) TODAY
ANNOUNCES INTERIM OPERATING AND FINANCIAL RESULTS FOR THE FOURTH QUARTER AND YEAR
ENDED DECEMBER 31, 2005. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT
ARE IN CANADIAN DOLLARS.
Fourth Quarter 2005 Highlights:
- Distributions in the fourth quarter were $0.96 per Trust Unit representing a payout
ratio of approximately 57% of operating cash flow compared to third quarter 2005
distributions of $0.90 per Trust Unit, representing a payout ratio of 66% of operating
cash flow. The full year payout ratio in 2005 was 67% compared to 74% in 2004. The
2005 lower payout ratio reflects the increase in cash flow due to increased commodity
prices and retention of cash to fund development capital opportunities as well as
reducing outstanding bank debt.
- Fourth quarter cash flow from operations was $132.5 million ($1.66 per Trust Unit)
compared to $106.4 million ($1.36 per Trust Unit) in the third quarter 2005.
- Fourth quarter 2005 production averaged 40,269 barrels of oil equivalent per day
(BOE/day), compared to the third quarter 2005 rate of 40,121 BOE/day. The increase
is due to incremental volumes from capital development activity offset by decreases
due to operational issues and natural decline.
- Development capital expenditures in the fourth quarter were $41.2 million with
drilling and completion expenditures of $25.6 million resulting in 43 gross wells
(15.8 net) being drilled with a success rate of 100%. PrimeWest has identified a
portfolio of capital opportunities of approximately $800 million to be developed
over the next several years.
- In the fourth quarter of 2005, PrimeWest changed the method of accounting for
its unit-based compensation. PrimeWest has applied the fair value method retroactively
to Unit Appreciation Rights (UARs)issued on or after January 1, 2002. Prior periods
have been restated. (Refer to note 3 in the Notes to Consolidated Financial Statements).
- Net debt to annual 2005 cash flow was approximately 0.8 times compared to net
debt to annualized third quarter 2005 cash flow of 0.9 times at September 30, 2005.
PrimeWest has approximately $334 million available on its existing credit facilities
at December 31, 2005.
Subsequent Event:
- On February 10, 2006, PrimeWest announced the appointment of Mr. Brian Lynam,
P.Eng. to the position of Vice President, Operations. In this newly created position,
Mr. Lynam will have responsibility for field operations, drilling and facilities.
The addition of Mr. Lyman to PrimeWest's executive team reflects the increased portfolio
of development opportunities being executed by the Trust, the increased focus on
field operations and the preparation of the organization for future growth.
Forward-Looking Information
This MD&A contains forward-looking or outlook information with respect to PrimeWest.
Certain statements contained in this MD&A, and any documents incorporated by reference
into this MD&A, constitute forward-looking statements. The use of any of the words
"anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project",
"should", "believe", "outlook" and similar expressions are intended to identify
forward-looking statements. In addition, statements relating to "reserves" or "resources"
are deemed to be forward-looking statements, as they involve implied assessment,
based on certain estimates and assumptions, that the resources and reserves described
can be profitably produced in the future. 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, or incorporated
by reference into this MD&A. These statements speak only as of the date of this
MD&A or as of the date specified in any documents incorporated by reference into
this MD&A, as the case may be.
In particular, this MD&A, and any documents incorporated by reference, contain 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, operations and strategy of the commodity price risk management
program;
- the approximate and maximum amount of forward sales and hedging to be employed;
- our 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 us
relative to other oil and natural 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
- our ability to benefit from the combination of growth opportunities and the ability
to grow through the capital markets.
With respect to forward-looking statements contained in this MD&A, including any
documents incorporated herein by reference, we have made assumptions regarding,
among other things:
- future oil and natural gas prices and differentials between light, medium and
heavy oil prices;
- the cost of expanding our property holdings;
- our ability to obtain equipment in a timely manner to carry out development activities;
- our ability to market our oil and natural gas successfully to current and new
customers;
- the impact of increasing competition;
- our ability to obtain financing on acceptable terms; and
- our ability to add production and reserves through our development and exploitation
activities.
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 incorporated by reference
into this MD&A:
- volatility in market prices for oil and natural gas;
- the impact of weather conditions on seasonal demand;
- risks inherent in our oil and natural 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 and natural gas;
- royalties payable in respect of our oil and natural gas production;
- government regulation of the oil and natural 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;
- OPEC's ability to control production and balance global supply and demand of crude
oil at desired price levels;
- political uncertainty, including the risks of hostilities, in the petroleum producing
regions of the world;
- the need to obtain required approvals from regulatory authorities; and
- the other factors discussed under "Risk Factors" contained this MD&A.
These factors should not be construed as exhaustive. The forward-looking statements
contained in this MD&A and any documents incorporated by reference herein are expressly
qualified by this cautionary statement. We undertake no obligation to publicly update
or revise any forward-looking statements.
PrimeWest does not endorse any of the analyst or consultant sourced material contained
herein.
All figures reported in Canadian dollars unless otherwise stated.
Production figures stated are Company Interest before the deduction of royalties.
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer, Don Garner, and the Chief Financial Officer, Dennis
Feuchuk, evaluated the effectiveness of PrimeWest's disclosure controls and procedures
as of December 31, 2005, and concluded that PrimeWest's disclosure controls and
procedures were effective to ensure that information PrimeWest is required to disclose:
- in its annual filings, interim filings or other reports (each as defined in National
Instrument 52-109 of the Canadian Securities Administrators) filed or submitted
by it under provincial securities legislation is recorded, processed, summarized
and reported within the time periods specified in the provincial securities legislation
and to ensure that information required to be disclosed by PrimeWest in its annual
filings, interim filings or other reports filed or submitted under provincial securities
legislation is accumulated and communicated to PrimeWest's management, including
its chief executive officer and chief financial officer, as appropriate to allow
timely decisions regarding required disclosure; and
- in its annual filings, interim filings or other reports with the United States
Securities and Exchange Commission (SEC) in the United States (US) under the Securities
Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported,
within the time periods specified in the Commission'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.
The evaluation took into consideration PrimeWest's Communications and Disclosure
Policy and the functioning of its executive officers, board of directors and board
committees. In addition, the evaluation covered PrimeWest's processes, systems and
capabilities relating to regulatory filings, public disclosures and the identification
and communication of material information.
Changes to Internal Controls Over Financial Reporting
There were no changes to PrimeWest's internal control over financial reporting since
September 30, 2005 that have materially affected, or are reasonably likely to materially
affect PrimeWest's internal control over financial reporting.
Non-GAAP Measures
This MD&A contains the following measurements that are not defined by Canadian Generally
Accepted Accounting Principles (GAAP):
- Cash flow from operations on a total and per Trust Unit basis;
- Distributions per Trust Unit; and
- Net debt per Trust Unit.
These measurements do not have any standardized meaning prescribed by GAAP and are,
therefore, unlikely to be comparable to similar measures presented by other entities.
Cash flow from operations is calculated from the Trust's cash flow statement as
cash flow from operating activities before changes in working capital. Cash flow
from operations per Trust Unit on a basic basis is calculated by dividing cash flow
by the weighted average number of Trust Units outstanding plus Trust Units issuable
upon the exchange of the outstanding Exchangeable Shares of PrimeWest Energy Inc.
(Exchangeable Shares). Cash flow from operations per Trust Unit on a diluted basis
is calculated using cash flow and adding back the interest expense on the Convertible
Unsecured Subordinated Debentures (Debentures), divided by the diluted weighted
average number of Trust Units outstanding in the period. The diluted weighted average
number of Trust Units outstanding consists of the weighted average Trust Units plus
Trust Units issuable upon the exchange of outstanding Exchangeable Shares and includes
the Trust Units issuable pursuant to the conversion of the Debentures, and Trust
Units issuable pursuant to PrimeWest's Long-Term Incentive Plan (LTIP). Cash flow
from operations is a key performance indicator of PrimeWest's ability to generate
cash and finance operations and pay monthly distributions.
Distributions per Trust Unit disclose the cash distributions accrued in 2005 based
on the number of Trust Units outstanding on the date the distributions were declared.
Net debt per Trust Unit is calculated as long-term debt, including Debentures, less
working capital, excluding financial derivative assets and liabilities and current
future income tax assets divided by the number of Trust Units outstanding and Trust
Units issuable upon the exchange of outstanding Exchangeable Shares and Trust Units
issuable pursuant to the LTIP at December 31, 2005.
Business Strategy
PrimeWest Energy Trust is a conventional oil and natural 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 Canada 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 appreciation
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 2005 and our goals for 2006 and beyond.
We believe that PrimeWest can maximize total return to Unitholders by continuing
to develop 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 principles to protect the interests of all stakeholders.
Asset Management and Growth
PrimeWest has a strategy to focus expansion efforts on existing Canadian core areas
and pursue depletion optimization strategies within those core areas to maximize
asset value. We strive to control our operations wherever possible, and maintain
high working interests in core areas. Maintaining control of 80% of our assets 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. The current size of the Trust gives us the ability
and critical mass to make acquisitions of significant size, while being able to
add value by transacting smaller acquisitions.
Financial Management
PrimeWest strives to maintain a prudent debt position, to allow us to fund smaller
acquisitions and to fund ongoing development activities without tapping the capital
markets. Our long-term debt is comprised of bank credit facilities through a bank
syndicate, US-dollar-denominated Senior Secured Notes (Secured Notes) and the Debentures.
Our diversified debt instruments help to reduce our reliance on the bank syndicate.
PrimeWest's commodity hedging approach is intended to help to stabilize cash flow,
reduce volatility, and when applicable protect near-term acquisition economics.
Since August 2003, PrimeWest has followed a strategy of maintaining a distribution
payout ratio within 70-90% of cash flow, calculated on an annual basis. The strength
in commodity prices has increased the Trust's cash flow from operations available
for distribution to Unitholders. The Board of Directors of PrimeWest will continue
to consider a variety of factors in establishing the monthly distribution level.
These factors include, but are not limited to: commodity price outlook, cash flow
forecast, capital development plans, debt levels, tax considerations and competitive
industry distribution practices.
The 2005 payout ratio was approximately 67% of annual operating cash flow. The retained
cash flow was utilized to fund the Trust's capital spending program and repay debt.
PrimeWest's net debt to cash flow ratio was 0.8 times at December 31, 2005 using
2005 annual cash flows.
PrimeWest's dual listing on the Toronto Stock Exchange (TSX) and New York Stock
Exchange (NYSE) provides increased liquidity and a broadened investor base. The
NYSE listing enables US Unitholders to conveniently trade in our Trust Units, and
allows us to access the US capital markets in the future. Our status as a corporation
for US tax purposes simplifies tax reporting for our US Unitholders.
For eligible Canadian and US Unitholders, PrimeWest offers participation in the
conventional Distribution Reinvestment Plan (DRIP), which represents a convenient
way to maximize an investment in PrimeWest. Canadian residents may also participate
in the Optional Trust Unit Purchase Plan (OTUPP) and the Premium Distribution Plan
(PREP). For alternate investment requirements, PrimeWest also has Exchangeable Shares
and Debentures available, which permit participation in PrimeWest without the ongoing
tax implications associated with receiving a distribution.
Corporate Governance
PrimeWest remains committed to high 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF FEBRUARY 23, 2006
The following is management's discussion and analysis (MD&A) of PrimeWest's operating
and financial results for the fourth quarter and twelve months ended December 31,
2005, 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.
FINANCIAL AND OPERATING RESULTS - FOURTH QUARTER 2005
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Three Months Ended
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$ millions, except per BOE(1) Dec 31, Sep 30, Dec 31,
and per Trust Unit amounts 2005 2005 2004
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Gross revenue (net of
transportation expense) 230.6 193.3 169.3
per BOE 62.97 52.38 41.46
Cash flow from operations 132.5 106.4 83.3
per BOE 35.76 28.83 20.41
per Trust Unit - basic (2) 1.66 1.36 1.17
Royalty expense 55.9 44.4 41.8
per BOE 15.08 12.04 10.24
Operating expense 32.9 31.6 28.3
per BOE 8.88 8.56 6.94
Cash general and administrative
expense 6.9 5.7 7.9
per BOE 1.88 1.54 1.93
Non-cash general and
administrative expense (3) 1.2 1.5 1.4
per BOE 0.33 0.41 0.34
Interest expense (4) 5.5 6.0 11.7
per BOE 1.48 1.61 2.86
Distributions to Unitholders 76.2 70.1 62.6
per Trust Unit (5) 0.96 0.90 0.90
Net debt (6) 323.7 381.8 552.0
per Trust Unit (7) 3.97 4.75 7.77
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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) The basic per Trust Unit calculation includes the weighted
average Trust Units and Trust Units issuable upon exchange of
the Exchangeable Shares of PrimeWest Energy Inc. (Exchangeable
Shares).
(3) Non-cash general and administrative expenses have been restated
to reflect the change in method of accounting for the unit-based
compensation. (see note 3 in the Notes to Consolidated Financial
Statements).
(4) Interest expense includes the interest on the Debentures.
(5) Based on Trust Units outstanding at date of distribution.
(6) Net debt is long-term debt including Debentures less working
capital, excluding financial derivative assets and liabilities
and future income tax assets.
(7) The net debt per Trust Unit calculation includes outstanding
Trust Units, Trust Units issuable upon exchange of the
outstanding Exchangeable Shares and Trust Units issuable pursuant
to the LTIP at the end of the period.
Operating Highlights
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Three Months Ended
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Dec 31, Sep 30, Dec 31,
2005 2005 2004
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Daily production volumes
Natural gas (mmcf/day) 176.8 176.8 187.2
Crude oil (bbls/day) 6,752 7,037 9,108
Natural gas liquids (bbls/day) 4,046 3,616 4,059
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Total (BOE/day) 40,269 40,121 44,368
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Cash Flow Reconciliation
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($ millions)
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Third quarter 2005 cash flow from operations $ 106.4
Volumes 0.6
Commodity prices 49.1
Net hedging change from prior quarter (9.8)
Operating expenses (1.3)
Royalties (11.5)
General and administrative expenses (1.2)
Other 0.2
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Fourth quarter 2005 cash flow from operations $ 132.5
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The above table includes non-GAAP measurements. (Refer to discussion
on Non-GAAP Measures on Page 4)
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, interest
expense, general and administrative expense (G&A), hedging gains or losses, royalties
and currency exchange rates. Some of these factors such as commodity prices, the
currency exchange rate and royalties are uncontrollable from PrimeWest's perspective.
Other factors that are to a certain extent controllable by PrimeWest are production
levels and operating expenses, as well as interest and G&A expenses.
Capital Expenditures
Three Months Ended
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Dec 31, Sep 30, Dec 31,
($ millions) 2005 2005 2004
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Land and lease acquisitions $ 1.9 $ 2.7 $ 1.8
Geological and geophysical 0.9 0.3 2.4
Drilling and completions 25.6 22.0 30.1
Investment in facilities
Equipping and tie-in 6.2 6.4 4.3
Compression and processing 0.4 0.3 0.9
Gas gathering 1.2 2.0 1.9
Production facilities 4.2 2.2 5.0
Capitalized G&A 0.8 0.7 0.4
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Development capital 41.2 36.6 46.8
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Corporate/property acquisitions 0.5 2.6 1.4
Dispositions (16.9) (1.5) (88.1)
Leasehold improvements, furniture
and equipment 0.8 0.8 3.2
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Net capital expenditures $ 25.6 $ 38.5 (36.7)
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During the fourth quarter of 2005, PrimeWest's development capital expenditures
totaled $41.2 million, compared to $46.8 million invested in the fourth quarter
of 2004 and $36.6 million in the previous quarter of 2005. Of the $41.2 million
total, $31.8 million or 77% was invested in drilling, completions and tie-ins, which
contribute to new reserve additions and help offset natural production decline.
Dispositions in the fourth quarter of 2005 of $16.9 million consisted mainly of
proprietary seismic data.
PrimeWest drilled 43 gross wells (15.8 net wells) in the fourth quarter of 2005
with a success rate of 100%.
Through acquisitions as well as development drilling, workovers and re-completion
activities, PrimeWest strives to offset natural production declines and add to reserves
in order to sustain cash flows. Capital resources are allocated to projects on the
basis of anticipated rate of return. At PrimeWest, every capital project is measured
against stringent economic evaluation criteria prior to approval. These criteria
include expected return, risks and further development opportunities.
Daily Production Volumes
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Three Months Ended
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Dec 31, Sep 30, Dec 31,
2005 2005 2004
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Natural gas (mmcf/day) 176.8 176.8 187.2
Crude oil (bbls/day) 6,752 7,037 9,108
Natural gas liquids (bbls/day) 4,046 3,616 4,059
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Total (BOE/day) 40,269 40,121 44,368
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All production information is reported before the deduction of crown
and freehold royalties.
PrimeWest's production volumes averaged 40,269 BOE/day in the fourth quarter of
2005 compared to 40,121 BOE/day in the third quarter. The marginal increase is due
to incremental volumes added through capital development activity in 2005 and to
the lifting of the Maximum Rate Limitation (MRL) by the Alberta Energy and Utilities
Board in September. Operational issues at Crossfield and Valhalla, and natural decline
partially offset the incremental volumes.
At the end of the fourth quarter of 2005, approximately 2,200 BOE/day of production
volumes remained behind pipe, awaiting tie-in.
Operating Costs
Operating costs for the fourth quarter of 2005 were $8.88/BOE, above the full year
2005 average of $7.94/BOE. The run-up in power and fuel costs through the quarter
along with prior period adjustments attributed to operations at the Valhalla plant
were the significant items contributing to the higher operating costs.
Going forward into 2006, PrimeWest has budgeted power costs of $85/mWhr. As part
of our ongoing program to manage costs, a number of cost reduction initiatives are
planned for 2006, including the shutdown of the Valhalla plant and consolidation
of facilities at Thorsby and Grand Forks.
Average Realized Sales Prices
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Three Months Ended
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Dec 31, Sep 30, Dec 31,
2005 2005 2004
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Natural gas ($/Mcf) (1)(2) 10.98 8.41 7.00
Without hedging 11.99 8.66 6.98
Crude oil ($/bbl)(1) 51.89 56.19 36.45
Without hedging 59.78 67.48 46.03
Natural gas liquids ($/bbl) 59.07 59.83 47.32
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Total (1) ($/BOE) 62.87 52.30 41.37
Without hedging 68.59 55.38 43.24
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Realized hedging loss included in
prices above ($/BOE) 5.72 3.08 1.87
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(1) Includes realized hedging losses.
(2) Excludes sulphur.
Commodity prices were higher in the fourth quarter of 2005 when compared to the
previous quarter and the fourth quarter of 2004, resulting in higher average realized
selling prices per BOE.
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 fourth quarter 2005, PrimeWest incurred a realized hedging loss of $21.2
million compared to a loss of $11.4 million in the third quarter.
Benchmark Commodity Prices
The following table sets forth benchmark historical and estimated future commodity
prices.
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Past Four Quarters (Actual)
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Q1 2005 Q2 2005 Q3 2005 Q4 2005
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Natural gas
AECO (Cdn$/mcf) 6.69 7.38 8.17 11.69
Crude oil WTI (US$/bbl) 49.85 53.17 63.19 60.02
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Next Four Quarters (Forward Markets)(1)
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Q1 2006 Q2 2006 Q3 2006 Q4 2006
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Natural gas
AECO (Cdn$/mcf) 8.88 7.42 7.66 8.69
Crude oil WTI (US$/bbl) 63.02 63.32 64.70 65.49
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(1) As at February 17, 2006
FINANCIAL AND OPERATING RESULTS - TWELVE MONTHS ENDED DECEMBER 31, 2005
Full Year 2005 Highlights:
- Production in 2005 averaged 40,351 BOE/day, up 13% from the 2004 level of 35,578
BOE/day as a result of the Calpine acquisition in the third quarter of 2004 and
development capital volume additions, partially offset by minor asset divestments
transacted in December 2004 and natural production declines.
- Operating margin of $31.54/BOE for 2005, up 25% from 2004 primarily due to higher
commodity prices throughout the year, offset by the impact of the commodity hedging
program as well as higher operating costs and royalties in 2005.
- Distributions of $3.66 per Trust Unit in 2005 compared to $3.30 per Trust Unit
in 2004. The distribution level was increased in December 2005 by 20% from $0.30
per Trust Unit per month to $0.36 per Trust Unit per month, based on commodity price
levels in effect at the time, coupled with PrimeWest's prudent risk management strategy.
PrimeWest's payout ratio for 2005 was approximately 67% compared to the 2004 payout
ratio of 74%.
- Capital development program of $185.6 million added 14.7 mmBOE of Proved plus
Probable reserves (including technical revisions) on a Company Interest basis at
$12.63/BOE, which excludes $4.06/BOE for future development capital. The capital
development program replaced 100% of the 2005 production on a Proved plus Probable
basis by reinvesting approximately 45% of cash flow from operations.
- PrimeWest's Reserve Life Index (RLI) at year end 2005 is 11.0 years on a Company
Interest Proved plus Probable basis. (Refer to the "Disclosure of Oil and Natural
Gas Reserves" section later in this MD&A for reserve definitions).
- Operating expenses were 32% higher in 2005 than in 2004, reflecting higher production
volumes and higher industry wide cost structure. On a unit of production basis,
operating expenses were 16% higher than in 2004 at $7.94/BOE versus $6.83/BOE.
- Cash G&A expense increased $3.9 million over 2004 reflecting increases in labour
costs, information technology expenses, office rent and property taxes associated
with additional staffing and office space requirements resulting from the 2004 Calpine
asset acquisition.
- Interest expense during 2005 was 37% higher than in 2004 due to a higher average
net debt balance and higher interest rates during the year resulting from the issuance
of the Debentures in the third quarter of 2004 to acquire the Calpine assets.
- The Distribution Reinvestment, Premium Distribution and Optional Trust Unit Purchase
Plans contributed $55.7 million of equity capital to be reinvested in the capital
development program and to repay debt.
Outlook - 2006
PrimeWest expects 2006 production volumes to average approximately 38,000-39,000
BOE/day. Full-year operating costs are expected to be approximately $8.00/BOE. PrimeWest
expects to invest approximately $275 million in its 2006 capital development program,
with the focus primarily in the core areas of Caroline, Columbia, Wilson Creek,
Crossfield and Brant Farrow.
Financial and Operating Results -
Twelve Months Ended December 31, 2005
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Financial
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($ millions, except Per BOE(1) Change
and Per Trust Unit) 2005 2004 (%)
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Gross revenue(net of transportation
Expense) $ 749.7 $ 513.7 46
Per BOE 50.90 39.45 29
Cash flow from operations 414.1 266.8 55
Per BOE 28.11 20.49 37
Per Trust Unit - basic (2) 5.46 4.49 22
Per Trust Unit - diluted (3) 5.16 4.33 19
Royalty expense 172.8 119.8 44
Per BOE 11.73 9.20 28
Operating expense 117.0 88.9 32
Per BOE 7.94 6.83 16
Cash general and administrative expense 22.9 19.0 21
Per BOE 1.56 1.46 7
Non-cash general and administrative
expense (4) 5.4 4.1 32
Per BOE 0.37 0.32 16
Interest expense (5) 28.3 20.6 37
Per BOE 1.92 1.58 22
Net income 207.5 105.4 97
Per Trust Unit - basic (2) 2.73 1.77 54
Per Trust Unit - diluted (3) 2.66 1.77 50
Distributions to Unitholders 276.6 196.1 41
Per Trust Unit (6) 3.66 3.30 11
Net debt (7) 323.7 552.0 (41)
Per Trust Unit (8) 3.97 7.77 (48)
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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) The basic per Trust Unit calculation includes the weighted
average Trust Units outstanding and Trust Units issuable upon
exchange of the outstanding Exchangeable Shares of PrimeWest
Energy Inc. (Exchangeable Shares).
(3) The diluted per Trust Unit calculation includes the weighted
average Trust Units outstanding, Trust Units issuable upon
exchange of the outstanding Exchangeable Shares, the deemed
conversion of the Convertible Unsecured Subordinated Debentures
(the "Debentures") and Trust Units issuable pursuant to the
Long-Term Incentive Plan (LTIP). Interest expense incurred on the
Debentures is added back to net income and to cash flow for the
diluted per Trust Unit calculation.
(4) Non-cash general and administrative expenses have been restated
to reflect the change in method of accounting for the Trust's
Unit-Based Compensation. See note 3 in the Notes to Consolidated
Financial Statements.
(5) Interest expense includes the interest on the Debentures.
(6) Based on Trust Units outstanding at the date of distribution.
(7) Net debt is long-term debt including Debentures less working
capital, excluding financial derivative assets and liabilities
and current future income tax assets.
(8) The net debt per Trust Unit calculation includes outstanding
Trust Units, Trust Units issuable upon exchange of the
outstanding Exchangeable Shares and Trust Units issuable pursuant
to the LTIP at the end of the period.
Daily Production Volumes
---------------------------------------------------------------------
Change
2005 2004 (%)
---------------------------------------------------------------------
Natural gas (mmcf/day) 178.2 145.1 23
Crude oil (bbls/day) 6,861 8,282 (17)
Natural gas liquids (bbls/day) 3,797 3,107 22
---------------------------------------------------------------------
Total (BOE/day) 40,351 35,578 13
---------------------------------------------------------------------
---------------------------------------------------------------------
Realized Commodity Prices
---------------------------------------------------------------------
Change
2005 2004 (%)
---------------------------------------------------------------------
Natural gas ($/mcf) (1) (2) 8.43 6.61 28
Without hedging 8.75 6.70 31
Crude oil ($/bbl) (1) 49.05 36.83 33
Without hedging 58.48 44.46 32
Natural gas liquids ($/bbl) 55.92 43.69 28
---------------------------------------------------------------------
Total ($/BOE) (1) 50.81 39.35 29
Without hedging 53.82 41.51 30
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes realized hedging losses.
(2) Excludes sulphur.
Cash Flow Reconciliation
---------------------------------------------------------------------
($ millions)
---------------------------------------------------------------------
2004 cash flow from operations $ 266.8
Production volumes 67.3
Commodity prices 184.8
Net hedging change from prior year (16.1)
Operating expense (28.1)
Royalties (53.0)
Interest expense (7.7)
Other 0.1
---------------------------------------------------------------------
2005 cash flow from operations $ 414.1
---------------------------------------------------------------------
---------------------------------------------------------------------
The above table includes non-GAAP measurements (refer to discussion
on Non-GAAP measures on Page 4)
The 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 expense, interest
expense, G&A expense, hedging gains or losses, royalties and currency exchange rates.
Some of these factors such as commodity prices, the currency exchange rate and royalties
are uncontrollable by PrimeWest. Factors that are, to a certain extent, controllable
by PrimeWest are production levels and operating expense, as well as interest and
G&A expense.
Capital Spending
---------------------------------------------------------------------
($ millions ) 2005 2004
---------------------------------------------------------------------
Land and lease acquisitions $ 17.6 $ 8.3
Geological and geophysical 7.6 8.2
Drilling and completions 106.5 69.8
Equipping and tie-in 26.5 12.1
Compression and processing 9.1 4.7
Gas gathering 3.9 4.4
Production facilities 11.5 15.8
Capitalized G&A expense 2.9 1.8
---------------------------------------------------------------------
Development capital $ 185.6 $ 125.1
---------------------------------------------------------------------
Corporate/property acquisitions 2.7 807.4
Dispositions (20.6) (99.5)
Head office equipment 4.2 4.6
---------------------------------------------------------------------
Total $ 171.9 $ 837.6
---------------------------------------------------------------------
---------------------------------------------------------------------
Capital expenditures, including development, acquisitions and divestments totaled
approximately $171.9 million in 2005, versus $837.6 million in 2004. PrimeWest's
property acquisitions in 2004 included the Calpine oil and natural gas assets.
PrimeWest's 2005 capital development program totaled $185.6 million (2004 - $125.1
million). PrimeWest drilled 132 gross (62.8 net) wells with a success rate of 98.5%.
The capital program focused on the core areas of Caroline, Columbia, Wilson Creek,
Valhalla and Brant Farrow. The development program added 10.7 mmBOE of Company Interest
Proved reserves and 14.7 mmBOE of Company Interest Proved plus Probable reserves,
including technical revisions.
---------------------------------------------------------------------
2005 2004
---------------------------------------------------------------------
Development Program
Proved reserve additions (mmBOE) (1) 10.7 7.7
Average cost ($/BOE) (2)(3) $ 22.25 $ 16.59
---------------------------------------------------------------------
Proved plus Probable reserve additions (mmBOE) (1) 14.7 9.1
Average cost ($/BOE) (2)(3) $ 16.85 $ 16.91
---------------------------------------------------------------------
Acquisition Program: (4)
Proved reserve additions (mmBOE) (0.5) 42.4
Average cost ($/BOE) (1)(4) $ (35.8) $ 16.57
---------------------------------------------------------------------
Proved plus Probable reserve additions (mmBOE) (0.6) 53.2
Average cost ($/BOE) (1)(4) $ (29.83) $ 13.20
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Proved and Proved plus Probable reserve additions in 2004 exclude
the impact of economic factors.
(2) Under National Instrument 51-101 - Standards of Disclosure for
Oil and Gas Activities the implied methodology to be used to
calculate finding development and acquisition (FD&A) costs
includes the change during the current year in estimated future
development costs (FDC). The average cost per BOE from Company
Interest Proved reserves additions includes the change in the
current year FDC of $4.91/BOE ($0.35/BOE for 2004) and the
average cost per BOE from Company Interest Proved plus Probable
reserve additions including the change in the current year FDC of
$4.22/BOE ($3.17/BOE for 2004).
(3) The aggregate of the costs incurred under the capital development
program in 2005 and the estimated FDC generally will not reflect
total finding and development costs related to reserve additions
for that year.
(4) Net of dispositions.
Investment in drilling, completions and tie-in represented 72% of development capital
that contributed to new reserve additions in 2005. Investment in facilities totaled
$24.5 million, representing 13% of development capital, on projects related to debottlenecking,
increasing capacity or other activities that contribute to future production volumes.
In 2006, PrimeWest plans to invest approximately $275 million in its capital development
programs.
Given that production volumes will decline naturally over time as oil or natural
gas reservoirs are depleted, PrimeWest is continually striving to offset this natural
decline, and add to reserves in an effort to sustain cash flows. Investment in activities
such as development drilling, workovers and recompletions can add incremental production
volumes and reserves.
Capital is allocated on the basis of anticipated rate of return on projects undertaken.
At PrimeWest, every capital project is measured against economic evaluation criteria
prior to approval. These criteria 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 Canada Sedimentary Basin. Within this focused area, we have a diversified
suite of assets producing from multiple geological zones and stretching from northeast
B.C. across much of Alberta. 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 major properties.
Reserves and Production
Company Interest Reserves - Forecast Prices and Costs
The following table sets forth a reconciliation of light, medium and heavy crude
oil, natural gas, natural gas liquids and total BOE of the Company Interest reserves
of PrimeWest for the year ended December 31, 2005. The table is derived from the
January 23, 2006 report of the independent reserve evaluators, GLJ Petroleum Consultants
Ltd. (GLJ), using forecast price and cost estimates, and reconciled to December
31, 2004 (the GLJ Report). PrimeWest's Company Interest reserves include working
interest and royalty reserves receivable. This definition is consistent with the
basis on which reserves were reported in prior years. See further discussion of
reserves definitions and National Instrument 51-101 (NI 51-101) under "Disclosure
of Oil and Gas Reserves - Standards of Disclosure for Oil and Gas Activities" below.
Forecast prices are based on the consultants' average price projections from GLJ
Petroleum Consultants Ltd., Sproule Associates Limited and McDaniel & Associates
Consultants Ltd., all of which are effective January 1, 2006.
Light, Medium and Heavy Crude Oil (mbbls)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 19,052 19,765 4,138 23,903
Capital Additions (1) 303 399 620 1,019
Improved Recovery (2) 474 501 189 690
Technical Revisions 806 760 (149) 611
Acquisitions 0 0 0 0
Dispositions (57) (57) (15) (72)
Economic Factors 0 0 0 0
Production (2,504) (2,504) 0 (2,504)
---------------------------------------------------------------------
Dec. 31, 2005 18,073 18,864 4,783 23,646
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding.
Natural Gas (Bcf)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 450.2 529.2 148.7 677.9
Capital Additions (1) 17.9 23.9 19.8 43.7
Improved Recovery (2) 10.6 23.7 2.0 25.7
Technical Revisions 10.1 1.3 (3.5) (2.2)
Acquisitions 0.2 0.2 0 0.2
Dispositions (2.6) (2.6) (0.4) (3.0)
Economic Factors 0 0 0 0
Production (65.0) (65.0) 0 (65.0)
---------------------------------------------------------------------
Dec. 31, 2005 421.4 510.7 166.6 677.3
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding
Natural Gas Liquids (mbbls)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 11,739 13,988 4,282 18,270
Capital additions (1) 462 675 564 1,239
Improved Recovery (2) 327 741 59 801
Technical Revisions (243) (549) (267) (816)
Acquisitions 0 0 0 0
Dispositions (36) (36) (4) (40)
Economic Factors 0 0 0 0
Production (1,386) (1,386) 0 (1,386)
---------------------------------------------------------------------
Dec. 31, 2005 10,864 13,434 4,634 18,068
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding.
Barrel of Oil Equivalent (mmBOE)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 105.8 121.9 33.3 155.2
Capital additions (1) 3.7 5.1 4.4 9.5
Improved Recovery (2) 2.6 5.2 0.6 5.8
Technical Revisions 2.2 0.4 (1.0) (0.6)
Acquisitions 0 0 0 0
Dispositions (0.5) (0.5) (0.1) (0.6)
Economic Factors 0 0 0 0
Production (14.7) (14.7) 0 (14.7)
---------------------------------------------------------------------
Dec. 31, 2005 99.2 117.4 37.2 154.6
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding
(1) Capital additions include exploration discoveries and drilling
extensions.
(2) Improved recovery includes infill drilling and improved recovery.
Net Reserves - Forecast Prices and Costs
The following table sets forth a reconciliation of PrimeWest's Net Reserves for
the year ended December 31, 2005 derived from the GLJ Report using forecast price
and cost estimates. These year end reserves are reconciled to December 31, 2004
reserves. PrimeWest's Net Reserves include working interest reserves plus royalties
receivable less royalties payable, as stipulated by NI 51-101. All data in the following
tables was provided by GLJ.
Light and Medium Crude Oil (mbbls)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 14,767 15,296 3,098 18,394
Capital Additions (1) 178 251 321 572
Improved Recovery (2) 369 389 146 535
Technical Revisions 268 261 (26) 235
Discoveries 0 0 0 0
Acquisitions 0 0 0 0
Dispositions (48) (48) (12) (60)
Economic Factors 137 133 17 150
Production (1,573) (1,573) 0 (1,573)
---------------------------------------------------------------------
Dec. 31, 2005 14,098 14,709 3,544 18,253
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding.
Heavy Oil (mbbls)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 2,541 2,623 503 3,126
Capital Additions (1) 85 85 178 263
Improved Recovery (2) 41 49 18 68
Technical Revisions 104 92 (103) (11)
Discoveries 0 0 0 0
Acquisitions 0 0 0 0
Dispositions 0 0 0 0
Economic Factors 149 151 34 185
Production (564) (564) 0 (564)
---------------------------------------------------------------------
Dec. 31, 2005 2,355 2,436 630 3,066
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding.
Associated and Non-Associated Gas (Bcf)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 358.2 420.4 117.6 538.0
Capital Additions (1) 14.0 17.9 14.6 32.6
Improved Recovery (2) 8.2 18.5 1.4 19.9
Technical Revisions 5.8 (0.2) (2.4) (2.7)
Discoveries 0.1 0.9 0.3 1.2
Acquisitions 0.1 0.1 0.0 0.2
Dispositions (1.9) (1.9) (0.3) (2.2)
Economic Factors 1.3 1.1 0.4 1.5
Production (49.5) (49.5) 0 (49.5)
---------------------------------------------------------------------
Dec. 31, 2005 336.4 407.2 131.7 539.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding.
Natural Gas Liquids (mbbls)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 8,308 9,911 3,008 12,919
Capital Additions (1) 306 416 374 790
Improved Recovery (2) 219 528 36 563
Technical Revisions (152) (381) (196) (577)
Discoveries 0 45 18 63
Acquisitions 0 0 0 0
Dispositions (24) (24) (3) (27)
Economic Factors (12) (22) (3) (25)
Production (977) (977) 0 (977)
---------------------------------------------------------------------
Dec. 31, 2005 7,668 9,495 3,234 12,729
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding.
Natural Gas from Coal (mmcf)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 0 0 0 0
Capital Additions (1) 0 226 395 621
Improved Recovery (2) 177 386 113 499
Technical Revisions 37 38 11 48
Discoveries 0 0 0 0
Acquisitions 0 0 0 0
Dispositions 0 0 0 0
Economic Factors 0 0 0 0
Production (44) (44) 0 (44)
---------------------------------------------------------------------
Dec. 31, 2005 171 606 518 1,124
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding.
Total (mmBOE)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
Dec. 31, 2004 85.3 97.9 26.2 124.1
Capital Additions (1) 2.9 3.8 3.4 7.2
Improved Recovery (2) 2.0 4.1 0.5 4.6
Technical Revisions 1.2 (0.1) (0.7) (0.8)
Discoveries 0.0 0.2 0.1 0.3
Acquisitions 0.0 0.0 0.0 0.0
Dispositions (0.4) (0.4) (0.1) (0.5)
Economic Factors 0.5 0.4 0.1 0.6
Production (11.4) (11.4) 0.0 (11.4)
---------------------------------------------------------------------
Dec. 31, 2005 80.2 94.6 29.5 124.1
---------------------------------------------------------------------
Columns may not add due to rounding.
Notes:
(1) Capital additions include exploration discoveries and drilling
extensions.
(2) Improved recovery includes infill drilling and improved recovery.
Reserves and Future Net Revenues
The following tables provide reserves data and a breakdown of reserves on a Company
Interest, Gross and Net basis and the net present value of future net revenues using
consultant's average pricing.
Reserves
---------------------------------------------------------------------
Light And Medium
Crude Oil (mbbl) Heavy Oil (mbbl)
---------------------------------------------------------------------
Reserves Company Company
Category Interest Gross Net Interest Gross Net
---------------------------------------------------------------------
Proved
Developed
Producing 15,512 13,959 14,098 2,561 2,550 2,355
Developed
Non-Producing 351 351 304 90 90 81
Undeveloped 350 331 307 0 0 0
---------------------------------------------------------------------
Total Proved 16,212 14,641 14,709 2,652 2,640 2,436
Probable 4,085 3,777 3,545 697 696 630
---------------------------------------------------------------------
Total Proved
Plus Probable 20,297 18,417 18,253 3,349 3,335 3,066
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding
Reserves
---------------------------------------------------------------------
Natural Gas
Natural Gas (Bcf) Liquids (mbbls)
---------------------------------------------------------------------
Reserves Company Company
Category Interest Gross Net Interest Gross Net
---------------------------------------------------------------------
Developed
Producing 421.4 411.8 336.6 10,864 10,635 7,668
Developed
Non-Producing 36.9 36.8 29.4 1,128 1,125 820
Undeveloped 52.5 52.5 41.9 1,442 1,442 1,008
---------------------------------------------------------------------
Total Proved 510.7 501.1 407.8 13,434 13,203 9,495
Probable 166.6 164.5 132.3 4,634 4,583 3,233
---------------------------------------------------------------------
Total Proved
Plus Probable 677.3 665.6 540.1 18,068 17,786 12,729
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding
Total (mBOE)
-------------------------------
Company
Interest Gross Net
---------------------------------------------------------------------
Proved
Developed Producing 99,162 95,778 80,214
Developed Non-Producing 7,724 7,697 6,106
Undeveloped 10,535 10,517 8,292
---------------------------------------------------------------------
Total Proved 117,422 113,993 94,612
Probable 37,181 36,474 29,450
---------------------------------------------------------------------
Total Proved Plus Probable 154,603 150,466 124,062
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding
Net Present Values of Future Net Revenue ($ millions)
---------------------------------------------------------------------
Before Future Income Tax Expenses
Discounted at (%)
---------------------------------------------------------------------
Reserves Category 0% 5% 10% 15% 20%
---------------------------------------------------------------------
Proved
Developed Producing 3,241.2 2,387.1 1,935.7 1,656.2 1,464.1
Developed Non-Producing 265.0 178.6 140.3 118.2 103.5
Undeveloped 277.7 179.8 128.9 97.9 76.9
---------------------------------------------------------------------
Total Proved 3,783.8 2,745.5 2,204.9 1,872.3 1,644.6
Probable 1,259.7 701.0 479.0 365.0 295.7
---------------------------------------------------------------------
Total Proved Plus
Probable 5,043.6 3,446.6 2,684.0 2,237.2 1,940.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Net Present Values Of Future Net Revenue ($ millions)
---------------------------------------------------------------------
After Future Income Tax Expenses
Discounted at (%)
---------------------------------------------------------------------
Reserves Category 0% 5% 10% 15% 20%
---------------------------------------------------------------------
Proved
Developed Producing 3,241.2 2,387.1 1,935.7 1,656.2 1,464.1
Developed Non-Producing 265.0 178.6 140.3 118.2 103.5
Undeveloped 277.7 179.8 128.9 97.9 76.9
Total Proved 3,783.8 2,745.5 2,204.9 1,872.3 1,644.7
Probable 1,259.7 701.0 479.0 365.0 295.7
---------------------------------------------------------------------
Total Proved Plus
Probable 5,043.6 3,446.6 2,684.0 2,237.2 1,940.4
---------------------------------------------------------------------
Columns may not add due to rounding
Daily Production Volumes
---------------------------------------------------------------------
2005 2004 Change (%)
---------------------------------------------------------------------
Natural gas (mmcf/day) 178.2 145.1 23
Crude oil (bbls/day) 6,861 8,282 (17)
Natural gas liquids (bbls/day) 3,797 3,107 22
---------------------------------------------------------------------
Total (BOE/day) 40,351 35,578 13
---------------------------------------------------------------------
Gross overriding royalty volumes
included above (BOE/day) 1,338 1,440 (7)
---------------------------------------------------------------------
All production information is reported before the deduction of Crown and freehold
royalties.
The 13% increase in daily average production year-over-year is due in part to the
acquisition of the Calpine assets in the third quarter of 2004, combined with production
additions from 2005 development activity, offset partially by the natural decline
of production. Based on 2005 production statistics, natural production decline is
estimated at approximately 17%. During 2005, approximately 2,900 BOE/day of annualized
incremental production was brought on-stream from development activities to help
offset natural decline. Approximately 2,200 BOE/day of new production remained "behind
pipe" or awaiting tie-in to production facilities, at the end of 2005.
PrimeWest expects production for full year 2006 to be 38,000 - 39,000 BOE/day. This
estimate incorporates PrimeWest's expected natural decline rate, production volume
shut-ins due to scheduled plant turnarounds at Crossfield, Caroline and Edson (estimated
to affect approximately 600 BOE/day on a full-year average basis), the reinstatement
effective January 1, 2006 of the Maximum Rate Limitation (MRL) on the Cecil wells
and others, all offset by production additions from the 2006 capital development
program.
Commodity Prices
---------------------------------------------------------------------
Average Benchmark Prices 2005 2004 Change (%)
---------------------------------------------------------------------
Natural Gas
NYMEX (US$/mcf) $ 8.55 $ 6.09 40
AECO (Cdn$/mcf) $ 8.48 $ 6.79 25
Crude oil - W.T.I. (US$/bbl) $ 56.56 $ 41.40 37
---------------------------------------------------------------------
---------------------------------------------------------------------
Average Realized Sales Prices(1)(Cdn$) 2005 2004 Change (%)
---------------------------------------------------------------------
Natural gas ($/mcf)(2) $ 8.43 $ 6.61 28
Crude oil ($/bbl) $ 49.05 $ 36.83 33
Natural gas liquids ($/bbl) $ 55.92 $ 43.69 28
---------------------------------------------------------------------
Total ($/BOE)(2) $ 50.81 $ 39.35 29
---------------------------------------------------------------------
Realized hedging loss included in
prices above ($/BOE) $ (3.01) $ (2.16) (39)
---------------------------------------------------------------------
(1) Includes realized hedging losses.
(2) Excludes sulphur.
The selling price that PrimeWest realized from its 2005 production, net of hedging
impact, was 29% higher than in 2004. The commodity hedging program resulted in a
reduction of PrimeWest's 2005 average realized price by $3.01/BOE, compared to a
reduction of $2.16/BOE in 2004. This hedging impact reflects the amount of additional
revenue foregone by PrimeWest as a result of its hedging program, through which
the price of a portion of its production was capped at certain price levels in exchange
for downward price protection. PrimeWest utilizes financial hedges as part of its
financial strategy to reduce the impact of commodity price volatility and to improve
the predictability of cash flow from operations.
The Canadian and US currency exchange rate is another factor that has an impact
on the price PrimeWest realizes from its production. Since Canadian prices of oil
and natural gas are influenced by benchmark prices that are set in US dollars, a
stronger Canadian dollar will translate into lower realized prices and revenues
when expressed in Canadian dollars. During 2005, the Canadian dollar exchange rate
increased by approximately 3% versus the US dollar, from US$0.831 at December 31,
2004 to US$0.858 at December 31, 2005. The stronger Canadian dollar during 2005
negatively impacted PrimeWest's Canadian realized prices and revenue receipts.
Crude Oil Prices
Continued growth in global oil demand combined with supply concerns resulted in
strong crude oil prices in 2005. On the demand side, robust economic growth in Asia,
notably in China and India, together with a strong consumer economy in the US have
increased worldwide oil consumption. Supply disruptions occurred in various parts
of the world, due to political uncertainty and natural disasters, such as hurricanes
Katrina and Rita, which shut down a large volume of production in the Gulf of Mexico.
Within OPEC, the excess production capacity that once existed among most members
was reduced by the increased demand. In 2005 Saudi Arabia, Kuwait and the United
Arab Emirates were the only OPEC member countries with meaningful spare capacity
that could be used to offset supply disruptions. As a result, oil prices fluctuated
throughout 2005 in response to world events and weather conditions. During 2005,
oil went from US$43.45/bbl at the beginning of the year to a historical high of
US$69.81/bbl on August 30, 2005, before dropping to US$61.04/bbl by year end.
The forward price of crude oil as at December 31, 2005 indicated a rising trend
over the next 12 months to approximately US$64.00/bbl by 2006 year end. Key factors
that are expected to influence prices in 2006 include: potential slow down in worldwide
demand growth, particularly in China and India, as a response to higher prices;
attempts by OPEC to influence prices by adjusting production quotas; the ability
of Iraq to restore more of its oil export capability and the rate and magnitude
of production growth from OPEC and non-OPEC producers.
The netbacks for Canadian companies and energy trusts that produce a heavier grade
of crude oil were negatively affected by a wide price differential versus lighter,
sweet crude in 2005. As the majority of crude production coming into the markets
worldwide was of heavier and more sour quality, the discount versus lighter oil
remained at a high level throughout 2005, as heavy-oil refining capacity was reaching
full utilization. In addition, the realized price for heavy oil producers was negatively
affected by an increase in the price of condensate, a natural gas by-product that
is widely used as a diluent to blend heavier crude oil for pipeline transport.
Approximately 32% of PrimeWest's crude oil production is made up of medium to slightly
heavy grades. These products do not require any diluent blending and attract a better
pricing differential than heavier crude oil production.
Natural Gas Prices
PrimeWest's realized natural gas prices in 2005 increased 28% to $8.43/mcf from
a 2004 average of $6.61/mcf. At the beginning of 2005, the outlook for natural gas
prices was markedly bearish due to mild winter weather and a decline in heating
demand. The natural gas storage level at the end of the 2005 winter season was higher
than at the end of the 2004 winter season, which had also experienced a warmer than
normal winter. Over the ensuing summer, this year-on-year storage overhang was gradually
worked off by the increased natural gas demands in response to hotter temperatures.
The impact of Hurricanes Katrina and Rita turned a surplus storage position into
deficit, causing a run-up of natural gas prices to approximately US$15.00/mmbtu
by early December. Prices began to soften in the latter part of December due to
unseasonably warm weather. At 2005 year end, North American natural gas storage
levels were approaching the five-year average. Forward natural gas prices as of
December 31, 2005 reflected a bullish trend, but have softened with the warm weather
in early 2006.
Key factors expected to influence prices in 2006 include: the speed of the restoration
of shut-in Gulf of Mexico production; North American weather patterns during the
upcoming summer and winter seasons; the ability of producers in Canada and the US
to replace and add to production levels through increased drilling; the continued
growth of natural gas demand in the electricity sector; and the impact of government
regulations and conservation efforts in response to higher natural gas prices.
Sales Revenue
---------------------------------------------------------------------
Revenue % of % of Change
($ millions)(1) 2005 Total 2004 Total (%)
---------------------------------------------------------------------
Natural gas (2) $ 548.0 73 $ 351.0 69 56
Crude oil 122.8 16 111.7 22 10
Natural gas liquids 77.5 11 49.7 9 56
---------------------------------------------------------------------
Total 748.3 512.4
---------------------------------------------------------------------
Hedging loss
included above $ (44.3) $ (28.2)
---------------------------------------------------------------------
(1) Net of transportation expense.
(2) Excludes sulphur.
PrimeWest's revenues from the sale of commodities for 2005 were $748.3 million compared
to $512.4 million in the previous year, including the effect of hedging. Higher
commodity prices along with increases in natural gas sales volumes were the major
contributors to the increased revenue in 2005.
If the pricing environment softens in 2006, and the Canadian dollar remains strong,
oil and natural gas revenues will be negatively impacted. Since approximately 73%
of PrimeWest's revenues are derived from natural gas, the Trust has greater sensitivity
to changes in natural gas prices than crude oil prices.
2005 Hedging Results
As part of our financial management strategy, PrimeWest uses a consistent commodity
hedging approach. The purposes of the hedging program are to reduce volatility in
cash flows, to protect acquisition economics against the unpredictable commodity
price environment and to protect our capital structure when commodity prices cycle
downwards, while at the same time retaining exposure to pricing upside. PrimeWest's
hedging policy reflects a willingness to forfeit a portion of the pricing upside
in return for protection against a significant downturn in prices.
Crude Oil Natural Gas BOE
($/bbl) ($/mcf)(1) ($/BOE)(1)
---------------------------------------------------------------------
2005 2004 2005 2004 2005 2004
---------------------------------------------------------------------
Unhedged Price $ 58.48 $ 44.46 $ 8.75 $ 6.70 $ 53.82 $ 41.51
Hedging Loss (9.43) (7.63) (0.32) (0.09) (3.01) (2.16)
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Realized Price $ 49.05 $ 36.83 8.43 $ 6.61 $ 50.81 $ 39.35
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(1) Excludes sulphur
2005 Hedging Loss 2004 Hedging Loss
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% Hedged $ millions % Hedged $ millions
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Crude Oil 60 $ 23.6 58 $ 23.1
Natural Gas 55 20.7 54 5.1
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Total $ 44.3 $ 28.2
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(1) Excludes sulphur
The table below shows the production volumes hedged at December 31,
2005.
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2006 Q1 Q2 Q3 Q4 Full Year
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Crude Oil (bbls/day) 4,000 3,000 2,000 2,000 2,750
Natural Gas (mmcf/day) 79 42 42 42 51
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2007
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Crude Oil (bbls/day) 500 500 0 0 250
Natural Gas (mmcf/day) 14 0 0 0 4
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A summary of hedging contracts in place as at December 31, 2005 is
available under Note 17 in the Notes to Consolidated Financial
Statements.
PrimeWest's derivatives are marked-to-market with the resulting gain or loss reflected
in earnings for the reporting period.
The 2005 income statement includes an unrealized loss of $11.6 million on derivatives
resulting from the change in the mark-to-market valuation of the derivative financial
instruments during the period. The loss was comprised of a $6.6 million gain for
crude oil hedges, an $18.3 million loss for natural gas hedges and a $0.1 million
gain for electrical power hedges.
For the year ended December 31, 2005 the cash impact of contract settlements was
a $43.5 million loss, comprised of a $23.6 million loss in crude oil, a $20.7 million
loss in natural gas, and a $0.8 million gain on electrical power.
Royalties
Royalties are paid by PrimeWest to the owners of mineral rights with whom PrimeWest
holds leases. PrimeWest has mineral leases with the Crown (provincial and federal
governments) and freeholders (individuals or other companies).
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($ millions, except per BOE) 2005 2004 Change (%)
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Royalty expense $ 172.8 $ 119.8 44
Per BOE $ 11.73 $ 9.20 28
Royalties as a percentage of
sales revenues
With hedge revenue 23% 23%
Excluding hedge revenue 22% 22%
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Royalty expenses as a percentage of sales have remained constant when compared to
the previous year.
The Crown royalty system is based on a sliding scale structure that increases the
royalty rates as commodity prices rise until a maximum rate is achieved. Because
of the sliding scale Crown royalty system, future changes to commodity prices will
result in changes to royalty rates and expenses.
Operating Expenses
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($ millions, except per BOE) 2005 2004 Change (%)
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Operating expense $ 117.0 $ 88.9 32
Per BOE $ 7.94 $ 6.83 16
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Operating expenses for 2005 increased $28.1 million or 32% over 2004 mainly due
to the increase in volumes resulting from the Calpine asset acquisition, which occurred
in the third quarter of 2004.
The increase in operating costs per BOE is due mainly to the effects of inflationary
pressures on the price of industry-related goods and services, due to the current
commodity price environment. Operating issues at the Valhalla plant and Boundary
Lake pipeline repairs and clean-up costs also contributed to the increase in operating
costs per BOE.
Operating Margin
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($/BOE) 2005 2004 Change (%)
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Sales price and other revenue (1) $ 51.70 $ 40.13 29
Transportation expense (0.49) (0.63) (22)
Royalties (11.73) (9.20) 28
Operating expense (7.94) (6.83) 16
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Operating margin $ 31.54 $ 23.47 34
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(1) Includes hedging and sulphur.
Operating margins increased 34% from 2004 on a per BOE basis. The increase in 2005
from 2004 is primarily due to higher sales prices, offset by higher per unit operating
expenses and higher royalties. Operating margin measures the level of cash flow
per BOE at the field level and before head office expenses.
G&A Expense
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2005 2004 Change
($ millions, except per BOE) restated (%)
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Cash G&A expense $ 22.9 $ 19.0 21
Per BOE $ 1.56 $ 1.46 7
Non-cash G&A expense $ 5.4 $ 4.1 32
Per BOE $ 0.37 $ 0.32 16
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Cash G&A expense increased 21% in 2005 from 2004, primarily due to higher staff
levels resulting in increased employee costs, office rent, property taxes and information
technology expenditures. These increases are primarily attributable to the Calpine
asset acquisition which occurred in the third quarter of 2004. The increases were
partially offset by overhead recoveries resulting from increases to capital expenditures
and operating expenses.
Included in non-cash G&A expense is $3.6 million relating to the UARs, granted under
the LTIP. UARs in the Trust are similar to stock options in a corporation. 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 the UARs until the Unitholders have first achieved a 5% total annual return from
the time of grant. PrimeWest continues to pay for the exercise of UARs in Trust
Units. Also included in non-cash G&A expense is $1.8 million related to the Special
Employee Retention Plan (SERP). See Note 18 in the Notes to Consolidated Financial
Statements.
Interest Expense
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($ millions, except per Trust Unit) 2005 2004 Change (%)
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Interest expense $ 28.3 $ 20.6 37
Period end net debt level $ 323.7 $ 552.0 (41)
Debt per Trust Unit $ 3.97 $ 7.77 (48)
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Average cost of debt 5.2% 4.8%
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Interest expense, representing interest on bank debt, the Secured Notes and the
Debentures increased to $28.3 million in 2005 from $20.6 million in 2004 due to
higher average debt balances in 2005 compared to 2004 mainly resulting from the
issuance of the Debentures to finance the Calpine acquisition. The Debentures also
increased the average cost of debt with interest rates of 7.50% and 7.75% for the
Series I and Series II Debentures respectively.
Net debt at December 31, 2005 is 41% lower than December 31, 2004 due to the repayment
of $111.0 million of the bank credit facility and to the conversion of $186.2 million
(net of accretion expense of $1.0 million) of Debentures into Trust Units.
Foreign Exchange Gain
The foreign exchange gain of $4.6 million resulted mainly from the translation of
the US dollar denominated Secured Notes and related interest payable into Canadian
dollars.
Depletion, Depreciation and Amortization (DD&A)
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($ millions, except per BOE amounts) 2005 2004 Change (%)
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Depletion, depreciation
and amortization $ 230.2 $ 197.3 17
Per BOE $ 15.63 $ 15.15
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The 2005 DD&A rate of $15.63/BOE is higher than the 2004 rate of $15.15/BOE mainly
due to the impact of the Calpine asset acquisition.
Gain on Sale of Marketable Securities
PrimeWest sold its 8% ownership in the Viking Energy Royalty Trust (formerly Calpine
Natural Gas Trust Units) in 2005 for net proceeds of $94.5 million, resulting in
a gain of $27.1 million.
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 reclamation and abandonment
costs incurred in 2005 were $8.7 million, compared to $4.6 million in 2004.
The 2005 contribution rate for the fund was unchanged from 2004 at $0.50/BOE, which
is expected to be sufficient to meet expenditure requirements for the future. As
at December 31, 2005, the site reclamation fund had a balance of $9.2 million.
Net Asset Value
Net asset value (NAV) measures the net worth of PrimeWest by subtracting the value
of debt from the estimated economic value of its underlying assets - primarily crude
oil, natural gas and natural gas liquids reserves. The value placed on these reserves
is the pre-tax present value of future net cash flows, discounted at 10%, as independently
assessed by GLJ as at January 1, 2006. The present value of reserves reflects provisions
for royalties, operating costs, future capital costs and site reclamation and abandonment
costs, but is prior to deductions for income taxes, interest expense and G&A expense.
This calculation is a "snapshot" in time and is heavily dependent upon future commodity
price expectations when the "snapshot" is taken. Accordingly, the NAV as at January
1, 2006 may not reflect fairly the equity market trading value of PrimeWest. It
is also significant to note that NAV declines as reserves are produced and net operating
cash flow is distributed to Unitholders. Value is delivered to Unitholders through
such monthly distributions.
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As at December 31 2005 2004
($ millions, except Consultant's Consultant's
per Trust Unit amounts) Average Average
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Assets
Present value of future net cash
flow discounted at 10% (1)(3) $ 2,684.0 $ 1,714.4
Market value of Viking Energy
Royalty Trust Units - 91.0
Mark-to-market value of hedging contracts (11.5) 0.1
Unproved lands 151.3 103.9
Reclamation fund 9.2 10.3
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$ 2,833.0 $ 1,919.7
Liabilities
Debt and working capital surplus (2) (267.9) (378.5)
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Net asset value $ 2,565.1 $ 1,541.2
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Outstanding Trust Units - millions,
diluted 83.7 80.5
Net asset value per Trust Unit $ 30.64 $ 19.15
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(1) Company Interest Proved plus Probable reserves
(2) Debt excludes Debentures
(3) Refer to Summary of Oil and Natural Gas Reserves and Net Present
Values of Future Net Revenues table under the section "Disclosure
of Oil and Natural Gas Reserves".
2005 2004
Consultant's Consultant's
Price Assumptions Average Average
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Edmonton Par Oil - Cdn$/bbl
2005 $ - $ 50.37
2006 $ 67.64 $ 47.46
2007 $ 66.40 $ 43.88
2008 $ 60.89 $ 40.89
2009 $ 56.83 $ 39.20
2010 $ 54.25 $ -
Spot Gas at AECO-C - Cdn$/mcf
2005 $ - $ 6.79
2006 $ 10.93 $ 6.52
2007 $ 9.88 $ 6.25
2008 $ 8.48 $ 5.95
2009 $ 7.59 $ 5.79
2010 $ 7.23 $ -
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The NAV calculation is based on the above reference prices as of December 31, 2005
and 2004 and is highly sensitive to changes in price forecasts over time as well
as in the exchange rate. In addition, the year-over-year change is impacted by the
cash distributions made throughout the year, which totaled $276.6 million or $3.66
per Trust Unit in 2005. Also, the NAV calculation assumes a "blow down" scenario
whereby existing reserves are produced without being replaced by acquisitions and
development. A major cornerstone of PrimeWest's strategy is to replace reserves
through accretive acquisitions and capital development.
Income and Capital Taxes
---------------------------------------------------------------------
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2005 2004 Change
($ millions) restated (%)
---------------------------------------------------------------------
Income and capital taxes $ 2.8 $ 3.3 (15)
Future income tax recovery (14.8) (34.3) 57
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Total income and capital taxes and
future income tax recovery $ (12.0) $ (31.0)
---------------------------------------------------------------------
The decrease in the future income tax recovery is due to the increase in net income
resulting primarily from higher oil and natural gas revenues.
Net Income
---------------------------------------------------------------------
2005 2004 Change
($ millions) restated (%)
---------------------------------------------------------------------
Net income $ 207.5 $ 105.4 97
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Cash flow from operations, as opposed to net income, is the primary measure of performance
for an energy trust. The generation of cash flow is critical to the ability of an
energy trust to continue to sustain the monthly distribution of cash 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 the unrealized
gains or losses on derivatives, foreign exchange gains or losses, DD&A and future
income taxes.
Net income of $207.5 million in 2005 was higher than 2004 net income of $105.4 million
primarily due to the increase in net oil and natural gas revenues resulting from
increases to commodity prices and production volumes. Increases to operating expenses,
DD&A, the unrealized loss on derivatives and lower future income tax recovery had
a negative impact on net income.
Liquidity and Capital Resources
---------------------------------------------------------------------
Long-Term Debt ($ millions) 2005 2004 Change (%)
---------------------------------------------------------------------
Long-term debt $ 354.2 $ 656.3 (46)
Working capital surplus (1) (30.5) (104.3) (71)
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Net debt 323.7 552.0 (41)
Market value of Trust Units and
Exchangeable Shares outstanding (2) 2,884.7 1,877.7 54
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Total capitalization $ 3,208.4 $ 2,429.7 32
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Net debt as a % of total
capitalization 10% 23%
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(1) Working capital surplus excludes financial derivative assets and
liabilities and current future income tax assets.
(2) Based on December 31, 2005 Trust Unit closing price of $35.90 and
exchangeable share ratio of 0.56399:1.
Long-term debt is comprised of bank credit facilities, Secured Notes and Debentures
of $153.0 million, $145.4 million and $55.8 million, respectively.
PrimeWest had a borrowing base of $650 million at December 31, 2005. The bank credit
facilities consist of an available revolving term loan of $458.7 million and an
operating facility of $35 million, with the balance being attributed to the Secured
Notes valued at $156.3 million based on the agreed US dollar exchange rate at the
time of last renewal. In addition to the amounts outstanding under the bank credit
facility, PrimeWest has outstanding letters of credit in the amount of $6.6 million
(2004 - $4.9 million). The credit facility revolves until June 30, 2006, by which
time the lenders will have conducted their annual borrowing base review.
The Secured Notes in the amount of US$125 million have a final maturity date of
May 7, 2010, and bear interest at 4.19% per annum, with interest paid semi-annually
on November 7 and May 7 of each year. The Note Purchase Agreement requires PrimeWest
to make four annual principal repayments of US$31,250,000 commencing May 7, 2007.
PrimeWest issued the 7.5% (Series I) and 7.75% (Series II) Debentures in the third
quarter of 2004 for proceeds of $150.0 million and $100.0 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 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 a price of $1,000 per Series
II Debenture. On redemption or maturity the Trust may elect to satisfy its obligations
to repay the principal by issuing Trust Units.
PrimeWest's net debt at December 31, 2005 was lower than at December 31, 2004 due
to the conversion of $114.3 million of Series I and $72.9 million of Series II Debentures,
offset by accretion of $1.0 million. In addition, cash flow from operations in excess
of distributions allowed for the repayment of $111.0 million of the bank credit
facility.
Unitholders' Equity
The Trust had 79,666,352 Trust Units outstanding at December 31, 2005 compared to
69,886,111 Trust Units at the end of 2004. In addition, there were 1,219,335 Exchangeable
Shares (see below) outstanding at year end, exchangeable into a total of 687,693
Trust Units. The weighted average number of Trust Units, including those issuable
by the exchange of Exchangeable Shares, was 75,808,919 Trust Units for the twelve
month period ended December 31, 2005 compared to 59,482,034 in 2004.
During the year, 487,421 Trust Units were issued to employees pursuant to the LTIP.
During 2005, PrimeWest issued 262,347 Trust Units under the DRIP for $7.9 million
(2004 - 268,677 Trust Units, $6.5 million), 932,142 Trust Units for $27.4 million
pursuant to the PREP (2004 - 1,311,462 Trust Units, $32.0 million) and 704,806 Trust
Units for $20.4 million pursuant to the OTUPP in 2005 (2004 - 894,167 Trust Units,
$21.5 million).
The DRIP gives Canadian and US Unitholders the opportunity to reinvest their monthly
distributions at a 5% discount to the volume-weighted average market price of the
Trust Units. As an alternative to the DRIP component of the Plan, 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 OTUPP gives Canadian
Unitholders an opportunity to purchase additional Trust Units directly from PrimeWest
at the same 5% discount. The DRIP and PREP components are mutually exclusive. Participation
in the OTUPP requires enrolment in either the DRIP or PREP.
These plan components benefit Unitholders by offering alternatives to maximize their
investment in PrimeWest, while providing the Trust with an inexpensive method of
raising additional capital. The Trust expects interest in these plans in 2006 to
be similar to 2005. Proceeds from these plans are used for debt reduction of PrimeWest's
credit facility and to help fund ongoing capital development programs.
For additional information or to join these plans, contact the plan agent for the
DRIP, OTUPP and PREP, Computershare Trust Company of Canada at 1-800-564-6253 or
visit PrimeWest's website at
www.primewestenergy.com.
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.
In 2005, 94,340 Exchangeable Shares were issued pursuant to the SERP (2004 - 94,340).
See Note 18 in Notes to Consolidated Financial Statements.
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 December 31, 2005, there were 1,219,335 Exchangeable Shares outstanding. The
exchange ratio was 0.56399:1 Trust Units for each Exchangeable Share at year end.
For purposes of calculating basic per Trust Unit amounts, these Exchangeable Shares
have been assumed to be exchanged into Trust Units at the current exchange ratio.
Cash Distributions
Since August 2003, PrimeWest has followed a strategy of targeting a distribution
payout ratio within 70-90% of cash flow, calculated on an annual basis. The recent
strength in commodity prices has increased the Trust's cash flow from operations
available for distribution to Unitholders. The Board of Directors of PrimeWest will
continue to consider a variety of factors in establishing the monthly distribution
level. These factors include, but are not limited to: commodity price outlook, cash
flow forecast, capital development plans, debt levels, taxability considerations
and competitive industry distribution practices.
Cash distributions for 2005 were $276.6 million or $3.66 per Trust Unit, representing
a payout ratio of approximately 67% versus 2004 amounts of $196.1 million or $3.30
per Trust Unit, representing a payout ratio of approximately 74%.
Distribution payments to US Unitholders are subject to a 15% Canadian withholding
tax, which is deducted from the distribution amount prior to deposit into accounts.
Cash Flow Sensitivities
---------------------------------------------------------------------
Increase to
Annual Cash Flow
$/Trust Unit (1)
---------------------------------------------------------------------
Crude oil price (US$1.00/bbl WTI