PrimeWest Energy Trust Announces 2006 Financial and Operating Results
FEB 21, 2007 - 21:37 ET
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2006
CALGARY, ALBERTA--(CCNMatthews - Feb. 21, 2007) - PRIMEWEST ENERGY TRUST (TSX:PWI.UN)
(TSX:PWI.DB.A) (TSX:PWI.DB.B) (TSX:PWI.DB.C) (TSX:PWX) (NYSE:PWI) (PRIMEWEST OR
THE TRUST) TODAY ANNOUNCES OPERATING AND FINANCIAL RESULTS FOR THE QUARTER AND YEAR
ENDED DECEMBER 31, 2006. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT
ARE IN CANADIAN DOLLARS.
2006 Highlights:
- Distributions for 2006 were $3.75 per Trust Unit representing a payout ratio of
approximately 84% funds flow from operations compared to 2005 distributions of $3.66
per Trust Unit, which represented a payout ratio of approximately 68% of funds flow
from operations.
- Funds flow from operations for 2006 was $364.1 million ($4.43 per Trust Unit)
compared to $405.4 million ($5.35 per Trust Unit) in 2005.
- 2006 production averaged 39,321 BOE per day, compared to the 2005 rate of 40,351
BOE per day.
- Capital development program of $261.0 million added 23.2 mmBOE of Proved plus
Probable reserves on a Company Interest basis at an average of $11.22/BOE of reserves
added, which excludes $5.24/BOE for changes in future development capital. The capital
development program replaced 162% of the 2006 production on a Proved plus Probable
basis. PrimeWest's Reserve Life Index (RLI) at year end 2006 is 13.4 years on a
Company Interest Proved plus Probable basis. PrimeWest has identified a portfolio
of capital opportunities in excess of $1 billion to be developed over the next several
years.
- On July 6, 2006, PrimeWest through a U.S. subsidiary, acquired producing oil and
gas assets located in Montana, North Dakota, Wyoming and Saskatchewan for consideration
of $336.7 million. The acquisition established a new operating area for PrimeWest
within the Williston Basin with considerable waterflood and development drilling
potential. The U.S. assets 2006 annualized production was 1,349 barrels of oil equivalent
(BOE) per day.
- On August 25, 2006, PrimeWest acquired natural gas assets in the Caroline area
for a net adjusted purchase price of $31.9 million. The acquisition of these assets,
already operated by PrimeWest, represents the conclusion of a farm in arrangement
between PrimeWest and the vendor.
- Net debt to annualized 2006 funds flow from operations was approximately 2.3 times
at December 31, 2006 compared to net debt to annualized 2005 funds flow from operations
of 0.8 times at December 31, 2005. This increase is primarily due to additional
debt utilized to finance the U.S. asset acquisition.
- For details on the fourth quarter 2006 results see Summary of Fourth Quarter Results
of this release.
- On October 31, 2006, the federal government announced its intention to change
the way that royalty trusts and income funds are taxed, which would take effect
January 1, 2011.
- PrimeWest is using "funds flow from operations" as a key performance indicator
of its ability to generate cash. Funds flow from operations is measured as cash
flow from operating activities before changes in working capital. Funds flow from
operations includes site reclamation and restoration expenditures of $14.3 million
in 2006 (2005 - $8.7 million).
Subsequent Event
- On January 11, 2007, PrimeWest sold 6,420,000 Trust Units at $23.35 per Trust
Unit, resulting in gross proceeds of $149.9 million and a total of $200 million
aggregate principal amount of five-year convertible unsecured subordinated debentures.
The debentures bear a coupon rate of 6.5 % per annum, payable semi-annually, and
are convertible at $26.25 per Trust Unit. The total net proceeds from the offering
of Trust Units and convertible debentures were approximately $334 million. The proceeds
were used to repay a portion of the outstanding credit facility.
MANAGEMENT'S DISCUSSION AND ANALYSIS
THE FOLLOWING IS MANAGEMENT'S DISCUSSION AND ANALYSIS (MD&A) AS AT FEBRUARY 21,
2007, OF PRIMEWEST ENERGY TRUST'S (REFERRED TO HEREINAFTER AS PRIMEWEST OR THE TRUST)
OPERATING AND FINANCIAL RESULTS FOR THE YEAR ENDED DECEMBER 31, 2006, THE CORRESPONDING
PERIOD IN THE PRIOR YEAR AS WELL AS INFORMATION AND OPINIONS CONCERNING THE TRUST'S
OUTLOOK BASED ON CURRENTLY AVAILABLE INFORMATION. THIS DISCUSSION SHOULD BE READ
IN CONJUNCTION WITH THE TRUST'S CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS
ENDED DECEMBER 31, 2006, AND 2005, TOGETHER WITH ACCOMPANYING NOTES.
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Financial ($ Millions, except per BOE (1) and
Per Trust Unit amounts) 2006 2005 Change (%)
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Gross revenue $ 698.5 $ 801.2 (13)
Per BOE 48.67 54.40 (11)
Funds flow from operations (2) 364.1 405.4 (10)
Per BOE 25.37 27.52 (8)
Per Trust Unit - Basic (3) 4.43 5.35 (17)
Per Trust Unit - Diluted (4) 4.37 4.91 (11)
Royalty expense 144.8 172.8 (16)
Per BOE 10.09 11.73 (14)
Operating expense 138.9 117.8 18
Per BOE 9.68 8.00 21
General and administrative expense (G&A) (5) 30.4 28.3 7
Per BOE 2.12 1.93 10
Interest expense (6) 34.7 28.3 23
Per BOE 2.41 1.92 26
Net income 208.3 207.5 -
Per Trust Unit - Basic (3) 2.53 2.73 (7)
Per Trust Unit - Diluted (4) 2.52 2.66 (5)
Distributions to Unitholders 305.8 276.6 11
Per Trust Unit (7) 3.75 3.66 2
Net debt (8) 820.8 323.7 154
Per Trust Unit (9) 9.74 3.97 145
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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 necessarily represent a value equivalency at
the wellhead.
(2) See Non-GAAP Measures for definition of funds flow from operations.
(3) The basic per Trust Unit calculation includes the weighted average
Trust Units outstanding and Trust Units issueable upon exchange of the
outstanding Exchangeable Shares of PrimeWest Energy Inc. (Exchangeable
Shares).
(4) The diluted per Trust Unit calculation includes the weighted average
Trust Units outstanding, Trust Units issueable upon exchange of the
outstanding Exchangeable Shares, the deemed conversion of the Series I
and Series II Convertible Unsecured Subordinated Debentures
(Debentures) and Trust Units issueable 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.
(5) Includes cash and non-cash expenses.
(6) Interest expense includes the interest on the Debentures.
(7) Based on Trust Units outstanding at the applicable Record Dates.
(8) Net debt is long-term debt including Debentures less working capital,
excluding financial derivative assets and liabilities and current
future income tax assets and liabilities.
(See Non-GAAP Financial Measures)
(9) The net debt per Trust Unit calculation includes outstanding Trust
Units, Trust Units issueable upon exchange of the outstanding
Exchangeable Shares and Trust Units issueable pursuant to the LTIP
at the end of the period.
Operating Highlights
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Daily Production Volumes 2006 2005 Change (%)
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Natural gas (mmcf/day) 166.0 178.2 (7)
Crude oil (bbls/day) 7,816 6,861 14
Natural gas liquids (bbls/day) 3,835 3,797 1
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Total BOE/day 39,321 40,351 (3)
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Realized Commodity Prices
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2006 2005 Change (%)
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Natural gas ($/mcf) (1) 7.09 8.75 (19)
Crude oil ($/bbl) 62.42 58.48 7
Natural gas liquids ($/bbl) 59.09 55.92 6
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Total ($/BOE) (1) 48.09 53.82 (11)
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Realized derivative gains/(losses) ($/BOE) 1.64 (3.01)
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Net realized price ($/BOE) 49.73 50.81 (2)
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(1) Excludes sulphur.
Forward-Looking Information
This MD&A contains forward-looking or outlook information with respect to PrimeWest.
Certain statements contained in 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 this MD&A.
These statements speak only 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, 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 there from;
- The impact of the Canadian federal and provincial governmental regulations 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, 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:
- 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;
- Tax treatment of the trust and its subsidiaries;
- 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 could 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 in this MD&A.
These factors should not be construed as exhaustive. The forward-looking statements
contained in this MD&A are expressly qualified by this cautionary statement. Except
as may be required by applicable securities laws we undertake no obligation to publicly
update or revise any forward-looking statements.
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, 2006, and concluded that PrimeWest's disclosure controls and
procedures were effective to ensure that information PrimeWest is required to disclose:
- In its annual filings and interim filings (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
and interim filings 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 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.
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, 2006, 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):
- Funds flow from operations on a total and per Trust Unit basis;
- Distributions per Trust Unit; and
- Net debt per Trust Unit.
These measures do not have any standardized meaning prescribed by GAAP and are therefore
unlikely to be comparable to similar measures presented by other issuers.
Funds flow from operations is measured as cash flow from operating activities before
changes in non-cash working capital. Funds flow from operations ("funds flow") does
not represent operating cash flows or operating profits for the period and should
not be viewed as an alternative to cash flow from operating activities calculated
in accordance with GAAP. Funds flow from operations is a key performance indicator
of PrimeWest's ability to generate cash and finance operations and pay monthly distributions.
Funds flow from operations per Trust Unit on a basic basis is calculated by dividing
funds flow from operations by the weighted average number of Trust Units outstanding
plus Trust Units issueable upon the exchange of the outstanding Exchangeable Shares
of PrimeWest Energy Inc. Funds flow from operations per Trust Unit on a diluted
basis is calculated using funds flow from operations and adding back the interest
expense on the 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 issueable
upon the exchange of outstanding Exchangeable Shares and includes the Trust issueable
pursuant to the conversion of the Debentures, and Trust Units issueable pursuant
to LTIP.
Distributions per Trust Unit disclose the cash distributions accrued in 2006 based
on the number of Trust Units outstanding on the applicable Record Dates.
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 and liabilities divided by the number of Trust Units outstanding
and Trust Units issueable upon the exchange of outstanding Exchangeable Shares and
Trust Units issueable pursuant to the LTIP at December 31, 2006.
Business Strategy
PrimeWest Energy Trust is an Alberta based conventional oil and natural gas royalty
trust actively managed to generate monthly cash distributions for the holders of
Trust Units (Unitholders). The Trust's operations are focused in the Western Canada
Sedimentary Basin and Montana, North Dakota and Wyoming in the United States. 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 2006 and our goals for 2007 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 core areas and pursue
depletion optimization strategies within those core areas to maximize asset value.
We make every effort to obtain operatorship of our asset base and maintain high
working interests in core areas. We currently maintain operatorship of approximately
80% of our assets, which allows us to use existing infrastructure and synergies
within our core areas. We believe this high level of control can translate into
cost efficiencies 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, U.S.-dollar-denominated Senior Secured Notes (U.S. Secured Notes), Pounds
Sterling denominated Senior Secured Notes (U.K. Secured Notes) and Debentures. Our
diversified debt instruments help to reduce our reliance on the bank syndicate.
PrimeWest's commodity hedging strategy is designed to reduce the volatility of cash
flow by providing some near term downside price protection. Hedging a portion of
our production protects acquisition economics and our capital structure and provides
partial protection against short-term declines in commodity prices. Since 2003,
PrimeWest has followed a strategy of maintaining a distribution payout ratio within
70-90% of funds flow from operations, calculated on an annual basis, recognizing
that during periods of volatile commodity prices the payout ratio may move out of
this range. The Board of Directors of PrimeWest considers a variety of factors in
establishing the monthly distribution level including, but not limited to: commodity
price outlook, cash flow forecast, capital development plans, debt levels, tax considerations
and competitive industry distribution practices. Further, the October 31 Proposals
discussed below under Taxation of the Trust, have created additional uncertainty
with respect to the payout ratio. At this time, PrimeWest is unable to predict what
payout ratio it will be able to maintain in the future.
The 2006 payout ratio (being the ratio of distributions paid or declared to funds
flow from operations) was approximately 84% of funds flow from operations. Retained
cash flow was utilized to fund a part of the Trust's capital spending program. PrimeWest's
ratio of net debt to annual funds flow from operations was approximately 2.3 times
at December 31, 2006.
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 U.S. Unitholders to conveniently trade in our Trust Units,
and allows us to access the U.S. capital markets. Our status as a corporation for
U.S. tax purposes simplifies tax reporting for our U.S. Unitholders.
For eligible Canadian and U.S. 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 issued and outstanding.
Taxation of the Trust
On October 31, 2006, the Minister of Finance (Canada) ("Finance") announced proposed
changes to the taxation of certain publicly-traded trusts and partnerships and their
unitholders. These changes, assuming they are enacted, would apply, in the case
of trusts, to a trust that is resident in Canada for purposes of the Tax Act, holds
one or more "non-portfolio properties", and the units of which are listed on a stock
exchange or other public market (a "specified investment flow-through trust", or
"SIFT trust"). In the case of a SIFT trust the units of which were already publicly
traded on October 31, 2006, the proposed changes generally would not take effect
until January 1, 2011, provided the trust experiences only "normal growth" and no
"undue expansion" before then. On December 15, 2006, Finance issued guidelines with
respect to what would be considered "normal growth" for this purpose, and on December
21, 2006, Finance released draft legislative proposals to implement the changes
previously announced on October 31, 2006. On January 30, 2007, Finance confirmed
the Government's intention to proceed with these proposals. The October 31, 2006
proposals, December 15, 2006 guidelines, and December 21, 2006 draft legislation,
are hereinafter collectively referred to as the "October 31 Proposals".
Until such time as the October 31 Proposals apply to the Trust, which is not expected
to be until January 1, 2011, it is expected that:
a) the Trust will continue not to be liable for any material amount of Canadian
income tax;
b) returns on capital generally will be taxed as ordinary income or as dividends
in the hands of a Unitholder who is resident in Canada for purposes of the Tax Act,
and will be subject to withholding tax at a rate of 25% (subject to a reduction
in such rate under the terms of an applicable tax treaty or convention) when paid
to a non-resident Unitholder;
c) returns of capital paid to a Unitholder who is resident in Canada for purposes
of the Tax Act generally will not be included in the Unitholder's income but will
reduce the adjusted cost base of the Unitholder's Trust Units; and
d) returns of capital paid to a non-resident Unitholder will be subject to the special
15% Canadian withholding tax under Part XIII.2 of the Tax Act.
Pursuant to the October 31 Proposals, commencing January 1, 2011, the Trust will
be subject to tax on its income from non-portfolio properties and taxable capital
gains from dispositions of non-portfolio properties, that is paid or payable to
Unitholders, at a rate of 30.5% (comparable to the projected combined federal and
provincial corporate income tax rate in 2011), and distributions of such income
to Unitholders will be treated as dividends paid by a taxable Canadian corporation.
The Royalty and the shares and notes of PrimeWest will constitute "non-portfolio
properties" of the Trust under the October 31 Proposals, with the result that virtually
all of the Trust's income, including any taxable capital gains, would be subject
to the 30.5% tax, and distributions of such income by the Trust to its Unitholders
would be treated as dividends paid by a taxable Canadian corporation. Returns of
capital by the Trust to its Unitholders would not be affected by the October 31
Proposals and would continue to be taxed in the same manner as under the current
rules.
As noted above, the Trust could become subject to these changes before 2011 if it
experiences growth, other than "normal growth", before that time. Under the December
15, 2006 guidelines, the Trust will be considered to have experienced only "normal
growth" if its issuances of new equity (which for this purpose includes Trust Units
and debt that is convertible into Trust Units, but does not include non-convertible
debt) do not exceed, for each of the intervening periods set forth below, a safe
harbour measured by reference to the Trust's market capitalization as of the end
of trading on October 31, 2006 (measured solely by the value of the Trust's issued
and outstanding publicly-traded Trust Units as of that date). The Trust's market
capitalization as of October 31, 2006, was approximately $2.379 billion. The intervening
periods and their respective safe harbour amounts are as follows:
e) November 1, 2006 to December 31, 2007 - 40% of the Trust's market capitalization
as of October 31, 2006;
f) January 1, 2008 to December 31, 2008 - 20% of the Trust's market capitalization
as of October 31, 2006;
g) January 1, 2009 to December 31, 2009 - 20% of the Trust's market capitalization
as of October 31, 2006;
h) January 1, 2010 to December 31, 2010 - 20% of the Trust's market capitalization
as of October 31, 2006.
The December 15, 2006 guidelines provide that these annual safe harbour amounts
are cumulative, and that replacing debt that was outstanding as of October 31, 2006
with new equity, whether through a debenture conversion or otherwise, will not be
considered growth for these purposes. In addition, an issuance of new equity will
not be considered growth to the extent that the issuance is made in satisfaction
of the exercise by another person of a right in place on October 31, 2006 to exchange
an interest in a partnership, or a share of a corporation, for Trust Units.
Corporate Governance
PrimeWest is 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 contained
in the Trust's Management Proxy Circular for its upcoming annual general meeting
and 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.
Financial and Operating Highlights
- Production in 2006 averaged 39,321 BOE/day, down 3% from the 2005 level of 40,351
BOE/day, as a result of natural production decline exceeding volumes added from
development capital expenditures and acquisitions.
- Operating margin decreased 3% from 2005 to $30.48/BOE for 2006, primarily due
to lower natural gas prices and natural gas volumes, as well as higher operating
costs. Derivative gains and increases to crude oil prices and oil volumes had a
positive impact on the operating margin.
- Distributions were $3.75 per Trust Unit in 2006 compared to $3.66 per Trust Unit
in 2005. The distribution level was reduced in June 2006 from $0.36 per Trust Unit
monthly to $0.30 per Trust Unit monthly and in October 2006 to $0.25 per Trust Unit
monthly. PrimeWest's payout ratio for 2006 was approximately 84% compared to the
2005 payout ratio of 68%.
- On July 6, 2006, PrimeWest through a U.S. subsidiary, acquired producing oil and
gas assets located in Montana, North Dakota, Wyoming and Saskatchewan for consideration
of $336.7 million. The acquisition establishes a new operating area for PrimeWest
within the Williston Basin with considerable waterflood and development drilling
potential.
- On August 25, 2006, PrimeWest acquired natural gas assets in the Caroline area
for a net adjusted purchase price of $31.9 million. The acquisition of these assets,
already operated by PrimeWest, represents the conclusion of a farm in arrangement
between PrimeWest and the vendor.
- Capital development program of $261.0 million added 23.2 mmBOE of Proved plus
Probable reserves (including technical revisions) on a Company Interest basis at
an average of $11.22/BOE of reserves added, which excludes $5.24/BOE for the change
in future development capital. The capital development program replaced 162% of
the 2006 production on a Proved plus Probable basis.
- PrimeWest's Reserve Life Index at year-end 2006 is 13.4 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 18% higher in 2006 than in 2005, reflecting the acquisition
of the U.S. assets in July 2006 and higher industry-wide cost pressures. On a unit
of production basis, operating expenses were 21% higher than in 2005 at $9.68/BOE
versus $8.00/BOE.
- Cash G&A increased $1.7 million over 2005 reflecting increases in employee costs
and the impact of acquiring the U.S. assets offset by increases in overhead recoveries.
- Interest expense during 2006 was 23% higher than in 2005 due to a higher average
net debt balance and higher interest rates during the year resulting mainly from
the issuance of additional debt in the third quarter of 2006 to acquire the U.S.
assets.
- The DRIP, PREP and OTUPP collectively contributed $56.1 million of equity capital
to be reinvested in the capital development program.
Outlook 2007
PrimeWest expects 2007 production volumes to average approximately 39,000 - 40,000
BOE/day. Full-year operating costs are expected to be approximately $10.00/BOE.
PrimeWest expects to invest approximately $230 - $255 million in its 2007 capital
development program, with the focus primarily in the core areas of Caroline, Columbia,
Wilson Creek, Crossfield, Valhalla, Laprise and the U.S. assets.
Funds Flow From Operations Reconciliation
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($ Millions)
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2005 funds flow from operations $ 405.4
Production volumes (17.6)
Commodity prices (84.8)
Net change in realized derivative gain 69.0
Operating expense (21.2)
Royalties 28.0
Site restoration and reclamation (5.6)
Interest expense (7.1)
Other (2.0)
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2006 funds flow from operations $ 364.1
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The funds flow from operations reconciliation includes non-GAAP
measurements (refer to discussion on non-GAAP measures).
The key performance driver for the Trust is funds flow from operations, which directly
affects PrimeWest's ability to pay monthly distributions. Funds 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, site
restoration and reclamation expenditures, interest expenses, G&A expenses, 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 expenses, as well as interest and G&A expense.
Selected Canadian and U.S. Financial Results
Prior to 2006, PrimeWest had focused on oil and natural gas plays in Western Canada.
In July 2006 PrimeWest acquired the U.S. assets. The following table provides selected
financial results from PrimeWest's Canadian and U.S. operations for the twelve months
ended December 31, 2006. The financial results for the U.S. operations are for the
period July - December 2006.
Twelve Months ended Dec 31, 2006
---------------------------------------------------------------------------
($ Millions, except production
volumes and per unit prices) Canada U.S. Total
---------------------------------------------------------------------------
Daily Production Volumes
Natural gas (mmcf/day) 165.4 0.6 166.0
Crude oil (bbls/day) 6,587 1,229 7,816
Natural gas liquids (bbls/day) 3,810 25 3,835
Total daily sales (BOE/day) 37,972 1,349 39,321
---------------------------------------------------------------------------
Pricing (1)
Natural gas ($/mcf) 7.09 7.00 7.09
Crude oil ($/bbl) 62.54 61.78 62.42
Natural gas liquids ($/bbl) 59.32 25.11 59.09
---------------------------------------------------------------------------
Revenues ($ Millions)
Natural gas (1)(2) 427.9 1.5 429.4
Crude oil (1) 150.4 27.7 178.1
Natural gas liquids (1) 82.5 0.2 82.7
Realized derivative gains 23.3 2.2 25.5
Royalties (138.6) (6.2) (144.8)
---------------------------------------------------------------------------
Expenses ($ Millions)
Operating 131.6 7.3 138.9
G&A 28.9 1.5 30.4
Depletion, depreciation and
amortization 225.2 9.8 235.0
Income and capital taxes 0.7 0.8 1.5
---------------------------------------------------------------------------
Capital Expenditures ($ Millions)
Development 255.6 5.4 261.0
Acquisition of oil and gas properties 35.5 334.1 369.6
Disposition of oil and gas properties (3.5) - (3.5)
---------------------------------------------------------------------------
(1) Net of transportation expense. Excludes realized and unrealized
derivative gains and losses.
(2) Excludes sulphur.
The Trust did not have any U.S. operations prior to July 2006.
Capital Expenditures
---------------------------------------------------------------------------
($ Millions) 2006 2005
---------------------------------------------------------------------------
Land and lease acquisitions $ 10.5 $ 17.6
Geological and geophysical 3.2 7.6
Drilling and completions 168.4 106.5
Equipping and tie-in 47.9 26.5
Gas gathering and compression 13.1 13.0
Production facilities 12.7 11.5
Capitalized G&A expense 5.2 2.9
---------------------------------------------------------------------------
Development Capital $ 261.0 $ 185.6
---------------------------------------------------------------------------
Corporate/property acquisitions 369.6 2.7
Dispositions (3.5) (20.6)
Leasehold improvements, furniture & equipment 3.5 4.2
---------------------------------------------------------------------------
Total $ 630.6 $ 171.9
---------------------------------------------------------------------------
On July 6, 2006, PrimeWest acquired U.S. assets located in Montana, North Dakota,
Wyoming and Saskatchewan for $336.7 million. The acquisition established a new operating
area within the Williston Basin, providing considerable waterflood and development
drilling potential. The major fields acquired are Flat Lake, Dwyer and Goose Lake
in Montana; Rival, Grenora, Alexander, Wiley, Glenburn and Sherwood in North Dakota;
and Rocky Point in Wyoming.
On August 25, 2006, PrimeWest acquired natural gas assets in the Caroline area for
$31.9 million. The acquisition of these assets, which were already operated by PrimeWest,
represented the conclusion of a farm in arrangement between PrimeWest and the vendor.
The total 2006 acquisition capital of $369.6 million added 20.3 mmBOE of Company
Interest Proved reserves and 29.0 mmBOE of Company Interest Proved plus Probable
reserves.
PrimeWest's 2006 capital development program totalled $261.0 million (2005 - $185.6
million). PrimeWest drilled 168 gross (107.2 net) wells with a success rate of 96%.
The capital program focused on the core areas of Caroline, Columbia, Wilson Creek,
Valhalla, Laprise and Crossfield/Lone Pine Creek.
Investment in drilling, completions and tie-ins in 2006 represented 83% of development
capital expenditures, contributing to new reserve additions. The development program
added 15.8 mmBOE of Company Interest Proved reserves and 23.2 mmBOE of Company Interest
Proved plus Probable reserves, including technical revisions. Investment in facilities
totalled $25.8 million, representing 10% of development capital, on projects related
to debottlenecking, increasing capacity and other activities that contribute to
future production volumes.
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.
In 2007 PrimeWest plans to invest approximately $230 - $255 million in its capital
development programs.
Capital is allocated on the basis of anticipated rate of return on projects undertaken.
At PrimeWest, every capital project is measured against economic evaluation criteria
prior to approval. These criteria include expected return, risks and further development
opportunities.
Finding, Development and Acquisition Costs
Under National Instrument 51-101 ("NI 51-101") finding, development and acquisition
costs incorporate changes in future development capital (FDC) required to bring
the Proved undeveloped and Probable reserves to production. Changes in forecast
FDC occur annually as a result of development activities, acquisition and disposition
activities and capital cost estimates. The FDC is determined independently by the
reserves evaluator GLJ Petroleum Consultants Ltd (GLJ). The current high level of
activity has resulted in increased capital costs throughout the industry and this
is reflected in the estimated future development costs related to reserve additions
for that year.
The aggregate of the exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future development costs
generally will not reflect total finding and development costs related to reserve
additions for that year.
---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
FD&A Costs Excluding Future Proved plus Proved plus
Development Costs Proved Probable Proved Probable
---------------------------------------------------------------------------
Development capital expenditures
($ millions) 261.0 261.0 185.6 185.6
Development reserve additions
including revisions (mmBOE) 15.8 23.2 10.7 14.7
Finding and development costs
($/BOE) 16.56 11.22 17.35 12.63
Net acquisition capital
($ millions) 366.1 366.1 (17.9) (17.9)
Net acquisition reserve additions
(mmBOE) 20.3 29.0 (0.5) (0.6)
Net acquisition costs ($/BOE) 18.08 12.63 (35.80) (29.83)
Total capital expenditures including
net acquisitions ($ millions) 627.1 627.1 167.7 167.7
Reserves additions including net
acquisitions (mmBOE) 36.0 52.2 10.2 14.1
Finding development and acquisition
cost ($/BOE) 17.42 12.00 16.44 11.89
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
FD&A Costs Including Future Proved plus Proved plus
Development Costs Proved Probable Proved Probable
---------------------------------------------------------------------------
Development capital expenditures 261.0 261.0 185.6 185.6
Development change in FDC 72.0 121.7 52.5 62.1
Development capital including
change in FDC 333.0 382.7 238.1 247.7
Development reserve addition
including revisions (mmBOE) 15.8 23.2 10.7 14.7
Finding and development costs
($/BOE) 21.13 16.46 22.25 16.85
Net acquisition capital (after
disposals) 366.1 366.1 (17.9) (17.9)
Net acquisition FDC (after
disposals) 85.0 111.7 - -
Acquisition capital including
change in FDC 451.1 477.8 (17.9) (17.9)
Net acquisition reserves additions
(mmBOE) 20.3 29.0 (0.5) (0.6)
Net acquisition cost ($/BOE) 22.28 16.48 (35.8) (29.83)
Total capital including net
acquisitions ($ millions) 627.1 627.1 167.7 167.7
Development and net acquisition
change in FDC 157.0 233.4 52.5 62.1
Development net acquisition capital
including change in FDC 784.1 860.5 220.2 229.8
Reserves additions including net
acquisitions (mmBOE) 36.0 52.2 10.2 14.1
Finding, development and net
acquisition cost ($/BOE) 21.78 16.47 21.59 16.30
---------------------------------------------------------------------------
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, 2006. The table is derived from the
January 24, 2007 report (the GLJ Report) of the independent reserve evaluators,
GLJ Petroleum Consultants Ltd. (GLJ), using forecast price and cost estimates, reconciled
to December 31, 2005. PrimeWest's Company Interest reserves include working interest
and royalty reserves receivable. The reserve information includes the Consolidated
Canadian and U.S. assets. This definition is consistent with the basis on which
reserves were reported in prior years. See further discussion of reserves definitions
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,
Sproule Associates Limited and McDaniel & Associates Consultants Ltd., all of which
are effective January 1, 2007.
Light, Medium and Heavy Crude Oil (mbbls)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 18,073 18,864 4,783 23,646
Capital Additions (1) 1,041 1,609 581 2,190
Improved Recovery (2) 29 207 106 313
Technical Revisions 311 100 224 324
Acquisitions 9,253 18,140 7,458 25,598
Dispositions 0 0 0 0
Economic Factors 0 0 0 0
Production (2,853) (2,853) 0 (2,853)
---------------------------------------------------------------------------
Dec. 31, 2006 25,852 36,068 13,150 49,218
---------------------------------------------------------------------------
Columns may not add due to rounding.
Natural Gas (bcf)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 421.4 510.7 166.6 677.3
Capital Additions (1) 27.9 39.8 28.5 68.3
Improved Recovery (2) 15.9 29.8 13.6 43.4
Technical Revisions 25.2 8.4 (3.5) 4.9
Acquisitions 7.9 12.2 7.2 19.4
Dispositions (0.2) (0.2) (0.1) (0.3)
Economic Factors 0 0 0 0
Production (60.6) (60.6) 0 (60.6)
---------------------------------------------------------------------------
Dec. 31, 2006 437.5 540.1 212.4 752.5
---------------------------------------------------------------------------
Columns may not add due to rounding.
Natural Gas Liquids (mbbls)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 10,864 13,434 4,634 18,068
Capital Additions (1) 755 1,039 454 1,493
Improved Recovery (2) 425 812 331 1,143
Technical Revisions (144) (1,011) (643) (1,654)
Acquisitions 91 108 103 211
Dispositions (4) (4) (1) (5)
Economic Factors 0 0 0 0
Production (1,399) (1,399) 0 (1,399)
---------------------------------------------------------------------------
Dec. 31, 2006 10,589 12,980 4,877 17,857
---------------------------------------------------------------------------
Columns may not add due to rounding.
Total (mmBOE)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 99.2 117.4 37.2 154.6
Capital Additions (1) 6.4 9.3 5.8 15.1
Improved Recovery (2) 3.1 6.0 2.7 8.7
Technical Revisions 4.4 0.5 (1.0) (0.5)
Acquisitions 10.7 20.3 8.7 29.0
Dispositions (0.0) (0.0) (0.0) (0.0)
Economic Factors 0 0 0 0
Production (14.4) (14.4) 0 (14.4)
---------------------------------------------------------------------------
Dec. 31, 2006 109.4 139.1 53.4 192.5
---------------------------------------------------------------------------
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, 2006, derived from the GLJ Report using
forecast price and cost estimates. These year-end reserves are reconciled
to December 31, 2005 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, 2005 14,098 14,709 3,544 18,253
Capital Additions (1) 892 1,450 531 1,980
Improved Recovery (2) 26 195 99 294
Technical Revisions (1,074) (1,252) (11) (1,262)
Acquisitions 7,975 15,743 6,439 22,183
Dispositions 0 0 0 0
Economic Factors 0 35 6 40
Production (1,905) (1,905) 0 (1,905)
---------------------------------------------------------------------------
Dec. 31, 2006 20,011 28,975 10,608 39,583
---------------------------------------------------------------------------
Columns may not add due to rounding.
Heavy Oil (mbbls)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 2,355 2,436 630 3,066
Capital Additions (1) 25 2 0 2
Improved Recovery (2) 0 0 0 0
Technical Revisions 696 646 163 809
Acquisitions 0 0 0 0
Dispositions 0 0 0 0
Economic Factors 0 22 1 23
Production (530) (530) 0 (530)
---------------------------------------------------------------------------
Dec. 31, 2006 2,546 2,576 794 3,370
---------------------------------------------------------------------------
Columns may not add due to rounding.
Associated and Non-Associated Gas (bcf)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 336.4 407.2 131.7 539.0
Capital Additions (1) 22.1 27.4 15.0 42.3
Improved Recovery (2) 12.2 23.5 10.8 34.3
Technical Revisions 18.8 5.2 (2.5) 2.7
Acquisitions 6.1 9.8 6.0 15.8
Dispositions (0.1) (0.1) (0.1) (0.2)
Economic Factors - 0.3 0.0 0.3
Production (46.2) (46.2) 0 (46.2)
---------------------------------------------------------------------------
Dec. 31, 2006 349.3 427.1 160.9 588.0
---------------------------------------------------------------------------
Columns may not add due to rounding.
Natural Gas Liquids (mbbls)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 7,668 9,495 3,234 12,729
Capital Additions (1) 520 712 320 1,032
Improved Recovery (2) 303 582 226 809
Technical Revisions (6) (659) (445) (1,104)
Acquisitions 61 72 66 138
Dispositions (2) (2) (1) (3)
Economic Factors 0 2 (2) 0
Production (1,049) (1,049) 0 (1,049)
---------------------------------------------------------------------------
Dec. 31, 2006 7,494 9,152 3,399 12,551
---------------------------------------------------------------------------
Columns may not add due to rounding.
Natural Gas from Coal (mmcf)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 171 606 518 1,124
Capital Additions (1) 80 4,262 8,600 12,862
Improved Recovery (2) 132 201 36 237
Technical Revisions 52 (158) (220) (378)
Acquisitions 0 0 0 0
Dispositions 0 0 0 0
Economic Factors 0 0 0 0
Production (21) (21) 0 (21)
---------------------------------------------------------------------------
Dec. 31, 2006 414 4,890 8,935 13,824
---------------------------------------------------------------------------
Total (mmBOE)
---------------------------------------------------------------------------
Proved Total Proved plus
Producing Proved Probable Probable
---------------------------------------------------------------------------
Dec. 31, 2005 80.2 94.6 29.5 124.1
Capital Additions (1) 5.1 7.4 4.8 12.2
Improved Recovery (2) 2.3 4.7 2.1 6.9
Technical Revisions 2.8 (0.4) (0.8) (1.2)
Acquisitions 9.1 17.5 7.5 25.0
Dispositions 0 0 0 0
Economic Factors 0 0.1 0 0.1
Production (11.2) (11.2) 0 (11.2)
---------------------------------------------------------------------------
Dec. 31, 2006 88.3 112.7 43.1 155.8
---------------------------------------------------------------------------
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.
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 (mbbls) Heavy Oil (mbbls)
---------------------------------------------------------------------------
Reserves Company Company
Category Interest Gross Net Interest Gross Net
---------------------------------------------------------------------------
Proved
Developed
Producing 23,074 21,761 20,011 2,779 2,772 2,546
Developed
Non-Producing 2,012 2,008 1,806 33 32 30
Undeveloped 8,170 8,169 7,158 0 0 0
Total Proved 33,256 31,939 28,975 2,811 2,804 2,576
Probable 12,246 11,968 10,608 904 902 793
---------------------------------------------------------------------------
Total Proved
plus Probable 45,502 43,907 39,583 3,715 3,706 3,370
---------------------------------------------------------------------------
Columns may not add due to rounding.
---------------------------------------------------------------------------
Reserves
---------------------------------------------------------------------------
Natural Gas (bcf) Natural Gas Liquids (mbbls)
---------------------------------------------------------------------------
Reserves Company Company
Category Interest Gross Net Interest Gross Net
---------------------------------------------------------------------------
Proved
Developed
Producing 437.5 426.2 349.7 10,589 10,351 7,494
Developed
Non-Producing 29.6 29.5 23.6 650 649 443
Undeveloped 73.0 73.0 58.7 1,742 1,742 1,215
Total Proved 540.1 528.7 432.0 12,980 12,742 9,152
Probable 212.4 209.9 169.8 4,877 4,826 3,398
---------------------------------------------------------------------------
Total Proved
plus Probable 752.5 738.6 601.8 17,857 17,568 12,551
---------------------------------------------------------------------------
Columns may not add due to rounding.
---------------------------------------------------------------------------
TOTAL (mmBOE)
---------------------------------------------------------------------------
Reserves Category Company Interest Gross Net
---------------------------------------------------------------------------
Proved
Developed Producing 109.4 105.9 88.3
Developed Non-Producing 7.6 7.6 6.2
Undeveloped 22.1 22.1 18.2
Total Proved 139.1 135.6 112.7
Probable 53.4 52.7 43.1
---------------------------------------------------------------------------
Total Proved plus Probable 192.5 188.3 155.8
---------------------------------------------------------------------------
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 3,112.4 2,280.5 1,824.7 1,538.0 1,340.3
Developed Non-Producing 228.6 160.5 124.0 101.4 86.1
Undeveloped 566.1 336.8 218.1 147.8 102.4
---------------------------------------------------------------------------
Total Proved 3,907.2 2,777.7 2,166.8 1,787.2 1,528.8
Total Probable 1,768.3 951.7 612.8 437.6 333.1
---------------------------------------------------------------------------
Total Proved plus Probable 5,675.5 3,729.4 2,779.6 2,224.8 1,861.9
---------------------------------------------------------------------------
---------------------------------------------------------------------------
After Future Income Tax Expenses
Discounted at (%) (1)
---------------------------------------------------------------------------
0% 5% 10% 15% 20%
---------------------------------------------------------------------------
Proved Developed Producing 3,112.3 2,280.3 1,824.7 1,537.0 1,340.3
Developed Non-Producing 216.9 152.0 117.4 96.0 81.2
Undeveloped 509.6 294.1 183.9 120.3 78.3
---------------------------------------------------------------------------
Total Proved 3,838.8 2,726.5 2,126.0 1,753.3 1,499.8
Total Probable 1,673.5 892.8 571.8 406.7 308.6
---------------------------------------------------------------------------
Total Proved plus Probable 5,512.3 3,619.3 2,697.8 2,160.1 1,808.4
---------------------------------------------------------------------------
Columns may not add due to rounding.
(1) Taxes have been calculated on cash flows associated with the U.S.
operations only. Future revenues after tax expense do not reflect the
October 31 Proposals (see "Taxation of the Trust").
Daily Production Volumes
---------------------------------------------------------------------------
2006 2005 Change (%)
---------------------------------------------------------------------------
Natural gas (mmcf/day) 166.0 178.2 (7)
Crude oil (bbls/day) 7,816 6,861 14
Natural gas liquids (bbls/day) 3,835 3,797 1
---------------------------------------------------------------------------
Total BOE/day 39,321 40,351 (3)
---------------------------------------------------------------------------
Gross overriding royalty volumes included
above (BOE/day) 1,173 1,338 (12)
---------------------------------------------------------------------------
All production information is reported before the deduction of Crown and
freehold royalties.
The 3% decrease in daily average production year-over-year was due to
regulatory change impacting the Nisku waterflood project at Crossfield,
the major turndown at the Crossfield plant in the third quarter and
natural decline. Volumes from the third quarter U.S. asset acquisition and
incremental volumes from capital expenditures partially offset the
decrease.
PrimeWest expects production for 2007 to be 39,000 - 40,000 BOE/day.
Commodity Prices
---------------------------------------------------------------------------
Average Benchmark Prices 2006 2005 Change (%)
---------------------------------------------------------------------------
Natural Gas
NYMEX (US$/mcf) $ 7.26 $ 8.55 (15)
AECO (C$/mcf) $ 6.99 $ 8.48 (18)
Crude Oil - West Texas Intermediate (US$/bbl) $ 66.22 $ 56.56 17
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Average Realized Sales Prices (1) (C$) 2006 2005 Change (%)
---------------------------------------------------------------------------
Natural gas ($/mcf) (1) (2) $ 7.09 $ 8.75 (19)
Crude oil ($/bbl) (1) $ 62.42 $ 58.48 7
Natural gas liquids ($/bbl) $ 59.09 $ 55.92 6
---------------------------------------------------------------------------
Total ($/BOE) $ 48.09 $ 53.82 (11)
---------------------------------------------------------------------------
(1) Excludes realized derivative gains/(losses)
(2) Excludes sulphur.
During 2006 PrimeWest realized an average sales price of $48.09 per BOE, for its
oil and gas production. The average sales price in 2006 was 11% lower than 2005
due to lower natural gas prices that were partially offset by higher crude oil and
natural gas liquids prices.
The prices realized by PrimeWest at the wellhead or plant gate are affected by benchmark
oil and gas prices traded in the New York Mercantile Exchange (NYMEX) and by the
Canadian and U.S. currency exchange rates. A stronger Canadian dollar negatively
impacts the actual price realized by producers in Canada because the benchmark prices
are denominated in U.S. dollars. During 2006 the NYMEX natural gas prices were 15%
lower than the 2005 price level, while West Texas Intermediate (WTI) crude oil prices
were 17% higher than 2005. The currency exchange rate had a negative impact on the
year-over-year price comparison, as the Canadian dollar averaged U.S. $0.88 for
2006 as compared to U.S. $0.83 in 2005.
Crude Oil Prices
Geopolitical instability was a key factor in moving crude oil prices to record highs
in 2006. With continued strong worldwide demand, the oil market reacted to many
of the world events that unfolded by pushing oil prices higher: the continued violence
in Iraq; the fighting between Israel and the Hezbolah in Lebanon; the concerns about
the development of nuclear weapons capability in Iran; the North Korean nuclear
weapon test; the temporary close down of a Prudhoe Bay pipeline for corrosion repair;
the record heat in North America that drove natural gas and distillate consumptions,
etc. During the summer, crude oil traded to a record high level of approximately
US $77.00/bbl.
In early 2007 prices fell to the U.S. level of $50/bbl as the market became less
concerned that the world supply of crude oil would continue to be tight. During
the early part of the year, crude oil inventories in North America were higher than
historical levels, and the expectation grew stronger for a warmer than normal winter
and thus a weaker energy demand. Rumours of hedge funds exiting the energy market
added volatility to the price movement. OPEC responded to the price decline by proposing
cuts in the production quotas in order to boost prices. OPEC's adherence to the
proposed cuts will be an important determining factor for crude oil price movement
in 2007. Possible environmental regulations to reduce fossil fuel consumption could
have a downward impact on prices.
While light sweet crude oil prices in the U.S. saw significant increases in 2006,
the benefits did not flow through entirely to Canadian producers as a result of
a stronger Canadian dollar relative to the U.S. currency and a widening of the differentials
between the price of light sweet crude oil and those of a heavier grade. As the
majority of the new production coming into the markets worldwide is of the heavier
quality, the realized price for heavy oil producers will continue to be negatively
affected by a wide price differential.
Approximately 32% of PrimeWest's crude oil production is of the medium to slightly
heavy grade. These products do not require any diluents blending and attract a better
pricing differential than the average heavy crude oil.
Natural Gas Prices
PrimeWest's average realized natural gas price was 19% lower in 2006 than 2005.
In 2006 natural gas prices were strongly influenced by a storage overhang that resulted
from weak consumptions, reflective of the warmest winter in North America on record.
Gas prices started to decline early in 2006 from record high levels at 2005 year-end
and reached a low of $4.23/GJ in October. Thereafter, prices recovered some of the
early losses due to support from continued high oil prices as well as the arrival
of the winter heating season. However, gas prices could continue to be burdened
by the high level of inventory balance until colder weather and the resultant increase
in gas consumption restores a tighter balance between supply and demand.
Key factors that will influence prices in 2007 include: the impact that colder temperatures
during the early part of 2007 will have on gas storage levels; the degree of slowdown
in gas drilling activities that will happen in North America in response to softer
gas prices and the impact on gas deliverability; the continued growth of natural
gas consumption in the electricity sector; and the impact of government regulations
and conservation efforts on the supply and demand of gas.
Sales Revenue
---------------------------------------------------------------------------
Percent of Percent of
Revenue ($ Millions) (1) 2006 Total 2005 Total Change (%)
---------------------------------------------------------------------------
Natural gas (2) $ 429.4 62 $ 568.7 72 (24)
Crude oil 178.1 26 146.4 18 22
Natural gas liquids 82.7 12 77.5 10 7
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total $ 690.2 $ 792.6
---------------------------------------------------------------------------
(1) Net of transportation expense.
(2) Excludes sulphur.
PrimeWest's revenues from the sale of commodities for 2006 were $690.2 million compared
to $792.6 million in the previous year. Lower realized natural gas prices along
with decreases in natural gas sales volumes were the major contributors to the decreased
revenue in 2006 partially offset by increases to crude oil prices and production
volumes.
If the pricing environment continues to soften in 2007, and the Canadian dollar
remains strong, oil and natural gas revenues will be negatively impacted. Since
approximately 68% of PrimeWest's production, on an energy equivalent basis, is natural
gas, the Trust has greater sensitivity to changes in natural gas prices than crude
oil prices.
Financial Derivatives
As part of our risk management strategy PrimeWest uses financial instruments to
manage commodity prices. These instruments are commonly referred to as "hedges"
PrimeWest did not elect to adopt hedge treatment for accounting purposes. The purpose
of the hedging program is to reduce volatility in cash flows and to protect acquisition
economics against the unpredictable commodity price environment.
Management entered into fixed price electricity purchase contracts during 2006 to
assist in maintaining stable power costs during the year. PrimeWest also entered
into a financial swap which converted the interest and principal payments associated
with the U.K. Senior Notes into Canadian dollars from pounds sterling. The pounds
sterling debt and interest payable are converted to Canadian dollars at the foreign
currency exchange rate in effect at the period end date.
The following table provides a breakdown of average commodity prices before and
after realized gains or losses on commodity derivatives.
---------------------------------------------------------------------------
2006 2005 Change (%)
---------------------------------------------------------------------------
Natural gas ($/mcf) (1) (2) 7.46 8.43 (12)
Without derivatives 7.09 8.75 (19)
Crude oil ($/bbl) (1) 62.74 49.05 28
Without derivatives 62.42 58.48 7
Natural gas liquids ($bbl) 59.09 55.92 6
---------------------------------------------------------------------------
Total ($/BOE) (1) 49.73 50.81 (2)
---------------------------------------------------------------------------
Without derivatives 48.09 53.82 (11)
---------------------------------------------------------------------------
(1) Includes realized derivatives gains/losses.
(2) Excludes sulphur.
The table below shows the production volumes hedged at December 31, 2006.
---------------------------------------------------------------------------
2007 Q1 Q2 Q3 Q4 Full Year
---------------------------------------------------------------------------
Crude oil (bbls/day) 5,900 5,300 4,400 4,300 4,975
Natural gas (mmcf/day) 70 56 51 37 54
---------------------------------------------------------------------------
2008 Q1 Q2 Q3 Q4 Full Year
---------------------------------------------------------------------------
Crude oil (bbls/day) 1,500 500 0 0 500
Natural gas (mmcf/day) 33 14 0 0 12
---------------------------------------------------------------------------
A summary of derivative contracts in place as at December 31, 2006, is
available under note 16 to the Consolidated Financial Statements.
The table below provides a summary of net gains and losses on financial
derivatives during 2006 and 2005.
Year Ended December 31, 2006
---------------------------------------------------------------------------
Foreign
($ Millions) Oil Gas Electricity Exchange Total
---------------------------------------------------------------------------
Realized gains on
derivatives $ 0.9 $ 22.7 $ 1.7 $ 0.2 $ 25.5
Unrealized gains on
derivatives 8.3 27.3 - 4.7 40.3
---------------------------------------------------------------------------
Total gains on derivatives $ 9.2 $ 50.0 $ 1.7 $ 4.9 $ 65.8
---------------------------------------------------------------------------
Realized gain on
derivatives per BOE $ 0.06 $ 1.58 $ 0.12 $ 0.02 $ 1.78
Unrealized gain in
derivatives per BOE $ 0.57 $ 1.90 $ - $ 0.33 $ 2.80
---------------------------------------------------------------------------
Year Ended December 31, 2005
---------------------------------------------------------------------------
Foreign
($ Millions) Oil Gas Electricity Exchange Total
---------------------------------------------------------------------------
Realized gains/(losses)
on derivatives $ (23.6) $ (20.7) $ 0.8 $ - $ (43.5)
Unrealized gains/(losses)
on derivatives 6.6 (18.3) 0.1 - (11.6)
---------------------------------------------------------------------------
Total gains/(losses) on
derivatives $ (17.0) $ (39.0) $ 0.9 $ - $ (55.1)
---------------------------------------------------------------------------
Realized gain/(loss) on
derivatives per BOE $ (1.60) $ (1.41) $ 0.06 $ - $ (2.95)
---------------------------------------------------------------------------
Unrealized gain/(loss)
on derivatives per BOE $ 0.45 $ (1.24) $ 0.01 $ - $ (0.78)
---------------------------------------------------------------------------
Royalties
PrimeWest pays Crown, freehold and overriding royalties to the owners of mineral
rights with whom PrimeWest holds leases. These royalties vary for each property
and product. The Crown royalty system is based on a sliding scale structure that
increases the royalty rates as commodity prices rise. Because of the sliding scale
Crown royalty system, future changes to commodity prices will result in changes
to royalty rates and expenses. In certain situations, the Crown grants royalty "holidays"
which eliminate royalties on specific wells.
---------------------------------------------------------------------------
($ Millions, except per BOE) 2006 2005 Change (%)
---------------------------------------------------------------------------
Royalty expense $ 144.8 $ 172.8 (16)
Per BOE $ 10.09 $ 11.73 (14)
Royalties as a percentage of sales
revenue 21% 22%
---------------------------------------------------------------------------
Royalty expenses as a percentage of sales have decreased when compared to the previous
year due to the decline in natural gas prices.
Operating Expense
---------------------------------------------------------------------------
($ Millions, except per BOE) 2006 2005 Change (%)
---------------------------------------------------------------------------
Operating expense $ 138.9 $ 117.8 18
Realized gains on electricity
derivative contracts $ (1.7) $ (0.8) 112
$ 137.2 $ 117.0 17
---------------------------------------------------------------------------
Per BOE without electricity
derivative $ 9.68 $ 8.00 21
Per BOE with electricity derivative $ 9.56 $ 7.94 20
---------------------------------------------------------------------------
2006 operating expense totalled $138.9 million, an increase of 18% from 2005. On
a per BOE basis, 2006 operating expense increased by 21% compared to 2005. The increase
in operating expense and operating expense per BOE is partially due to the acquisition
of the U.S. assets in July 2006. Operating expense for the U.S. assets was $7.3
million for the year. The effects of inflationary pressure on the price of industry
related goods and services also contributed to the increase in operating expense
and operating expense per BOE.
Operating Margin
---------------------------------------------------------------------------
($ per BOE) 2006 2005 Change (%)
---------------------------------------------------------------------------
Revenues $ 48.99 $ 54.71 (10)
Transportation expense (0.52) (0.49) 6
Royalties (10.09) (11.73) (14)
Operating expense (9.68) (8.00) 21
---------------------------------------------------------------------------
Operating margin before realized
derivative gains/(losses) $ 28.70 $ 34.49 (17)
---------------------------------------------------------------------------
Realized derivative gain/loss $ 1.78 $ (2.95)
---------------------------------------------------------------------------
Operating margin after realized
derivative gain/(losses) $ 30.48 $ 31.54 (3)
---------------------------------------------------------------------------
Operating margin per BOE decreased by 3% from 2005 primarily due to lower realized
natural gas prices and higher operating expenses, partially offset by higher realized
oil and natural gas liquids prices, increases to realized derivative gains and lower
royalties. Operating margin measures the level of cash flow per BOE at the field
level and before head office expenses and financing charges.
G&A Expense
---------------------------------------------------------------------------
($ Millions, except per BOE amounts) 2006 2005 Change (%)
---------------------------------------------------------------------------
G&A expense $ 30.4 $ 28.3 7
per BOE $ 2.12 $ 1.93 10
---------------------------------------------------------------------------
G&A expense increased by 7% in 2006 from 2005 primarily due to increased employee
costs and costs related to the U.S. operations. The increases were partially offset
by overhead recoveries resulting from increases to capital expenditures and operating
expense.
Included in G&A expense is $4.4 million relating to the Unit Appreciation Rights
(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 G&A expense is $1.4 million
related to the Special Employee Retention Plan (SERP). See note 17 to the Consolidated
Financial Statements.
Interest Expense
---------------------------------------------------------------------------
($ Millions, except per BOE amounts) 2006 2005 Change (%)
---------------------------------------------------------------------------
Interest expense $ 34.7 $ 28.3 23
Period end net debt level $ 820.8 $ 323.7 154
Debt per Trust Unit $ 9.74 $ 3.97 145
---------------------------------------------------------------------------
Average cost of debt 5.7% 5.2% 10%
---------------------------------------------------------------------------
Interest expense, representing interest on the bank Credit Facility, the U.S. Secured
Notes, the U.K. Secured Notes and the Debentures, increased to $34.7 million in
2006 from $28.3 million in 2005 due to a higher average cost of debt and higher
average debt balances in 2006 compared to 2005.
The increase in the average debt balance resulted mainly from additional borrowing
against the Credit Facility to finance the U.S. asset acquisition which occurred
in the third quarter of 2006.
The average cost of debt increased in 2006 compared to 2005 due to an increase in
banker's acceptance rates which are the basis for calculating interest on the Canadian
portion of the Credit Facility. The draw down under the U.S. portion of the Credit
Facility that bears interest at the London Inter Bank Offer Rate (LIBOR), which
is higher than the Canadian rate, also increased the average cost of debt in 2006.
Foreign Exchange
The foreign exchange gain of $13.5 million resulted mainly from the translation
of the U.S. dollar-denominated Secured Notes and U.K. pound-denominated Secured
Notes and related interest payable into Canadian dollars.
Depletion, Depreciation and Amortization (DD&A)
---------------------------------------------------------------------------
($ Millions, except per BOE amounts) 2006 2005 Change (%)
---------------------------------------------------------------------------
Depletion, depreciation and amortization $ 235.0 $ 230.2 2
Per BOE $ 16.37 $ 15.63 5
---------------------------------------------------------------------------
The 2006 DD&A rate of $16.37/BOE is 5% higher than the 2005 rate of $15.63/BOE.
The DD&A rate will fluctuate from one year to the next depending on the amount and
type of capital spending and the amount of reserves added. Expenditures on maintenance
capital, land and seismic do not contribute to reserve additions and may cause the
DD&A rate to increase.
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
Commencing in 1998, funding for the reserve was provided for by reducing distributions
otherwise payable based on an amount per BOE produced ($0.50/BOE produced for 2006
and 2005). The cash amount contributed, including interest earned, was $7.3 million
in 2006 (2005 - $7.6 million). Actual costs of site restoration and reclamation
totaling $14.3 million were paid out of this cash reserve for the year ended December
31, 2006, (2005 - $8.7 million). As at December 31, 2006, the site reclamation fund
had a balance of $2.2 million (2005 - $9.2 million). Future site restoration and
reclamation expenditures will be funded from the cash reserve and if required out
of cash flow from operating activities.
Asset Retirement Obligation
PrimeWest recognizes the fair value of asset retirement costs relating to its petroleum
and natural gas properties when a reasonable estimate of the fair value can be made
(See note 9 to the consolidated financial statements). These liabilities will be
settled based on the expected life of the underlying assets. These liabilities are
subsequently adjusted for the passage of time (accretion) and revisions in either
timing or changes to the underlying liability. PrimeWest had a significant increase
in the asset retirement obligation in 2006 which is mainly the result of a review
of actual costs incurred to reclaim wells and to a new directive by the Alberta
Energy and Utilities Board relating to the remediation of facilities. An additional
liability of approximately $38 million was capitalized to the related asset and
will be amortized to earnings over time.
Net Asset Value
Net asset value (NAV) measures the net worth of PrimeWest by subtracting the value
of debt from the estimated economic value of its underlying assets - primarily crude
oil, natural gas and natural gas liquids reserves. The value placed on these reserves
is the pre-tax present value of future net cash flows, discounted at 10%, as independently
assessed by GLJ as at January 1, 2007. The present value of reserves reflects provisions
for royalties, operating costs, future capital costs and site reclamation and restoration
costs, but is prior to deductions for Canadian income taxes, interest expense and
G&A expense.
This calculation is a "snapshot" in time and is heavily dependent upon future commodity
price expectations when the "snapshot" is taken. Accordingly, the NAV as at January
1, 2007, may not reflect fairly the equity market trading value of PrimeWest. It
is also significant to note that NAV declines as reserves are produced and net operating
cash flow is distributed to Unitholders. Value is delivered to Unitholders through
such monthly distributions.
---------------------------------------------------------------------------
As at December 31 ($ Millions, 2006 Consultants' 2005 Consultants'
except per Trust Unit amounts) Average Average
---------------------------------------------------------------------------
Assets
Canada
Present value of future net cash
flow discounted at 10% (1) (2) (4) $ 2,448.0 $ 2,684.0
U.S.
Present value of future net cash
flow discounted at 10% (1) (4) 331.6 -
Present value of future income
taxes discounted at 10% (84.2) -
Mark-to-market value of hedging contracts 28.8 (11.5)
Fair value of unproved lands 130.3 151.3
Reclamation fund 2.2 9.2
---------------------------------------------------------------------------
$ 2,856.7 $ 2,833.0
Liabilities
Debt and working capital (3) $ (781.9) $ (267.9)
---------------------------------------------------------------------------
Net asset value $ 2,074.8 $ 2,565.1
---------------------------------------------------------------------------
Outstanding Trust Units - millions, diluted 85.8 83.7
Net asset value per Trust Unit $ 24.18 $ 30.64
---------------------------------------------------------------------------
(1) Company Interest Proved plus Probable reserves.
(2) Estimated future cash flow does not include the proposed federal tax on
Canadian trust income, which if implemented, becomes effective in 2011
and is estimated to have a negative impact of approximately $1.50 /unit
on the present value of PrimeWest's cash flow discounted at 10%
per annum.
(3) Debt excludes Debentures.
(4) Refer to Summary of Oil and Natural Gas Reserves and Net Present Values
of Future Net Revenues table under the section Disclosure of Oil and
Natural Gas Reserves.
---------------------------------------------------------------------------
2006 Consultants' 2005 Consultants'
Price Assumptions Average Average
---------------------------------------------------------------------------
Edmonton Par Oil - C$/bbl
2006 $ - $ 67.64
2007 71.72 66.40
2008 71.64 60.89
2009 67.90 56.83
2010 65.39 54.25
2011 63.53 -
Spot Gas at AECO-C - C$/mcf
2006 $ - $ 10.93
2007 7.38 9.88
2008 7.83 8.48
2009 7.77 7.59
2010 7.75 7.23
2011 7.90 -
---------------------------------------------------------------------------
The NAV calculation is based on the above reference prices as of December 31, 2006
and 2005 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 totalled $305.8 million or $3.75
per Trust Unit in 2006. Also, the NAV calculation assumes a "blow down" scenario
whereby existing reserves are produced without being replaced by acquisitions and
development. A major cornerstone of PrimeWest's strategy is to replace reserves
through accretive acquisitions and capital development.
Income and Capital Taxes
---------------------------------------------------------------------------
($ Millions) 2006 2005 Change (%)
---------------------------------------------------------------------------
Income and capital taxes $ 1.5 $ 2.8 (46)
Future income tax recovery (49.4) (14.8) 233
---------------------------------------------------------------------------
Total $ (47.9) $ (12.0) 299
---------------------------------------------------------------------------
The increase in the future income tax recovery is mainly due to the
reduction in federal statutory tax rates that were substantially enacted
in the second quarter of 2006.
Net Income
---------------------------------------------------------------------------
($ Millions) 2006 2005 Change (%)
---------------------------------------------------------------------------
Net income $ 208.3 $ 207.5 -
---------------------------------------------------------------------------
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 a 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 $208.3 million in 2006 was relatively flat compared to 2005 net income
of $207.5 million. Lower oil and gas revenues, primarily due to lower realized commodity
prices, higher operating expenses and foreign exchange losses had a negative impact
on net income. These were offset by lower royalties, increased realized and unrealized
gains on derivatives and increases to future income tax recoveries.
Liquidity and Capital Resources
---------------------------------------------------------------------------
($ Millions) 2006 2005 Change (%)
---------------------------------------------------------------------------
Long-term debt $ 619.4 $ 354.2 75
Working capital deficit(surplus) (1) 201.4 (30.5)
---------------------------------------------------------------------------
Net debt 820.8 323.7 154
Market value of Trust Units and Exchangeable
Shares outstanding (2) (3) 1,805.9 2,884.7 (37)
---------------------------------------------------------------------------
Total capitalization $ 2,626.7 $ 3,208.4 (18)
---------------------------------------------------------------------------
Net debt as a percentage of total
capitalization 31% 10%
---------------------------------------------------------------------------
(1) Working capital/surplus excludes financial derivative assets and
liabilities and current future income tax assets and liabilities.
(2) Based on December 31, 2006 Trust Unit closing price of $21.50 and
Exchangeable Share ratio of 0.63765:1.
(3) Excludes the Debentures.
Long-term debt is comprised of the Credit Facility, the U.S. Secured Notes, the
U.K. Secured Notes and the Debentures of $477.4 million, $145.7 million, $143.8
million and $38.9 million respectively. $36.4 million relating to the U.S. Secured
Notes and $150 million relating to a bridge facility that formed part of the Credit
Facility are included in working capital as a current portion of long-term debt.
In addition to amounts outstanding under the Credit Facility, PrimeWest has outstanding
letters of credit in the amount of $6.8 million (2005 - $6.6 million).
The indebtedness under the Credit Facility, the U.S. Secured Notes and the U.K.
Secured Notes is supported by a borrowing base of $750 million and is comprised
of revolving facilities under the Canadian portion of the Credit Facility having
a capacity of $220.5 million, the U.S. portion of the Credit Facility having a capacity
of Cdn $255.0 million, the U.S. Secured Notes valued at $143.8 million based on
a U.S. dollar exchange rate of U.S. $0.87 and the U.K. Secured Notes valued at Cdn
$130.7 million. PrimeWest also had a $150 million bridge facility under the Canadian
portion of the Credit Facility, which expired upon repayment in January 2007.
As a result of the U.S. asset acquisition during the third quarter of 2006, PrimeWest
drew advances under the U.S. portion of the Credit Facility in U.S. dollars in the
form of LIBOR loans that bear interest at LIBOR plus a margin based on PrimeWest's
debt to EBITDA ratio. PrimeWest will continue to fund its ongoing operations in
Canada with advances from the Canadian portion of the Credit Facility utilizing
Banker Acceptances (BA) that bear interest at the BA rate plus a stamping fee determined
in the same manner as the LIBOR margin.
On June 15, 2006, PrimeWest replaced a portion of the Credit Facility with U.K.
Secured Notes in the amount of Pounds Sterling 63 million, which bears interest
at 5.76% per annum. PrimeWest entered into a currency swap transaction to fix the
aggregate principal value and annual interest payments at $130.7 million and $3.9
million, respectively. As a result of the swap, the U.K. Secured Notes bear interest
at an effective rate of 5.93% per annum with interest payable semi-annually on June
14 and December 14 of each year. The U.K. Secured Notes have a final maturity of
June 14, 2016. PrimeWest has not used hedge accounting and therefore the U.K. Secured
Notes and related interest payable were translated into Canadian dollars at the
foreign currency exchange rate in effect at the period end date.
PrimeWest has $24.0 and $14.9 million outstanding related to the Series I and Series
II Debentures respectively. For additional disclosure on the Debentures see Note
8 to the Consolidated Financial Statements.
On January 11, 2007, PrimeWest issued $200 million of Series III five-year convertible
unsecured subordinated debentures. The Series III debentures bear interest at 6.5%
per annum, payable semi-annually and are convertible at $26.25 per Trust Unit.
Unitholders' Equity
The Trust had 83,256,610 Trust Units outstanding at December 31, 2006, compared
to 79,666,352 Trust Units at the end of 2005. In addition, there were 1,161,864
Exchangeable Shares (see below) outstanding at year-end, exchangeable into a total
of 740,863 Trust Units. The weighted average number of Trust Units, including those
issueable by the exchange of Exchangeable Shares, was 82,270,315 Trust Units for
the twelve month period ended December 31, 2006, compared to 75,808,919 in 2005.
During 2006 PrimeWest issued 599,950 Trust units for proceeds of $20.3 million pursuant
to an "at the market offering" through the facilities of the NYSE under a shelf
prospectus issued on May 12, 2006 with a prospectus supplement filed July 28, 2006.
During the year, 366,033 Trust Units were issued to employees pursuant to the LTIP
(2005 - 487,421).
During 2006 PrimeWest issued 476,523 Trust Units under the DRIP for $14.4 million
(2005 - 262,347 Trust Units, $7.9 million), 943,150 Trust Units for $28.3 million
pursuant to the PREP (2005 - 932,142 Trust Units, $27.4 million) and 440,457 Trust
Units for $13.4 million pursuant to the OTUPP (2005 -704,806 Trust Units, $20.4
million).
On January 11, 2007, PrimeWest issued 6,420,000 Trust Units at $23.35 per Trust
Unit for gross proceeds of $149.9 million.
The DRIP gives Canadian and U.S. 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 2007 to
be similar to 2006. Proceeds from these plans are used for the repayment of debt
under the 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 certain acquisitions and as part
of PrimeWest's management internalization transaction. Exchangeable Shares continue
to be issued to certain Executive Officers pursuant to the SERP instituted as part
of the management internalization transaction.
In 2006, 94,340 (2005 - 94,340) Exchangeable Shares were issued pursuant to the
SERP. See Note 17 to the 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 that month.
At December 31, 2006, there were 1,161,864 Exchangeable Shares outstanding. The
exchange ratio was 0.63765:1 Trust Units for each Exchangeable Share at year end.
For purposes of calculating basic per Trust Unit amounts, it is assumed that the
Exchangeable Shares have been exchanged into Trust Units at the current exchange
ratio.
Cash Distributions
Cash distributions to Unitholders are at the discretion of the Board of Directors
and can fluctuate depending on the funds flow generated from operations and other
factors. The cash 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.
The Board of Directors targets a long-term distribution payout ratio that is a percentage
of funds flow from operations. However, the actual distribution payout ratio may
vary from such targets due to fluctuations in commodity prices and their impact
on cash flow forecasts, as well as other factors. The current distribution payout
ratio is targeted to be approximately 70-90% of annual funds flow from operations.
In 2006 cash distributions totalled $305.8 million, or $3.75 per Trust Unit representing
a payout ratio of approximately 84% of funds flow from operations, compared to $276.6
million, or $3.66 per Trust Unit (68% payout ratio) in the previous year. Further,
the October 31 Proposals discussed under Taxation of the Trust, have created additional
uncertainty with respect to the payout ratio. At this time, PrimeWest is unable
to predict what payout ratio it will be able to maintain in the future.
Distribution payments to U.S. 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 increase) $ 0.05
Natural gas price ($0.10/mcf increase) 0.06
Exchange rate (US$0.01 decrease) 0.08
Short-term interest rate (1% decrease) 0.02
Production (1,000 BOE/day increase) 0.15
---------------------------------------------------------------------------
(1) Without the effect of hedging and assuming no change in operating
costs and royalty costs.
The figures in the above table are provided for directional information only. Should
changes to the commodity price, interest rate, exchange rate or production levels
noted above take place, it should not be assumed that a corresponding change would
be made to the distribution level.
Contractual Obligations
PrimeWest enters into many contractual obligations as part of conducting day-to-day
business. Material contractual obligations include debt obligations, interest payments
on long-term debt, office lease rental commitments that run from 2006 through 2024
and various pipeline transportation commitments that run through 2010. The details
of the timing of these contractual obligations are included in the following table.
---------------------------------------------------------------------------
As at December 31, 2006 Less than 1 1-3 4-5 More than 5
($ Millions) Total Year Years Years Years
---------------------------------------------------------------------------
Long-term debt
obligations 766.9 186.4 400.3 36.4 143.8
Debentures 38.4 - 23.7 - 14.7
Interest (1) 101.0 16.4 27.8 19.5 37.3
Office lease rental
obligations 84.5 3.9 4.9 9.6 66.1
Pipeline transportation
obligations 6.2 5.0 1.0 0.2 -
---------------------------------------------------------------------------
Total contractual
obligations 997.0 211.7 457.7 65.7 261.9
---------------------------------------------------------------------------
(1) Includes interest on the U.S. Secured Notes, U.K. Secured Notes and the
Debentures assuming foreign exchange rates in effect at December 31,
2006.
As part of PrimeWest's 2002 internalization transaction, which closed on November
6, 2002, PrimeWest agreed to issue 377,360 Exchangeable Shares to certain Executive
Officers pursuant to the SERP. On November 6, 2004, 2005, and 2006, 94,340 Exchangeable
Shares were issued to those officers. An additional 94,340 shares will be issued
on November 6, 2007. For the 12 months ended December 31, 2006, $1.4 million was
recorded in G&A expense related to the SERP.
Summary of Fourth Quarter Results
Three Months Ended
---------------------------------------------------------------------------
Financial ($ Millions, except
per BOE (1) and per Trust Unit
amounts) Dec 31, 2006 Sep 30, 2006 Dec 31, 2005
---------------------------------------------------------------------------
Gross revenue 173.6 176.0 256.4
per BOE 45.59 47.37 69.21
Realized derivative gains/losses 12.7 8.5 (20.5)
Per BOE 3.34 2.28 (5.53)
Funds flow from operations 84.6 91.4 128.6
per BOE 22.23 24.60 34.71
per Trust Unit - basic (2) 1.01 1.11 1.61
per Trust Unit - diluted (3) 1.00 1.09 1.56
Royalty expense 33.7 34.5 55.9
per BOE 8.86 9.29 15.08
Operating expense 39.6 35.4 33.6
per BOE 10.40 9.53 9.07
General and administrative
expense (G&A) 8.6 6.5 8.1
per BOE 2.27 1.76 2.21
Interest expense (4) 13.0 11.9 5.5
per BOE 3.42 3.20 1.48
Distributions to Unitholders 62.3 74.0 76.2
per Trust Unit (5) 0.75 0.90 0.96
Net debt (6) 820.8 772.4 323.7
per Trust Unit (7) 9.74 9.16 3.97
Payout Ratio 74% 81% 59%
Capital Expenditures
Development 57.2 76.3 41.2
Acquisition 0.4 368.8 0.5
Disposition (0.1) (0.2) (16.9)
Corporate 0.5 0.4 0.8
---------------------------------------------------------------------------
Total capital expenditures $ 58.1 $ 445.3 $ 25.6
---------------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------------
Daily Production Volumes Dec 31, 2006 Sep 30, 2006 Dec 31, 2005
---------------------------------------------------------------------------
Natural gas (mmcf/day) 169.9 164.1 176.8
Crude oil (bbls/day) 8,950 9,106 6,752
Natural gas liquids (bbls/day) 4,127 3,931 4,046
---------------------------------------------------------------------------
Total (BOE/day) 41,386 40,381 40,269
---------------------------------------------------------------------------
(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 issueable upon exchange of the
Exchangeable Shares.
(3) The diluted per Trust Unit calculation includes the weighted average
Trust Units outstanding, Trust Units issueable upon exchange of the
outstanding Exchangeable Shares, the deemed conversion of the
Debentures and Trust Units issueable pursuant to the 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) Interest expense includes the interest on the Debentures
(5) Based on Trust Units outstanding at the record dates for distributions
during the period.
(6) Net debt is long-term debt including Debentures adjusted for working
capital, excluding current financial derivatives and future income tax
assets and liabilities.
(7) The net debt per Trust Unit calculation includes outstanding Trust
Units issueable upon exchange of the outstanding Exchangeable Shares
and Trust Units issueable pursuant to the LTIP at the end of the
period.
Funds Flow Reconciliation
---------------------------------------------------------------------------
$ Millions
--------------------------- -----------------------------------------------
Third quarter 2006 funds flow from operations $ 91.4
Volumes 3.4
Commodity prices (6.0)
Change in realized derivative gain 4.2
Operating expenses (4.2)
Royalties 0.8
Site restoration and reclamation (0.1)
G&A (2.0)
Interest (1.1)
Other (1.8)
---------------------------------------------------------------------------
Fourth quarter 2006 funds flow from operations $ 84.6
---------------------------------------------------------------------------
Average Realized Sales Prices
Three Months Ended
---------------------------------------------------------------------------
Dec 31, 2006 Sep 30, 2006 Dec 31, 2005
---------------------------------------------------------------------------
Natural gas ($/Mcf) (1) 6.79 6.20 11.99
Crude oil ($/bbl)(1) 55.13 69.18 59.78
Natural gas liquids ($/bbl) 52.52 62.50 59.07
---------------------------------------------------------------------------
Total ($/BOE) (1) 45.03 46.86 68.59
---------------------------------------------------------------------------
Realized derivative
gains/(losses) ($/BOE) 2.99 2.10 (5.72)
---------------------------------------------------------------------------
Net realized price ($/BOE) 48.02 48.96 62.87
---------------------------------------------------------------------------
(1) Excludes sulphur.
PrimeWest's 2006 fourth quarter funds flow from operations decreased over the prior
quarter mainly due to a decrease in the oil and natural gas liquids sales revenues
of $15.3 million due to a reduction in realized oil and natural gas liquids prices
and to increases in operating expenses. An increase to gas sales revenue of $12.6
million which arises from a $9.3 million price variance and a $3.3 million volume
variance, combined with increases to realized derivative gains and decreases to
royalties partially offset the decrease.
Fourth quarter 2006 funds flow was 34% lower than the same period in 2005 mainly
due to a significant decrease in commodity prices and an increase to operating expenses.
An increase to production volumes and realized derivatives gains and decreases to
royalty expenses had a positive impact on funds flow. The increase in production
volumes is due to additional volumes from acquisitions and capital development which
are partially offset by natural decline. The increase in operating expenses from
$33.6 million to $39.6 million was mainly due to inflationary cost pressures in
the Western Canadian oil and natural gas sector and power costs. The royalty rate
as a percentage of revenue decreased from 22% in the fourth quarter of 2005 to 19%
in the fourth quarter of 2006 mainly due to the 24% decrease in commodity prices.
Interest expense has increased from $11.9 million in the third quarter of 2006 to
$13.0 million in the fourth quarter mainly due to interest charges relating to prior
year tax returns. The increase from the fourth quarter 2006 compared to the same
period in 2005 is due to increases in the average debt balance and increases to
interest rates. The increase in the average debt balance was mainly due to the draw
down on the Credit Facility to finance the U.S. asset acquisition in the third quarter
of 2006.
Net debt increased from $772.4 million at September 30, 2006, to $820.8 million
at December 31, 2006. Approximately $28 million of the increase in net debt is due
to the conversion of the U.S. dollar and pounds sterling denominated debt to Canadian
dollars at the period end exchange rates. The U.S. dollar to Canadian dollar exchanges
rate increased from 1.117 at September 30, 2006, to1.1654 at December 31, 2006.
The pounds sterling exchange rate increased from $2.0873 at September 30, 2006,
to $2.2825 at December 31, 2006. The increase in the net debt balance from December
31, 2005, to December 31, 2006, was mainly due to the draw down on the Credit Facility
to finance the U.S. asset acquisition in the third quarter of 2006.
Capital expenditures including acquisitions were $58.1 million in the fourth quarter
of 2006 compared to $445.3 million in the third quarter of 2006. The third quarter
included the acquisition of the U.S. assets of $336.7 million and the Caroline properties
of $31.9 million. During the fourth quarter of 2006 18 gross well (12.9 net wells)
were drilled with a success rate of 94 %.
Quarterly Performance - Selected Measures
--------------------------------------------------------------------------
2006 2005 (1)
--------------------------------------------------------------------------
($ Millions, except
Per Trust Unit
amounts) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
---------------------------------------------------------------------------
Net revenues (2) 158.4 160.7 134.8 170.1 237.1 101.7 155.3 111.1
Net income 9.6 64.0 65.7 68.8 101.5 27.3 54.7 24.0
Funds flow from
operations 84.6 91.4 86.8 101.3 128.6 105.1 92.8 78.8
Net income per
Trust Unit - Basic 0.11 0.78 0.81 0.85 1.27 0.35 0.74 0.34
Net income per
Trust Unit -
Diluted 0.11 0.76 0.79 0.83 1.23 0.35 0.72 0.34
Funds flow per
Trust Unit - Basic 1.01 1.11 1.06 1.25 1.61 1.34 1.26 1.11
Funds flow per
Trust Unit -
Diluted 1.00 1.09 1.03 1.22 1.56 1.29 1.18 1.03
---------------------------------------------------------------------------
(1) See note 3 to the Consolidated Financial Statements.
(2) Net revenues equal revenues from the sale of crude oil, natural gas
and natural gas liquids less Crown and other royalties plus realized
and unrealized gain or loss on derivatives, gain on sale of marketable
securities and other income.
The above table highlights PrimeWest's performance by selected measures for the
quarter ended December 31, 2006, and the preceding seven quarters.
Commodity prices, production volumes and royalties impact net revenues. Non-cash
items, including the unrealized gain or loss on derivatives and the gain on sale
of marketable securities also impact net revenues.
Net income and net income per Trust Unit include both cash and non-cash items. The
non-cash items such as 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.
Annual Performance - Selected Measures
---------------------------------------------------------------------------
($ Millions,
except Per Trust Unit amounts) 2006 2005 2004
---------------------------------------------------------------------------
Gross revenue $ 698.5 $ 801.2 $ 550.1
Net income $ 208.3 $ 207.5 $ 105.4
Net income per Trust Unit - Basic $ 2.53 $ 2.73 $ 1.77
Net income per Trust Unit - Diluted $ 2.52 $ 2.66 $ 1.77
Funds flow from operations $ 364.1 $ 405.4 $ 262.2
Funds flow per Trust Unit - Basic $ 4.43 $ 5.35 $ 4.41
Funds flow per Trust Unit - Diluted $ 4.37 $ 4.91 $ 4.15
Total assets $ 2,588.5 $ 2,131.9 $ 2,240.9
Long-term financial liabilities (1) $ 710.9 $ 394.8 $ 696.6
---------------------------------------------------------------------------
(1) Includes long-term debt, derivative liabilities and the asset
retirement obligation.
The above table highlights selected performance measures for the years ended December
31, 2006, 2005 and 2004.
The increase in gross revenues net of transportation from $550.1 million in 2004
to $801.2 million in 2005 was largely due to increases in production volumes resulting
from the Calpine asset acquisition in the third quarter of 2004 and increases to
realized commodity prices over the period. The decrease in gross revenue in 2006
to $698.5 million is primarily due to lower natural gas production volumes and lower
realized natural gas prices.
Net income increased from 2004 to 2005 due to increases in gross revenues (described
above) and realized hedging gains, offset by increases to royalties, operating expense,
cash G&A expense and interest expense. Increases to non-cash expenses including
DD&A and unrealized losses on derivatives, and reductions to future income tax recoveries
have negatively impacted net income during the period. The increases to the operating
and cash G&A expenses were due mainly to additional production volumes and staffing
requirements resulting from corporate and asset acquisitions. Net income remained
relatively flat from 2005 to 2006 as lower oil and gas revenues, and higher operating
expenses were offset by lower royalties, increases to realized and unrealized gains
on derivatives and increases to future income tax recoveries.
Funds flow from operations increased from $262.2 million in 2004 to $405.4 million
in 2005 due to increases in gross revenues (as described above) and realized derivative
gains. Increases to royalties, operating expenses and cash G&A expenses, all of
which are attributable to the Calpine acquisition, offset the increases to revenues.
Funds flow from operations decreased to $364.1 million in 2006 from 2005 due to
lower oil and gas revenues resulting from decreases in realized commodity prices
and production volumes and increases to operating costs which are mainly due to
inflationary pressures on the price of industry related goods and services. Higher
G&A costs, increases to interest expense due to higher debt levels and increases
to site restoration and reclamation expenditures also reduced funds flow from operations.
Total assets at December 31, 2005, exceeded the balance at December 31, 2004, mainly
due to the Calpine asset acquisition. The increase in total assets from 2005 to
2006 was mainly due to the acquisition of the U.S. assets in the third quarter of
2006 and to the 2006 capital development program offset by DD&A.
Long-term financial liabilities decreased from December 31, 2004, to December 31,
2005, due to the conversion of $186.2 million of Debentures into Trust Units and
to the repayment of $111.0 million of the Credit Facility. Long-term financial liabilities
increased to $710.9 million at December 31, 2006, due to the draw down on the Credit
Facility to finance the acquisition of the U.S. assets and to the increase in the
asset retirement obligation resulting from a review of actual costs incurred and
to a new directive by the Alberta Energy and Utilities Board.
Critical Accounting Estimates
PrimeWest's financial statements have been prepared in accordance with GAAP. 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 this MD&A 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.
Disclosure of Oil and Natural Gas Reserves
PrimeWest's December 31, 2006, reserves are derived from the GLJ Reserve Report.
Proved oil and natural gas reserves 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 entity should result in at least
a 90% probability that the quantities 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 entity should result in at least a 50% probability that the quantities
recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.
The oil and natural 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 natural gas reserves on the financial results and position
of PrimeWest are described under the heading Full Cost Accounting for Oil and Natural
Gas Activities.
In addition to the categorization of its reserves into "Gross" and "Net", as required
by NI 51-101, PrimeWest also uses the term "Company Interest' to describe its reserves.
Company Interest reserves include working interest and royalties receivable by PrimeWest,
with no deduction of royalties payable. PrimeWest reported its reserves on a Company
Interest basis prior to the implementation of NI 51-101 and PrimeWest continues
to provide this disclosure for comparability purposes.
PrimeWest's disclosure of reserves data and other oil and natural gas information
is made in conformity with NI 51-101. There are differences between the requirements
under NI 51-101 and those imposed by the SEC, including with respect to the disclosure
of Proved Reserves, Probable Reserves and estimated future net cash flows from Reserves.
FULL COST ACCOUNTING FOR OIL AND NATURAL GAS ACTIVITIES
PrimeWest follows Canadian Institute of Chartered Accountants (CICA) Accounting
Guideline 16 (AcG-16), "Oil and Gas Accounting - Full Costs." The guideline requires
cost centres be tested for recoverability using undiscounted future cash flows from
Proved reserves using forward indexed prices. When the carrying amount of a cost
centre is not recoverable, the cost centre is written down to its fair value. Fair
value is estimated using accepted present value techniques that 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 activities, whether successful or not, are capitalized.
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 natural gas reserves. An increase in estimated Proved
oil and natural 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,
including commodity prices hedges, to manage market risk.
The estimation of the fair value of certain financial derivatives requires considerable
judgment. The estimation of the fair value of commodity price hedges requires sophisticated
financial models that incorporate forward price and volatility and that, 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
The calculation of our asset retirement obligations, requires a significant number
of estimates with respect to activities that will occur in many years to come. In
arriving at the recorded amount of the asset retirement obligation numerous assumptions
are made with respect to ultimate settlement amounts, inflation factors, credit
adjusted discount rates and timing of settlement. The asset retirement obligation
also results in an increase to the carrying cost of capital assets. The obligation
accretes to a higher amount with the passage of time as it is determined using discounted
present values. A change in any one of the assumptions could impact the estimated
future obligation and in return, net income.
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 uses the purchase method to account for its acquisitions. 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 natural gas properties primarily involves
placing a value on the oil and natural gas reserves. The valuation of oil and natural
gas reserves entails the process described above under Proved, Probable and Proved
Plus Probable Oil and Natural 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 natural 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 CICA
section 3062, Goodwill and Other Intangible Assets, goodwill is not 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.
UNIT BASED COMPENSATION
PrimeWest calculates the fair value of Trust Unit Appreciation Rights issued under
its Long-Term Incentive Plan using a binominal lattice option pricing model. The
process involves the use of significant estimates and assumptions which may change
over time. The values calculated under the option pricing model may not reflect
the actual value realized.
Recent Accounting Pronouncements Issued But Not Implemented
The following new or amended standards and guidelines were issued but not implemented
by PrimeWest.
FINANCIAL INSTRUMENTS
In May 2005 the CICA issued the Handbook Sections:
- 1530, Comprehensive Income;
- 3855, Financial Instruments - Recognition and Measurement;
- 3861, Financial Instruments - Disclosure and Presentation; and
- 3865, Hedges.
Under the these new standards, all financial assets should be measured at fair value
with the exception of loans, receivables and investments that are intended to be
held to maturity and certain equity investments, which should be measured at cost.
Similarly, all financial liabilities should be measured at fair value when they
are either derivatives or held for trading. Gains and losses on financial instruments
measured at fair value will be recognized in the income statement in the periods
they arise with the exception of gains and losses arising from:
- Financial assets held for sale, for which unrealized gains and losses are deferred
in other comprehensive income until sold or impaired; and
- Certain financial instruments that qualify for hedging accounting.
Section 3855 and 3865 make use of the term "other comprehensive income." Other comprehensive
income comprises revenues, expenses, gains, and losses that are excluded from net
income. Unrealized gains and losses in respect of qualifying hedging instruments,
unrealized foreign exchange gains and losses, and unrealized gains and losses on
financial instruments held for sale will be included in other comprehensive income
and reclassified to net income when realized. Comprehensive income and its components
will be a required disclosure under the new standard. Section 3861 addresses the
presentation of financial statements and non-financial derivatives, and identifies
the information that should be disclosed about them. These standards are effective
for interim and annual financial statements relating to fiscal years beginning on
or after October 1, 2006. The deferred charges which are currently shown as an asset
an our balance sheet will be reclassified to deficit with the implementation of
the new handbook section. We do not anticipate that there will be any other significant
impacts on the consolidated financial statements.
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 natural gas royalty trust sector and the conventional
oil and natural gas exploration and production 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 below.
COMMODITY PRICE, FOREIGN EXCHANGE AND INTEREST RATE RISK
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 of the Trust's control. These factors include:
- World market forces, specifically the actions of OPEC and other large crude oil
producing countries including Russia, and their implications for the supply of crude
oil;
- World and North American economic conditions, which influence the demand for 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. currency exchange rate, which 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 between 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, with the
results actively monitored by the Board.
Beyond the hedging strategy, PrimeWest also mitigates risk by having a diversified
marketing portfolio, by transacting with a number of counterparties and by limiting
the exposure to any individual counterparty. In 2006 approximately 17% of the Trust's
natural gas production was sold to aggregators and 83% into the Alberta short-term
or export long-term markets.
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.
The primary objectives of our hedging program are to stabilize cash flow, reducing
its volatility, to lock in the economics of major acquisitions and to protect our
capital structure when commodity prices cycle downwards, while retaining some exposure
to pricing upside. In 2006 PrimeWest recorded a gain/loss of $23.6 million from
commodity hedges ($0.28 per Trust Unit), while in 2005 PrimeWest recorded a loss
of $44.3 million ($0.54 per Trust Unit).
OPERATIONAL AND OTHER BUSINESS RISKS
PrimeWest is also exposed to a number of risks related to its activities within
the oil and natural gas industry that also 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:
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Risk We Mitigate By
---------------------------------------------------------------------------
Production
Risk associated with the production Performing regular and proactive
of oil and natural gas - includes well, facility and pipeline
well operations, processing and maintenance supported by
the physical delivery of commodities telemetry, physical inspection
to market. and diagnostic tools.
---------------------------------------------------------------------------
Commodity Price
Fluctuations in natural gas, crude Hedging. See Note 17 to the
oil and natural gas liquids prices. Consolidated Financial
Statements.
---------------------------------------------------------------------------
Transportation
Market risk related to the Diversifying the transportation
availability of transportation to systems on which we rely to get
market and potential disruption in our product to market.
delivery systems.
---------------------------------------------------------------------------
Natural Production Decline
Development risk associated with Diversifying our capital spending
capital enhancement activities program over a large number of
undertaken - the risk that capital projects so that excessive
spending on activities such as drilling, capital is not risked on any one
well completions, well workovers and activity. We also have a highly
other capital activities will not result skilled technical team of
in reserve additions or in added geologists, geophysicists and
production in quantities sufficient to engineers working to apply the
replace annual production declines. latest technology in planning
and executing capital programs.
Capital is spent only after
strict economic criteria for
estimated production and reserve
additions are met.
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Acquisitions
Acquisition risk associated with Our technical acquisition
acquiring producing properties at specialists evaluate potential
sufficiently low cost to renew our corporate or property
inventory of assets. 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.
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Reserves
Reserve risk in respect of the Contracting our reserves
quantity and quality of recoverable evaluation to a reputable third-
reserves estimated versus ultimately party consultant, GLJ. The
recovered. Operations and Reserves
Committee of the Board of
Directors of PrimeWest review
the work and independence of GLJ.
Our strategy is to invest in
mature, longer-life properties
having a higher proved producing
component in which the reserve
risk is generally lower and cash
flows are more stable and
predictable.
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Environmental Health and Safety (EH&S)
Environmental, health and safety risks Establishing and adhering to
associated with oil and natural gas strict guidelines for EH&S
properties and facilities. including training, proper
reporting of incidents,
supervision and awareness.
PrimeWest has active community
involvement in field locations
including regular meetings with
stakeholders in our operational
areas. 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 of
Directors, which acts as
PrimeWest's Environmental,
Health and Safety Committee.
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Regulation, Tax and Royalties
Changes in government regulations, Keeping informed of proposed
including reporting requirements, changes in regulations and laws
income tax laws, operating practices, to properly respond to and plan
environmental protection requirements for the effects that these
and royalty rates. changes may have on our
operations.
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Income Taxes - Unitholders - 2006
For the 2006 taxation year, Canadian Unitholders of PrimeWest were paid $3.75 per
Trust Unit in distributions. Of this distribution amount, 25% or $0.94 per Trust
Unit is deemed a tax-deferred return of capital, and 75% or $2.81 per Trust Unit
is taxable to Unitholders as other income (taxed at the same rate as interest income).
For Unitholders resident in the U.S., the taxability of distributions is calculated
using U.S. tax rules, which allow for the deduction of Crown royalties and accounting-based
depletion. Distributions are taxable as dividends with 82.48% of the 2006 distributions
taxable as a "qualified dividend" and the remaining 17.52% treated as a tax-deferred
return of capital. A 15% withholding tax applies to distributions paid to U.S. Unitholders.
Further details regarding the withholding tax is available on PrimeWest's website
at
www.primewestenergy.com.
For Canadian and U.S. Unitholders, the tax-deferred return of capital portion reduces
the Unitholder's adjusted cost base for purposes of calculating a capital gain or
loss upon ultimate disposition of their Trust Units. Unitholders contemplating a
disposition may wish to consult the "Unitholder Info" section on PrimeWest's website
and use the adjusted cost base calculator.
PrimeWest recommends that all Unitholders contact their tax advisors to discuss
tax-related issues.
The proposed changes to the tax treatment of mutual funds trusts which are to be
effective beginning 2011 may have adverse consequences for some Unitholders, particularly
Unitholders that are not residents of Canada and residents of Canada that are otherwise
exempt from Canadian income tax.
CONSOLIDATED BALANCE SHEETS
---------------------------------------------------------------------------
As at December 31 ($ Millions) 2006 2005
---------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 22.0 $ 36.8
Accounts receivable 104.5 125.0
Derivative assets (note 16) 23.5 -
Future income taxes (note 15) 2.3 3.9
Prepaid expenses 19.6 16.3
Inventory 0.3 3.5
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172.2 185.5
Cash reserved for site restoration and reclamation
(note 10) 2.2 9.2
Other assets and deferred charges (note 7) 7.4 8.8
Derivative assets (note 16) 5.3 -
Property, plant and equipment (note 6) 2,332.9 1,859.9
Goodwill 68.5 68.5
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$ 2,588.5 $ 2,131.9
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LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 143.3 $ 126.1
Current portion of long-term debt (note 8) 186.4 -
Future income taxes (note 15) 8.7 -
Derivative liabilities (note 16) - 11.3
Accrued distributions to Unitholders 18.1 25.0
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356.5 162.4
Long-term debt (note 8) 619.4 354.2
Derivative liabilities (note 16) - 0.2
Future income taxes (note 15) 153.9 214.8
Asset retirement obligation (note 9) 91.5 40.4
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1,221.3 772.0
UNITHOLDERS' EQUITY
Net capital contributions (note 11) $ 2,391.2 $ 2,294.3
Capital issued but not distributed 2.7 3.6
Convertible Unsecured Subordinated Debentures
(note 8) 1.2 1.8
Contributed surplus (note 12) 11.9 8.7
Cumulative translation account 6.2 -
Deficit (note 20) (1,046.0) (948.5)
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1,367.2 1,359.9
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$ 2,588.5 $ 2,131.9
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Commitments and contingencies (note 17)
CONSOLIDATED STATEMENTS OF CASH FLOW
---------------------------------------------------------------------------
For the years ended December 31 ($ Millions) 2006 2005 2004
---------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the year $ 208.3 $ 207.5 $ 105.4
Add/(deduct) items not involving cash from
operations:
Depletion, depreciation and amortization 235.0 230.2 197.3
Non-cash general and administrative 5.8 5.4 4.1
Non-cash foreign exchange loss/(gain) 13.5 (4.9) (11.9)
Gain on sale of marketable securities
(note 4) - (27.2) -
Unrealized (gain)/loss on derivatives (40.3) 11.6 (0.1)
Future income tax recovery (49.4) (14.8) (34.3)
Accretion on asset retirement obligation 3.6 2.5 2.0
Other non-cash items 1.9 3.8 4.3
Expenditures on site restoration and
reclamation (14.3) (8.7) (4.6)
---------------------------------------------------------------------------
Funds flow from operations $ 364.1 $ 405.4 $ 262.2
Change in non-cash working capital 29.7 (28.0) 11.9
---------------------------------------------------------------------------
$ 393.8 $ 377.4 $ 274.1
---------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust Units
(net of costs) $ 33.7 $ 20.4 $ 441.0
Proceeds from issue of Debentures - - 250.0
Net cash distributions to Unitholders (264.2) (241.5) (159.6)
Increase/(Decrease) in bank credit facilities 314.2 (111.0) 166.0
Increase in Senior Secured Notes 130.7 - -
Increase in deferred charges (0.7) - (10.0)
Change in non-cash working capital (9.7) 4.2 10.9
---------------------------------------------------------------------------
$ 204.0 $ (327.9) $ 698.3
---------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (264.5) (192.5) (129.7)
Acquisition of capital/corporate assets (369.6) - (807.4)
Proceeds on disposal of property, plant and
equipment 3.5 26.0 96.5
Investment in marketable securities (note 4) - - (72.7)
Decrease/(Increase) in cash reserved for
future site reclamation 7.0 1.1 (2.1)
Proceeds on disposal of marketable securities - 94.5 -
Change in non-cash working capital 11.0 3.8 (5.1)
---------------------------------------------------------------------------
$ (612.6) $ (67.1) $ (920.5)
---------------------------------------------------------------------------
(Decrease)/Increase in cash and cash
equivalents for the year $ (14.8) $ (17.6) $ 51.9
Cash and cash equivalents, beginning of year 36.8 54.4 2.5
---------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 22.0 $ 36.8 $ 54.4
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Cash interest paid $ 28.8 $ 23.8 $ 15.0
---------------------------------------------------------------------------
Cash taxes paid $ 2.7 $ 5.4 $ 3.8
---------------------------------------------------------------------------
Non-cash transactions -- conversion of
debentures into Trust Units $ 17.8 $ 193.5 $ 0.3
---------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
---------------------------------------------------------------------------
For the years ended December 31
($ Millions, except per Trust Unit amounts) 2006 2005 2004
---------------------------------------------------------------------------
REVENUES
Sales of crude oil, natural gas and natural
gas liquids $ 698.5 $ 801.2 $ 550.1
Crown and other royalties (144.8) (172.8) (119.8)
Realized gain/(losses) on derivatives
(note 16) 25.5 (43.5) (27.4)
Unrealized (loss)/gain on derivatives
(note 16) 40.3 (11.6) 0.1
Gain on sale of marketable securities
(note 4) - 27.2 -
Other income 4.5 4.7 0.6
---------------------------------------------------------------------------
$ 624.0 $ 605.2 $ 403.6
---------------------------------------------------------------------------
EXPENSES
Operating $ 138.9 $ 117.8 $ 89.7
Transportation 7.5 7.2 8.2
General and administrative 30.4 28.3 23.1
Interest 34.7 28.3 20.6
Depletion, depreciation and amortization
(note 6) 235.0 230.2 197.3
Accretion of asset retirement obligations
(note 9) 3.6 2.5 2.0
Foreign exchange loss/(gain) (note 2) 13.5 (4.6) (11.7)
---------------------------------------------------------------------------
$ 463.6 $ 409.7 $ 329.2
---------------------------------------------------------------------------
Income before taxes for the year 160.4 195.5 74.4
---------------------------------------------------------------------------
Income and capital taxes 1.5 2.8 3.3
Future income taxes recovery (note 15) (49.4) (14.8) (34.3)
---------------------------------------------------------------------------
(47.9) (12.0) (31.0)
---------------------------------------------------------------------------
Net income for the year $ 208.3 $ 207.5 $ 105.4
Deficit, beginning of year (948.5) (879.4) (555.4)
Adjustment to Unitholder's equity at beginning
of period to adopt: new oil and gas accounting
standard (note 3) - - (233.3)
---------------------------------------------------------------------------
Distributions paid or declared (305.8) (276.6) (196.1)
---------------------------------------------------------------------------
Adjustment to Unitholder's equity at
beginning of period to adopt:
new oil and gas accounting standard (note 3) - - (233.3)
---------------------------------------------------------------------------
Deficit, end of year $(1,046.0) $ (948.5) $ (879.4)
---------------------------------------------------------------------------
Net income per Trust Unit (note 11) $ 2.53 $ 2.73 $ 1.77
Net income per Trust Unit - Diluted
(note 11) $ 2.52 $ 2.66 $ 1.77
---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(ALL AMOUNTS ARE EXPRESSED IN MILLIONS OF CANADIAN DOLLARS UNLESS OTHERWISE INDICATED)
1. Structure of The Trust
PrimeWest Energy Trust (PrimeWest or the Trust) is an open-ended investment trust
formed under the laws of Alberta in accordance with a declaration of trust dated
August 2, 1996, as Amended. The beneficiaries of the Trust are the holders of Trust
Units (the Unitholders).
The principal undertaking of the Trust's operating companies, PrimeWest Energy Inc.,
and PrimeWest Petroleum Inc. is to acquire and hold, directly and indirectly, interests
in oil and natural gas properties. One of the Trust's primary assets is a royalty
entitling it to receive 99% of the net cash flow generated by the Canadian oil and
natural gas interests owned by PrimeWest. The royalty acquired by the Trust effectively
transfers substantially all of the economic interest in the Canadian properties
to the Trust.
2. Significant Accounting Policies
CONSOLIDATION
These consolidated financial statements include the accounts of the Trust and its
wholly owned subsidiaries. The Trust, through the royalty, obtains substantially
all of the economic benefits of the operations of PrimeWest.
CASH AND CASH EQUIVALENTS
Short-term investments, with maturities less than three months at the date of acquisition,
are considered to be cash equivalents and are recorded at cost, which approximates
market value.
FOREIGN CURRENCY TRANSLATION
The Trust has U.S. dollar operations, which are self-sustaining. The self-sustaining
operation is translated into Canadian dollars using the current rate method. Under
this method, assets and liabilities are translated using period-end exchange rates
with revenues and expenses translated using average rates for the period. Gains
and losses arising on the translation of assets and liabilities are included in
the cumulative translation account under Unitholders' Equity.
The Trust has U.S. dollar denominated and pounds sterling debt which are translated
into Canadian dollars at the period end rate with the resulting foreign exchange
gain or loss recorded on the income statement.
INVENTORY
Inventory is measured at the lower of cost and net realizable value.
GOODWILL
Goodwill represents the excess of purchase price over fair value of net assets acquired
and liabilities assumed. Goodwill is assessed for impairment at least annually.
To assess impairment, the fair value of each reporting unit is determined and compared
to the book value of the reporting unit. The amount of the impairment is determined
by deducting the fair value of the reporting unit's assets and liabilities from
the fair value of the reporting unit to determine the implied fair value of goodwill
and comparing that amount to the book value of the reporting unit's goodwill. Any
excess of the book value of goodwill over the implied fair value of goodwill is
the impairment amount.
PROPERTY, PLANT AND EQUIPMENT
PrimeWest follows the full cost method of accounting. All costs of acquiring oil
and natural gas properties and related development costs are capitalized and accumulated
into either the Canadian or the U.S. cost centre. Maintenance and repairs are charged
against earnings. Renewals and enhancements that extend the economic life of the
capital asset are capitalized.
Gains and losses are not recognized on the disposition of oil and natural gas properties
unless that disposition would alter the rate of depletion by 20% or more.
i) Ceiling test
PrimeWest places a limit on the aggregate cost of capital assets that may be carried
forward for depletion against net revenues of future periods (the ceiling test).
The ceiling test is an impairment test whereby the carrying amount of capitalized
assets is compared to the undiscounted cash flows from Proved reserves plus Unproved
properties using management's best estimate of future prices. If the asset value
exceeds the undiscounted cash flows the impairment is measured as the amount by
which the carrying amount of the capitalized asset exceeds the future discounted
cash flows from Proved plus Probable reserves. The discount rate used is the risk-free
rate.
ii) Depletion, depreciation and amortization (DD&A)
Provision for depletion and depreciation is calculated on the unit-of-production
method, based on Proved reserves before royalties. Reserves are estimated by independent
petroleum engineers. Reserves are converted to equivalent units on the basis of
approximate relative energy content. Depreciation and amortization of head office
furniture and equipment is provided for at rates ranging from 10 -30%.
ASSET RETIREMENT OBLIGATION
PrimeWest recognizes the future retirement obligations associated with the retirement
of property, plant and equipment. The obligations are initially measured at fair
value and subsequently adjusted for accretion of discount and changes in the underlying
liability. The asset retirement cost is capitalized to the related asset and amortized
to earnings over time.
JOINT VENTURE ACCOUNTING
PrimeWest conducts some of its oil and natural gas production activities through
joint ventures, and the accounts reflect only PrimeWest's proportionate interest
in such activities.
UNIT-BASED COMPENSATION
PrimeWest accounts for its Unit Appreciation Rights (UARs) issued to employees and
the Board of Directors using the fair value method. The fair value of each UAR is
estimated on the date of the grant using a binomial lattice options pricing model
and charged to earnings over the vesting period with a corresponding increase to
contributed surplus.
INCOME TAXES
The Trust is considered an inter-vivo trust for income tax purposes. As such, the
Trust is subject to tax on any taxable income that is not allocated to the Unitholders.
Periodically, current taxes may be payable by PrimeWest, depending upon the timing
of income tax deductions.
Future income taxes are recorded using the liability method of accounting. Future
income taxes are recorded to the extent that the carrying value of PrimeWest's capital
assets exceeds the available tax pools.
FINANCIAL INSTRUMENTS
PrimeWest uses financial instruments to manage its exposure to fluctuations in commodity
prices, electricity rate and foreign exchange. PrimeWest does not use financial
instruments for speculative trading purposes. The financial instruments are Marked-to-Market
with the resulting gain or loss reflected in earnings for the reporting period.
MEASUREMENT UNCERTAINTY
Certain items recognized in the Financial Statements are subject to measurement
uncertainty. The recognized amounts of such items are based on PrimeWest's best
information and judgment. Such amounts are not expected to change materially in
the near term. They include the amounts recorded for depletion, depreciation and
asset retirement obligations which depend on estimates of oil and natural gas reserves
or the economic lives and future cash flows from related assets, future income tax
and unit based compensation.
3. Changes in Accounting Policies
CHANGE IN METHOD OF ACCOUNTING FOR UNIT-BASED COMPENSATION
Effective January 1, 2005, PrimeWest adopted the fair value method of accounting
for its Long-Term Incentive Plan (LTIP) with respect to UARs granted on or after
January 1, 2002. Under the fair value method, PrimeWest recognizes compensation
expense related to the UARs over the vesting period of the UARs granted with the
related credit being charged to contributed surplus. In prior years, PrimeWest had
been applying the intrinsic method to value its unit-based compensation whereby
the value of the UARs was adjusted at the end of each accounting period to reflect
the impact of the reinvestment of cumulative distributions and the changes in the
trading price of the Trust Units. The changes in value of the UAR liability were
reflected in G&A on the income statement.
PrimeWest has applied the fair value method retroactively to UARs issued on or after
January 1, 2002, and prior periods have been restated. At January 1, 2005, the change
in accounting policy resulted in an increase to the future income tax liability
of $14.5 million (2004 - $11.2 million), a decrease to net capital contributions
of $7.9 million (2004 - $5.3 million), a decrease to the LTIP equity of $20.1 million
(2004 - $14.6 million), an increase in contributed surplus of $6.4 million (2004
- $3.6 million) and an increase to accumulated income of $7.1 million (2004 - $5.1
million).
The change in accounting method resulted in an increase to 2005 net income of $52.7
million.
FULL COST ACCOUNTING
The adoption of CICA Accounting Guideline 16 (AcG-16) modifies how the ceiling test
is performed resulting in a two stage process. The guideline is effective for fiscal
years beginning on or after January 1, 2004. The cost impairment test is a two-stage
process, which is performed at least annually. The first stage of the test determines
if the cost pool is impaired. An impairment loss exists when the carrying amount
of an asset is not recoverable and exceeds its fair value. The carrying amount is
not recoverable if it exceeds the sum of the undiscounted cash flows from Proved
reserves plus unproved properties using management's best estimate of future prices.
The second stage determines the amount of the impairment loss to be recorded. The
impairment is measured as the amount by which the carrying amount of capitalized
assets exceeds the future discounted cash flows from Proved plus Probable reserves.
The discount rate used is the risk free rate.
PrimeWest performed the ceiling test under AcG-16 as of January 1, 2004. The impairment
test was calculated using the consultants' average prices at January 1 for the years
2004 to 2008 as follows:
---------------------------------------------------------------------------
Consultants' Average Price Forecasts 2004 2005 2006 2007 2008
---------------------------------------------------------------------------
West Texas Intermediate (US$/bbl) 29.21 26.43 25.42 25.38 25.51
AECO (C$/mcf) 5.90 5.33 4.98 4.95 4.92
---------------------------------------------------------------------------
The ceiling test resulted in a before-tax impairment of $308.9 million and an after-tax
impairment of $233.3 million. This write down was recorded to accumulated income
in the first quarter of 2004 with the adoption of AcG-16.
4. Gain on Sale of Marketable Securities
PrimeWest sold its 8% ownership in the Viking Energy Royalty Trust in 2005 (formerly
Calpine Natural Gas Trust) for net proceeds of $94.5 million resulting in a gain
of $27.1 million.
5. Acquisitions
a) On July 6, 2006, PrimeWest acquired oil and gas assets located in Montana, North
Dakota, Wyoming and Saskatchewan. The acquisition was accounted for as a business
acquisition pursuant to EIC 124 and as such, the purchase method of accounting was
applied. The net assets acquired and consideration paid were as follows:
---------------------------------------------------------------------------
Net Assets Acquired at
Assigned Values ($ Millions) Consideration Paid ($ Millions)
---------------------------------------------------------------------------
Petroleum and natural
gas assets $ 343.0 Cash $ 329.5
Working capital (0.3) -
Asset retirement Costs associated
obligation (6.0) with acquisition 7.2
---------------------------------------------------------------------------
$ 336.7 $ 336.7
---------------------------------------------------------------------------
b) On September 2, 2004, PrimeWest acquired oil and natural 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)
---------------------------------------------------------------------------
Petroleum and natural gas
assets $ 745.3
Inventory 4.2 Cash $ 747.0
Net closing
Working capital 2.7 adjustments (11.1)
Costs associated
Asset retirement obligation (12.0) with acquisition 4.3
---------------------------------------------------------------------------
$ 740.2 $ 740.2
---------------------------------------------------------------------------
c) On March 16, 2004, PrimeWest completed the acquisition of Seventh Energy Ltd.
Subsequent to the acquisition, Seventh Energy was amalgamated with PrimeWest Gas
Corp. The acquisition was accounted for using the purchase method of accounting
with net assets acquired and consideration paid as follows:
---------------------------------------------------------------------------
Net Assets Acquired at
Assigned Values ($ Millions) Consideration Paid ($ Millions)
---------------------------------------------------------------------------
Petroleum and natural gas
assets $ 46.5
Goodwill 12.4
Working capital (2.5)
Long-term debt assumed (9.9)
Office lease obligation (0.1)
Asset retirement obligation (0.5) Cash $ 34.6
Costs associated
Future income taxes (11.1) with acquisition 0.2
---------------------------------------------------------------------------
$ 34.8 $ 34.8
---------------------------------------------------------------------------
6. Property, Plant and Equipment
2006
---------------------------------------------------------------------------
Accumulated
Depletion,
Depreciation and Net Book
($ Millions) Cost Amortization Value
---------------------------------------------------------------------------
Property acquisition oil and natural
gas rights $ 3,131.3 $ (1,427.8) $ 1,703.5
Drilling and completion 593.2 (155.9) 437.3
Production facilities and equipment 251.8 (68.1) 183.7
Head office furniture and equipment 20.3 (11.9) 8.4
---------------------------------------------------------------------------
$ 3,996.6 $ (1,663.7) $ 2,332.9
---------------------------------------------------------------------------
2005
---------------------------------------------------------------------------
Accumulated
Depletion,
Depreciation and Net Book
($ Millions) Cost Amortization Value
---------------------------------------------------------------------------
Property acquisition oil and natural
gas rights $ 2,677.1 $ (1,260.7) $ 1,416.4
Drilling and completion 417.9 (110.7) 307.2
Production facilities and equipment 176.6 (48.4) 128.2
Head office furniture and equipment 16.8 (8.7) 8.1
---------------------------------------------------------------------------
$ 3,288.4 $ (1,428.5) $ 1,859.9
---------------------------------------------------------------------------
Unproved land costs of $74.1 million (2005 - $88.0 million) and $3.9 million of
capital not in use (2005 - $4.1 million) are excluded from costs subject to depletion
and depreciation.
PrimeWest capitalized $5.9 million of G&A costs in 2006 (2005 - $3.7 million).
PrimeWest has performed ceiling tests as at December 31, 2006, on its Canadian and
U.S. assets. The impairment tests were calculated using the Consultant's Average
Prices (from GLJ, Sproule Associates Limited and McDaneil & Associates Consultants
Ltd.) at January 1, 2007, for the years 2007 to 2012 as follows:
---------------------------------------------------------------------------
Consultants' Average Price Forecasts 2007 2008 2009 2010 2011 2012
---------------------------------------------------------------------------
West Texas Intermediate (US$/bbl) 63.41 63.34 60.07 57.92 56.33 57.27
---------------------------------------------------------------------------
AECO (C$/mcf) 7.38 7.83 7.77 7.75 7.90 8.11
---------------------------------------------------------------------------
Subsequent to 2010, prices are increased by approximately 2% per year. The December
31, 2006, ceiling tests resulted in a surplus for both the Canadian and U.S. cost
centres.
7. Other Assets and Deferred Charges
---------------------------------------------------------------------------
($ Millions) 2006 2005
---------------------------------------------------------------------------
Deferred charges $ 7.4 $ 8.7
Other assets - 0.1
---------------------------------------------------------------------------
$ 7.4 $ 8.8
---------------------------------------------------------------------------
Deferred charges represent the un-amortized balance of issue costs related to the
U.S. Secured Notes, U.K. Secured Notes and Debentures. These costs are amortized
over the life of the debt.
8. Long-Term Debt
---------------------------------------------------------------------------
($ Millions) 2006 2005
---------------------------------------------------------------------------
Bank credit facilities $ 477.4 $ 153.0
U.S. Secured Notes 145.7 145.4
U.K. Secured Notes 143.8 -
Convertible Unsecured Subordinated Debentures 38.9 55.8
---------------------------------------------------------------------------
$ 805.8 $ 354.2
Current portion of long-term debt 186.4 -
---------------------------------------------------------------------------
$ 619.4 $ 354.2
---------------------------------------------------------------------------
Long-term debt is comprised of the Credit Facility, the U.S. Secured Notes, the
U.K. Secured Notes and the Debentures of $477.4 million, $145.7 million, $143.8
million and $38.9 million respectively. $36.4 million relating to the U.S. Secured
Notes and $150 million relating to a bridge facility that formed part of the Credit
Facility are included in working capital as a current portion of long-term debt.
In addition to amounts outstanding under the Credit Facility, PrimeWest has outstanding
letters of credit in the amount of $6.8 million (2005 - $6.6 million).
The indebtedness under the Credit Facility, the U.S. Secured Notes and the U.K.
Secured Notes is supported by a borrowing base of $750 million and is comprised
of revolving facilities under the Canadian portion of the Credit Facility having
a capacity of $220.5 million, the U.S. portion of the Credit Facility having a capacity
of Cdn $255.0 million, the U.S. Secured Notes valued at $143.8 million based on
a U.S. dollar exchange rate of U.S. $0.87 and the U.K. Secured Notes valued at Cdn
$130.7 million. PrimeWest also had a $150 million bridge facility under the Canadian
portion of the Credit Facility, which expired upon repayment in January 2007.
As a result of the U.S. asset acquisition during the third quarter of 2006, PrimeWest
has drawn advances under the U.S. portion of the Credit Facility in U.S. dollars
in the form of LIBOR loans that bear interest at LIBOR plus a margin based on PrimeWest's
debt to EBITDA ratio. PrimeWest will continue to fund its ongoing operations in
Canada with advances from the Canadian portion of the Credit Facility utilizing
Banker Acceptances (BA) that bear interest at the BA rate plus a stamping fee determined
in the same manner as the LIBOR margin.
Advances under the Canadian portion of the bank credit facility are made in the
form of BAs, prime rate loans or letters of credit. In the case of BAs, interest
is a function of the BA rate plus a stamping fee based on PrimeWest's current ratio
of debt to cash flow. In the case of prime rate loans, interest is charged at the
bank's prime rate. For 2006, the effective interest rate on the bank credit facilities
was 5.8% (2005 - 4.0%).
The Credit Facility revolves until June 30, 2007, by which time the lenders will
have conducted their annual borrowing base review. The lenders also have the right
to re-determine the borrowing base at one other time during the year. During the
revolving phase, the Credit Facility has no specific terms of repayment. At the
end of the revolving period, the lenders have the right to extend the revolving
period for a further 364-day period or to convert the facility to a term facility.
If the lenders convert to a non-revolving facility, 60% of the aggregate principal
amount of the loan shall be repayable on the date that is 366 days after such conversion
date and the remaining 40% of the aggregate principal amount outstanding shall be
repayable on the date that is 365 days after the initial term repayment date.
U.S. Secured Notes
The U.S. Secured Notes in the amount of US$125 million have a final maturity 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$31.25 million commencing May 7, 2007.
Issuance costs incurred with the U.S. Secured Notes, in the amount of $1.5 million,
were classified as deferred charges on the balance sheet and are being amortized
over the term of the Notes.
The U.S. Secured Notes are the legal obligation of PrimeWest Energy Inc. and are
guaranteed by PrimeWest Energy Trust.
U.K. Secured Notes
The U.K. Secured Notes in the amount of Pound Sterling 63 million bear interest
at 5.76% per annum. PrimeWest entered into a currency swap transaction to fix the
aggregate principal value and annual interest payments at $130.7 million and $3.9
million, respectively. As a result of the swap, the U.K. Secured Notes bear interest
at an effective rate of 5.93% per annum with interest payable semi-annually on June
14 and December 14 of each year. The U.K. Secured Notes have a final maturity of
June 14, 2016. Issue costs of $0.7 million were included in deferred charges on
the balance sheet and are being amortized over the term of the Notes.
Collateral for the U.S. Secured Notes, the U.K. Secured Notes and the Credit Facility
is a floating charge debenture covering all existing and after acquired property
in the principal amount of US$1.5 billion. The secured parties for the revolving
Credit Facility and Secured Notes have agreed to share the security interests on
a pari passu basis.
Debentures
The 7.5% (Series I) and 7.75% (Series II) Debentures were issued on September 2,
2004 for proceeds of $150 million and $100 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 PrimeWest 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 $1,000 per Series II Debenture.
On redemption or maturity PrimeWest may elect to satisfy its obligations to repay
the principal by issuing Trust Units.
Debenture issue costs of $10.0 million were included in deferred charges on the
balance sheet and are being amortized over the terms of the Debentures.
In accordance with CICA Handbook section 3860 - "Financial Instruments," the Debentures
were initially recorded at their fair value of $147.0 million (Series I) and $94.8
million (Series II). The difference between the fair value and proceeds of $8.1
million was recorded in equity ($3.0 million (Series I) and $5.1 million (Series
II)).
The Series I and Series II Debentures are being accreted such that the liability
at maturity will equal the proceeds of $150 million and $100 million less conversions
respectively. During 2006, $9.1 million (2005 - $114.3 million) of Series I and
$8.1 million (2005 -$72.9 million) of Series II Debentures included in long-term
debt were converted to equity. Accretion expense was $0.3 million (2005 - $1.0 million).
The five year schedule of long-term debt repayment based on maturity is as follows:
2007 - $186.4 million, 2008 - $363.8 million, 2009 - $36.4 million, 2010 - $36.4
million and 2011 - $0 million.
9. Asset Retirement Obligations
Management has estimated the total future asset retirement obligation based on the
Trust's net ownership interest in all wells and facilities. This includes all estimated
costs to dismantle, remove, reclaim and abandon the wells and facilities and the
estimated time period during which these costs will be incurred in the future.
The following table reconciles the asset retirement obligation associated with the
retirement of oil and natural gas properties:
---------------------------------------------------------------------------
Asset Retirement Obligation ($ Millions) 2006 2005
---------------------------------------------------------------------------
Asset retirement obligation, December 31, 2005 $ 40.4 $ 40.3
Liabilities incurred 57.8 8.3
Liabilities settled (14.3) (8.7)
Accretion expense 3.6 2.5
Disposal of capital assets (2.0) (2.0)
Acquisition of U.S. Assets 6.0 -
---------------------------------------------------------------------------
Asset retirement obligation, December 31, 2006 $ 91.5 $ 40.4
---------------------------------------------------------------------------
As at December 31, 2006, the undiscounted, inflation adjusted amount of estimated
cash flows required to settle the obligation is $444.8 million. The estimated cash
flow has been discounted using a credit-adjusted risk free rate of 7.0% (2005 -
7%) and an inflation rate of 1.9% (2005 - 1.5%) . Although the expected period until
settlement ranges from a minimum of 1 year to a maximum of 50 years, the expectation
is that the costs will be paid over an average of 34 years (2005 - 33.9 years).
These future asset retirement costs will be funded from the cash reserved for site
restoration and reclamation and if required out of cash flow from operations.
During 2006 PrimeWest reviewed the estimates of its asset retirement obligation
and made an upward revision resulting from a review of actual costs incurred to
reclaim wells and to a directive by the Alberta Energy and Utilities Board related
to the remediation of facilities. This amount increased the related cost of the
underlying assets. This review accounts for approximately $38 million of the increase
in liabilities incurred.
10. Cash Reserve For Site Restoration And Reclamation
Commencing in 1998, funding for the reserve was provided for by reducing distributions
otherwise payable based on an amount per BOE produced ($0.50/BOE produced for 2006
and 2005). The cash amount contributed, including interest earned, was $7.3 million
in 2006 (2005 - $7.6 million). Actual costs of site restoration and reclamation
totalling $14.3 million were paid out of this cash reserve for the year ended December
31, 2006 (2005 - $8.7 million). As at December 31, 2006, the site reclamation fund
had a balance of $2.2 million (2005 - $9.2 million).
11. Unitholders' Equity
---------------------------------------------------------------------------
Amounts
Trust Units Number of Units ($ Millions)
---------------------------------------------------------------------------
Balance December 31, 2004 69,886,111 $ 2,029.8
Issued on exchange of Exchangeable Shares 91,871 1.7
Issued pursuant to Distribution Reinvestment
Plan 262,347 7.9
Issued pursuant to Premium Distribution Plan 932,142 27.4
Issued pursuant to Long-term Incentive Plan 487,421 1.3
Issued pursuant to conversion of Debentures 7,301,654 193.5
Issued pursuant to Optional Trust Unit Purchase
Plan 704,806 20.4
---------------------------------------------------------------------------
Balance December 31, 2005 79,666,352 $ 2,282.0
---------------------------------------------------------------------------
Equity Offering 599,950 20.3
Issued on exchange of Exchangeable Shares 91,755 1.5
Issued pursuant to Distribution Reinvestment
Plan 476,523 14.4
Issued pursuant to Premium Distribution Plan 943,150 28.3
Issued pursuant to Long-term Incentive Plan 366,033 1.2
Issued pursuant to conversion of Debentures 672,339 17.8
Issued pursuant to Optional Trust Unit
Purchase Plan 440,457 13.4
Issued pursuant to Consolidation/Fractional Units 51 -
---------------------------------------------------------------------------
Balance December 31, 2006 83,256,610 $ 2,378.9
---------------------------------------------------------------------------
The weighted average number of Trust Units and Exchangeable Shares outstanding for
the twelve months ended December 31, 2006, was 82,270,315 (2005 - 75,808,919). For
purposes of calculating diluted net income per Trust Unit, 1,014,150 (2005 -3,247,742)
and 646,305 Trust Units (2005 -2,286,791) issueable pursuant to the conversion of
the Series I and Series II Debentures outstanding respectively and 326,065 Trust
Units (2005 - 1,220,958) issueable pursuant to the LTIP were added to the weighted
average number.
PRIMEWEST EXCHANGEABLE SHARES
PrimeWest has an unlimited number of Exchangeable Shares. The Exchangeable Shares
are exchangeable into Trust Units at any time up to March 29, 2010, based on an
exchange ratio that adjusts each time the Trust makes distribution to its Unitholders.
The exchange ratio, which was 1:1 on the date that the Exchangeable Shares were
issued, is based on the total monthly distribution, divided by the closing Trust
Unit price on the distribution payment date. The exchange ratio on December 31,
2006, was 0.63765:1 (2005 - 0.56399:1).
---------------------------------------------------------------------------
Number of Amounts
Exchangeable Shares Shares ($ Millions)
---------------------------------------------------------------------------
Balance December 31, 2004 1,294,391 $ 12.2
Issued for Special Employee Retention Plan 94,340 1.8
Exchanged for Trust Units (169,396) (1.7)
---------------------------------------------------------------------------
Balance December 31, 2005 1,219,335 $ 12.3
Issued for Special Employee Retention Plan 94,340 1.5
Exchanged for Trust Units (151,811) (1.5)
---------------------------------------------------------------------------
Balance December 31, 2006 1,161,864 $ 12.3
---------------------------------------------------------------------------
TRUST UNITS AND EXCHANGEABLE SHARES ISSUED AND OUTSTANDING
---------------------------------------------------------------------------
Number of Shares 2006 2005
---------------------------------------------------------------------------
Trust Units issued and outstanding 83,256,610 79,666,352
Exchangeable Shares
2006 - 1,161,864 shares exchangeable at
0.63765:1
2005 - 1,219,335 shares exchangeable at
0.56399:1 740,863 687,693
---------------------------------------------------------------------------
Total Trust Units and Exchangeable Shares issued
and outstanding 83,997,473 80,354,045
Convertible Unsecured Subordinated Debentures
Series I 895,245 1,246,981
Series II 554,075 874,717
Unit Appreciation Rights 326,065 1,220,958
---------------------------------------------------------------------------
Total Trust Units and Exchangeable Shares issued
and outstanding and Trust Units issued pursuant
to the conversion of the Convertible Unsecured
Subordinated Debentures and the Long-Term
Incentive Plan 85,772,858 83,696,701
---------------------------------------------------------------------------
12. Contributed Surplus
Contributed surplus includes the accumulated unit-based compensation charge in respect
of PrimeWest's unexercised Unit
Appreciation Rights granted under the LTIP on or after January 1, 2002. Upon exercise
of the UARs and delivery of the Trust Units, the contributed surplus account is
reduced and the amount is transferred to net capital contributions.
---------------------------------------------------------------------------
($ Millions)
---------------------------------------------------------------------------
Balance, December 31, 2004 $ 6.4
General and administrative expense 3.6
Unit Appreciation Rights exercised (1.3)
---------------------------------------------------------------------------
Balance, December 31, 2005 $ 8.7
General and administrative expense 4.4
Unit Appreciation Rights exercised (1.2)
---------------------------------------------------------------------------
Balance, December 31, 2006 $ 11.9
---------------------------------------------------------------------------
13. Long-Term Incentive Plan
Under the terms of the LTIP, the number of Trust Units that may be reserved for
issuance pursuant to the exercise of Unit Appreciation Rights (UARs) granted to
Directors and employees of PrimeWest is limited to 7.5% of the basic number of issued
and outstanding Trust Units at any given time. Payouts under the plan are based
on total Unitholder return, calculated using both the change in the Trust Unit price
as well as cumulative distributions paid. The plan requires that a hurdle return
of 5% per annum be achieved before payouts accrue. UARs have a term of up to six
years and vest equally over a three-year period, except for those issued to the
members of the Board, which vest immediately. PrimeWest has the option of settling
payouts under the plan in PrimeWest Trust Units or in cash. To date, all payouts
under the plan have been in the form of Trust Units.
Effective January 1, 2005, PrimeWest adopted the fair value method of accounting
for its LTIP with respect to UARs granted on or after January 1, 2002. Under this
method of accounting, the fair value of the UARs is estimated using a recognized
options pricing model on the grant date and is amortized over the vesting period
with the amortized amount recorded in G&A expense offset by an increase to contributed
surplus. When the UARs are exercised, contributed surplus is decreased and net capital
contributions are increased.
In 2006 PrimeWest recorded $4.4 million (2005 - $3.6 million) in G&A expense related
to the LTIP.
For the twelve months ended December 31, 2006, PrimeWest used a lattice binomial
pricing model to calculate the estimated fair value of outstanding UARs issued on
or after January 1, 2002. The following assumptions were used to arrive at the estimated
fair value:
---------------------------------------------------------------------------
Weighted Average Assumptions 2006 2005
---------------------------------------------------------------------------
Risk-free interest rate 4.06% 3.18%
Expected volatility in Trust Unit price 22.9% 19.8%
Expected time until exercise 1.5 - 3.5 years 1 - 3 years
Expected forfeiture rate 13% 13%
Expected annual dividend yield zero zero
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Weighted
Average
Exercise
Summary of Changes Number of UARs Price
---------------------------------------------------------------------------
Balance outstanding, December 31, 2004 3,233,492 $ 28.77
Granted 1,517,674 30.40
Forfeited (122,873) (28.44)
Exercised (458,618) (28.42)
---------------------------------------------------------------------------
Balance outstanding, December 31, 2005 4,169,675 $ 29.92
Granted 1,187,170 37.89
Forfeited (385,068) 29.29
Exercised (511,737) 27.81
---------------------------------------------------------------------------
Balance outstanding, December 31, 2006 4,460,040 $ 31.96
---------------------------------------------------------------------------
Summary of UARs Outstanding at December 31, 2006
---------------------------------------------------------------------------
UARs Issued UARs Vested Range of Expiry
Year of Grant and Outstanding and "in the money" Exercise Prices Date
---------------------------------------------------------------------------
2002 grants 515,610 515,054 $ 25.90-33.76 2008
2003 grants 628,252 625,447 25.92-32.24 2009
2004 grants 1,032,488 397,268 24.24-32.49 2010
2005 grants 1,172,075 - 28.90-43.17 2011
2006 grants 1,111,615 - 23.96-43.41 2012
---------------------------------------------------------------------------
Total grants 4,460,040 1,537,769 $ 23.96-43.41
---------------------------------------------------------------------------
14. Related Party Transactions
As part of PrimeWest's 2002 internalization transaction, which closed on November
6, 2002, PrimeWest agreed to issue 377,360 Exchangeable Shares to certain Executive
Officers pursuant to the SERP. On November 6, 2004, 2005, and 2006, 94,340 Exchangeable
Shares were issued to those Executive Officers. An additional 94,340 shares will
be issued on November 6, 2007. For the 12 months ended December 31, 2006, $1.4 million
was recorded in G&A expense related to the SERP.
15. Income Taxes
PrimeWest follows the liability method to calculate future income taxes. Under this
method, future income tax assets and liabilities are recognized based on the estimated
tax effects of temporary differences in the carrying value of assets and liabilities
reported on the financial statements and their respective tax bases, using income
tax rates substantively enacted on the balance sheet date.
---------------------------------------------------------------------------
($ Millions) 2006 2005
---------------------------------------------------------------------------
Reserve for future expenditures $ 2.3 $ -
Derivative liabilities - 3.9
---------------------------------------------------------------------------
Future income tax asset $ 2.3 $ 3.9
---------------------------------------------------------------------------
---------------------------------------------------------------------------
($ Millions) 2006 2005
---------------------------------------------------------------------------
Loss carry forwards $ (3.0) $ (1.2)
Deferred financing charges 1.1 -
Derivative assets 7.0 -
Capital assets 183.8 224.8
Foreign exchange gain on long-term debt 1.3 4.8
Asset retirement obligation (27.6) (13.6)
---------------------------------------------------------------------------
Future income tax liability $ 162.6 $ 214.8
---------------------------------------------------------------------------
The provisions for income taxes vary from the amounts that would be computed by
applying the combined Canadian federal and provincial income tax rates for the following
reasons:
---------------------------------------------------------------------------
($ Millions) 2006 2005 2004
---------------------------------------------------------------------------
Income before taxes $ 160.4 $ 195.5 $ 74.4
Computed income tax expense (recovery) at
the Canadian statutory rate
of 34.5% (2005 - 37.62%, 2004 - 38.87%) 55.3 73.5 28.9
Increase/(Decrease) resulting from:
Non-deductible Crown royalties and other
payments - 0.3 0.3
Federal resource allowance (5.2) (12.3) (9.2)
Change in income tax rate (21.3) (2.7) (7.0)
Foreign exchange on long-term debt 3.1 (0.9) (2.2)
Amounts included in Trust income and other (79.8) (69.9) (41.8)
---------------------------------------------------------------------------
$ (47.9) $ (12.0) $ (31.0)
---------------------------------------------------------------------------
On October 31, 2006, the Minister of Finance released for comment draft legislation
concerning the taxation of certain publicly traded trusts and partnerships. The
legislation reflects proposals originally announced by the Minister on October 31,
2006. Under the proposed legislation, certain distributions will not be deductible
to publicly traded income trusts and partnerships with the exception of real estate
investments trusts and, as a result, these entities will in effect be taxed as corporations
on the amount of the non-deductible distributions. For entities in existence on
October 31, 2006, the proposed rules, if passed into law, would not apply until
2011.
16. Financial Instruments
The Trust's financial instruments presented on the balance sheet consist of cash,
accounts receivable, accounts payable and accrued liabilities, accrued distributions
to Unitholders, derivative assets, derivative liabilities and long-term debt. Other
than the long-term debt, the fair market value of these financial instruments approximate
their carrying value due to the short-term to maturity and the risk management contracts
are presented at fair value on the balance sheet. The fair value of long-term debt
approximates its carrying value in all material respects, because the cost of borrowing
approximates the market rate for similar borrowings.
Interest Rate Risk
The Trust is exposed to movements in interest rates. Long-term debt is comprised
of both variable rate bank facilities and fixed rate senior notes. The Trust has
fixed the interest rate on approximately 41% of its debt.
Credit Risk
Substantially all of the Trusts' accounts receivable relate to oil, land and natural
gas sales are exposed to typical industry credit risks. The carrying value of accounts
receivable reflects management's assessment of the associated risks. The Trust manages
its credit risk by only entering into sales contracts with investment grade entities
and reviewing its exposure to individual entities on a quarterly basis. The Trust
is also exposed to certain losses, in the event of non-performance by counterparties,
to derivative financial instruments. The credit risk is managed by the Trust by
selecting only financially sound counterparties.
Foreign Exchange Rate Risk
The Trust is exposed to fluctuations in the Canadian/U.S. dollar exchange rate on
the sale of commodities that are denominated in U. S. dollars or directly influenced
by U.S. dollar benchmark prices. In addition, the Trust's 4.19% U.K. Senior Notes
are denominated in U. S. dollars. The semi-annual interest payments and principal
payments associated with the Senior Notes can be impacted by movement in the Canadian/U.S.
dollar exchange rate. PrimeWest, through the use of a financial swap, has converted
the U.K. Senior Notes from pounds sterling to Canadian dollar debt.
Commodity Price Risk Management
PrimeWest generally sells its oil and natural gas under short-term market-based
contracts. Derivative financial instruments, options and swaps may be used to hedge
the impact of oil and natural gas price fluctuations.
A summary of these contracts in place at December 31, 2006 follows:
-------------------------------------------------------------------------
CRUDE OIL
-------------------------------------------------------------------------
Volume
Period (bbls/day) Type WTI Price (US$/bbl)
-------------------------------------------------------------------------
Jan - Mar 07 500 Costless Collar 50.00/76.00
Jan - Mar 07 500 Costless Collar 50.00/80.80
Jan - Mar 07 500 Costless Collar 55.00/91.65
Jan - Mar 07 500 Costless Collar 55.00/90.00
Jan - Mar 07 500 Costless Collar 60.00/97.20
Jan - Mar 07 500 Costless Collar 65.00/95.15
Jan - Mar 07 1400 Costless Collar 70.00/83.65
Jan - Mar 07 500 Costless Collar 65.00/90.25
Jan - Mar 07 500 Costless Collar 55.00/74.50
Jan - Mar 07 500 Costless Collar 60.00/65.95
Apr - Jun 07 500 Costless Collar 50.00/80.00
Apr - Jun 07 500 Costless Collar 55.00/91.30
Apr - Jun 07 500 Costless Collar 55.00/90.08
Apr - Jun 07 500 Costless Collar 60.00/95.40
Apr - Jun 07 500 Costless Collar 65.00/93.90
Apr - Jun 07 1300 Costless Collar 70.00/84.25
Apr - Jun 07 500 Costless Collar 55.00/75.00
Apr - Jun 07 500 Costless Collar 60.00/73.45
Apr - Jun 07 500 Costless Collar 60.00/70.25
Jul - Sep 07 500 Costless Collar 60.00/92.75
Jul - Sep 07 500 Swap 75.20
Jul - Sep 07 500 Costless Collar 65.00/92.60
Jul - Sep 07 900 Costless Collar 70.00/83.25
Jul - Sep 07 500 Costless Collar 55.00/77.80
Jul - Sep 07 500 Costless Collar 60.00/75.10
Jul - Sep 07 500 Costless Collar 60.00/73.20
Jul - Sep 07 500 Costless Collar 60.00/75.03
Oct - Dec 07 500 Costless Collar 60.00/90.25
Oct - Dec 07 500 Swap 74.58
Oct - Dec 07 500 Costless Collar 65.00/91.35
Oct - Dec 07 800 Costless Collar 70.00/82.10
Oct - Dec 07 500 Costless Collar 55.00/78.25
Oct - Dec 07 500 Costless Collar 60.00/76.60
Oct - Dec 07 500 Costless Collar 60.00/75.20
Oct - Dec 07 500 Costless Collar 60.00/76.60
Jan - Mar 08 500 Costless Collar 55.00/78.00
Jan - Mar 08 500 Costless Collar 60.00/77.10
Jan - Mar 08 500 Costless Collar 60.00/76.60
Apr - Jun 08 500 Costless Collar 60.00/77.35
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NATURAL GAS
-------------------------------------------------------------------------
Volume AECO Price
Period (mmf/day) Type (C$/mcf)
-------------------------------------------------------------------------
Jan - Mar 07 5.0 Costless Collar 7.91/12.87
Jan - Mar 07 5.0 Costless Collar 8.44/13.80
Jan - Mar 07 5.0 Costless Collar 8.44/15.88
Jan - Mar 07 5.0 Costless Collar 8.44/18.46
Jan - Mar 07 5.0 Costless Collar 8.44/21.10
Jan - Mar 07 5.0 Costless Collar 8.44/21.21
Jan - Mar 07 5.0 Costless Collar 8.44/12.68
Jan - Mar 07 5.0 Costless Collar 7.39/14.77
Jan - Mar 07 5.0 Costless Collar 5.28/10.87
Jan - Mar 07 5.0 Costless Collar 7.39/17.04
Jan - Mar 07 5.0 Costless Collar 8.44/15.03
Jan - Mar 07 5.0 Costless Collar 7.39/9.76
Jan - Mar 07 10.0 Costless Collar 7.39/9.56
Jan - Mar 07 5.0 Swap 7.20
Apr - Jun 07 5.0 3 Way 6.33/7.39/11.24
Apr - Jun 07 5.0 Costless Collar 6.33/10.64
Apr - Jun 07 5.0 Costless Collar 6.33/10.23
Apr - Jun 07 5.0 Costless Collar 5.28/9.34
Apr - Jun 07 5.0 Costless Collar 6.33/11.39
Apr - Jun 07 5.0 Costless Collar 6.33/11.66
Apr - Jun 07 10.0 Swap 7.71
Apr - Jun 07 10.0 Swap 7.74
Apr - Jun 07 5.0 Swap 8.17
Apr - Jun 07 5.0 Swap 7.10
Jul - Sep 07 5.0 Costless Collar 6.33/11.61
Jul - Sep 07 5.0 Costless Collar 6.33/10.87
Jul - Sep 07 5.0 Costless Collar 5.28/10.02
Jul - Sep 07 5.0 Costless Collar 6.33/12.05
Jul - Sep 07 5.0 Costless Collar 6.33/12.45
Jul - Sep 07 10.0 Swap 7.90
Jul - Sep 07 10.0 Swap 7.90
Jul - Sep 07 5.0 Swap 8.33
Jul - Sep 07 5.0 Costless Collar 6.33/8.81
Oct - Dec 07 5.0 Costless Collar 7.39/12.28
Oct - Dec 07 5.0 Costless Collar 5.28/12.66
Oct - Dec 07 5.0 Costless Collar 7.39/12.77
Oct - Dec 07 5.0 Costless Collar 7.39/13.40
Oct - Dec 07 10.0 Costless Collar 7.39/9.84
Oct - Dec 07 10.0 Costless Collar 7.39/10.29
Jan - Mar 08 5.0 Costless Collar 6.33/12.71
Jan - Mar 08 5.0 Costless Collar 8.44/15.67
Jan - Mar 08 10.0 Costless Collar 7.39/12.40
Jan - Mar 08 10.0 Costless Collar 7.39/11.61
Jan - Mar 08 5.0 Costless Collar 7.39/11.56
Apr - Jun 08 10.0 Costless Collar 7.39/8.97
Apr - Jun 08 5.0 Costless Collar 6.33/9.76
-------------------------------------------------------------------------
Foreign Exchange
In 2006 PrimeWest replaced a portion of its revolving credit facility with the U.K.
Secured Notes in the amount of Pound Sterling 63 million which bear interest at
5.76% per annum. Through a currency swap PrimeWest has fixed the aggregate principal
value and annual interest payments at $130.7 million and $3.9 million respectively.
---------------------------------------------------------------------------
Amount Pounds
Period Sterling (000's) Type Price
---------------------------------------------------------------------------
$2.0748 Cdn per Pounds
Jan - Jun 2016 Principal 63,000 Swap Sterling 1.00
Interest 34,474
---------------------------------------------------------------------------
Electrical Power
There were no electrical derivative contracts in place at December 31, 2006.
Impact on Financial Statements
At December 31, 2006, the derivative assets on the balance sheet reflect the net
unrealized gain position of $28.8 million (2005 - $11.5 million unrealized loss)
for the contracts outstanding at that date of which $18.1 million is attributable
to natural gas, $6.0 million is attributable to crude oil and $4.7 million is attributable
to foreign exchange. $23.5 million of the derivative contracts will be settled within
the next twelve months.
For the year ended December 31, 2006, the total unrealized gain on the statement
of income was $40.3 million comprised of $27.3 related to natural gas, $8.3 million
related to crude oil and $4.7 million related to foreign exchange.
The financial impact on the settlement of contracts during 2006 was a $25.5 million
gain consisting of $22.7 million related to natural gas, $0.9 million related to
crude oil, $1.7 million related to electricity and $0.2 million related to foreign
exchange.
17. Commitments and Contingencies
PrimeWest has lease commitments relating to office buildings. The estimated annual
minimum lease rental payments for the buildings, after deducting sublease income
will be $3.9 million in 2007, $3.8 million in 2008, $1.1 million in 2009, $4.8 million
in 2010, $4.8 million in 2011 and $66.1 million for the years 2012 - 2024.
As part of PrimeWest's internalization transaction, which closed on November 6,
2002, PrimeWest agreed to issue 377,360 Exchangeable Shares to certain Executive
Officers as a SERP. 94,340 Exchangeable Shares were issued on each of November 6,
2004, 2005 and 2006 and an additional 94,340 Exchangeable Shares will be issued
on November 6, 2007. For the twelve months ended December 31, 2006, $1.4 million
was recorded in general and administrative expense related to the SERP.
PrimeWest has various pipeline transportation commitments that run through 2010.
The estimated annual payments are $5.0 million in 2007, $0.6 million in 2008, $0.4
million in 2009, $0.2 million in 2010.
PrimeWest is engaged in a number of matters of litigation, none of which could reasonably
be expected to result in any material adverse consequence.
18. Segmented Information
The Trust's business activities are conducted through two business segments: Canadian
oil and natural gas production and United States oil and natural gas production.
Oil and natural gas production in Canada and the U.S. includes development and production
of crude oil and natural gas reserves. The following table includes financial results
from the U.S. operations for the period July - December 2006. Prior to July 2006
the Trust operated in only one segment.
Twelve Months ended Dec 31, 2006
---------------------------------------------------------------------------
Inter Segment
Canada U.S. Elimination Total
---------------------------------------------------------------------------
Revenues
Gross production revenue $ 669.0 $ 29.5 $ - $ 698.5
Realized gain in financial
derivatives 23.3 2.2 - 25.5
Royalties (138.6) (6.2) - (144.8)
Other income 4.5 - - 4.5
-----------------------------------------
558.2 25.5 - 583.7
Expenses
Operating 131.6 7.3 - 138.9
Transportation 7.5 - - 7.5
General and administrative 28.9 1.5 - 30.4
-----------------------------------------
168.0 8.8 - 176.8
-----------------------------------------
Earnings before interest, taxes,
DD&A and other non-cash items 390.2 16.7 - 406.9
Non-cash revenue
Unrealized (loss)/gain on
derivatives 40.3 - - 40.3
Other Expenses
DD&A 225.2 9.8 - 235.0
Interest 26.7 8.0 - 34.7
Foreign exchange (loss)/gain 13.5 - - 13.5
Accretion on asset retirement
obligation 3.5 0.1 - 3.6
Income and capital taxes 0.8 0.7 - 1.5
Future income tax
(recovery)/expense (48.3) (1.1) - (49.4)
-----------------------------------------
221.4 17.5 - 238.9
-----------------------------------------
Net income for the year $ 209.1 $ (0.8) $ - $ 208.3
-----------------------------------------
Selected Balance Sheet Items
Capital Assets
Property, plant and equipment
net $ 1,981.4 $ 351.5 $ - $ 2,332.9
Goodwill 68.5 - - 68.5
Capital Expenditures
Net corporate and capital
acquisitions 32.0 334.1 - 366.1
Development 255.6 5.4 - 261.0
Working Capital
Accounts receivable 100.6 7.8 (3.9) 104.5
Account payable and accrued
liabilities 131.0 16.3 (3.9) 143.4
Current portion of long-term debt 186.4 - - 186.4
Long-term debt $ 384.0 $ 235.4 $ - $ 619.4
---------------------------------------------------------------------------
19. Prior Years' Comparative Numbers
Certain prior years' comparative numbers have been restated to conform to the current
year's presentation. In the prior year realized gains/losses on derivatives related
to commodity price and electricity contracts were included in oil and gas revenue
and operating expenses, respectively. In 2006 they are included in realized gains/(losses)
on derivatives on the income statement.
20. Deficit
---------------------------------------------------------------------------
($ Millions) 2006 2005
---------------------------------------------------------------------------
Accumulated income $ 512.1 $ 303.8
Accumulated distributions paid or declared (1,550.1) (1,244.3)
Accumulated dividends (8.0) (8.0)
---------------------------------------------------------------------------
$ (1,046.0) $ (948.5)
---------------------------------------------------------------------------
PrimeWest is obligated by virtue of its Royalty and Trust Indenture to distribute
to Unitholders a significant portion of its funds flow from operations. Funds flow
from operations normally exceeds net income due to non-cash expenses such as DD&A,
derivatives, unrealized foreign exchange gains/(losses) and accretion. These non-cash
expenses result in a deficit despite PrimeWest distributing less than all of the
funds flow from operations.
21. Subsequent Event
On January 11, 2007, PrimeWest issued 6,420,000 Trust Units at $23.35 per Trust
Unit, for gross proceeds of $149.9 million and a total of $200 million aggregate
principal amount of Debentures. The Debentures bear a coupon rate of 6.5% per annum,
payable semi-annually, and are convertible at $26.25 per Trust Unit. The total net
proceeds from the offering of Trust Units and Convertible Debentures were approximately
$334 million.
TRADING PERFORMANCE
---------------------------------------------------------------------------
For the Quarter Ended Dec 31/06 Sep 30/06 Jun 30/06 Mar 31/06 Dec 31/05
---------------------------------------------------------------------------
TSX Trust Unit Prices
(C$ per Trust Unit)
High $ 29.21 $ 35.42 $ 35.30 $ 38.14 $ 37.68
Low $ 20.87 $ 27.33 $ 30.62 $ 29.82 $ 30.55
Close $ 21.50 $ 27.35 $ 33.50 $ 32.98 $ 35.90
Average daily traded
volume 391,293 225,732 258,294 249,527 199,849
---------------------------------------------------------------------------
---------------------------------------------------------------------------
For the Quarter Ended Dec 31/06 Sep 30/06 Jun 30/06 Mar 31/06 Dec 31/05
---------------------------------------------------------------------------
NYSE Trust Unit Prices
(US$ per Trust Unit)
High $ 25.94 $ 31.29 $ 30.91 $ 32.90 $ 32.57
Low $ 18.03 $ 24.45 $ 27.76 $ 25.25 $ 25.71
Close $ 18.47 $ 24.64 $ 29.98 $ 28.39 $ 30.92
---------------------------------------------------------------------------
Average daily traded
volume 796,697 441,508 438,995 463,411 480,603
---------------------------------------------------------------------------
FIVE-YEAR FINANCIAL SUMMARY
---------------------------------------------------------------------------
($ Millions, except per
BOE and per Trust Unit
amounts) 2006 2005 2004 2003 2002
---------------------------------------------------------------------------
Funds flow from
operations $ 364.1 $ 405.4 $ 262.2 $ 214.4 $ 167.0
Per Trust Unit 4.37 4.91 4.15 4.62 4.84
Per BOE 25.37 27.53 20.14 17.63 15.16
Net revenues 624.0 605.2 403.6 338.7 270.6
Per Trust Unit 7.41 7.33 6.39 7.30 7.85
Per BOE 43.48 41.09 31.00 27.85 24.55
Operating expenses 138.9 117.8 89.7 79.9 60.8
Per Trust Unit 1.65 1.43 1.42 1.72 1.76
Per BOE 9.68 8.00 6.89 6.57 5.52
Operating margin after
hedging impact 437.4 464.6 305.6 250.5 203.5
Per Trust Unit 5.19 5.63 4.84 5.41 5.90
Per BOE 30.48 31.54 23.47 20.61 18.46
Cash G&A 24.6 22.9 19.0 14.5 11.3
Per Trust Unit 0.29 0.28 0.30 0.31 0.33
Per BOE 1.71 1.56 1.46 1.20 1.02
Interest expense 34.7 28.3 20.6 15.1 10.8
Per Trust Unit 0.37 0.34 0.33 0.32 0.32
Per BOE 2.41 1.92 1.58 1.24 0.98
Development capital
expenditures 261.0 185.6 125.1 104.5 64.2
Acquisitions, net of
dispositions 366.1 (17.9) 707.9 228.6 56.5
Working capital
(deficit)/surplus (1) (201.4) 30.5 104.3 (5.8) (0.7)
Total assets 2,588.5 2,131.9 2,240.9 1,690.5 1,511.5
Net asset value 2,074.8 2,565.1 1,541.2 692.4 727.9
Per Trust Unit 24.18 30.64 19.15 13.74 18.52
Total capitalization
(including debt) 2,626.7 3,208.4 2,429.7 1,636.6 1,072.5
---------------------------------------------------------------------------
Debt Analysis
Long-term debt, including
working capital 820.8 323.7 552.0 255.9 225.7
Debt to annual cash flow
ratio 2.3 0.8 1.70 1.18 1.32
Debt to equity ratio 37.5 19.2 31.6 25.1 26.6
Interest coverage ratio 11.9 15.6 14.2 15.9 16.9
Average cost of debt 5.7% 5.2% 4.8% 4.7% 4.6%
Net debt per Trust Unit 9.74 3.97 7.77 5.07 5.75
---------------------------------------------------------------------------
Tax Pools (Consolidated
Canadian)
Canadian Oil and Gas
Property Expense (COGPE) 770.0 825.0 879.0 426.0 425.0
Canadian Exploration
Expense (CEE) 13.8 9.8 79.8 61.5 -
Canadian Development
Expense (CDE) 306.7 156.0 109.5 60.9 41.2
Capital Cost Allowance
(CCA) 435.2 325.1 281.8 126.0 108.0
Losses Available For
Carry Forward 4.0 3.6 3.6 - 11.8
Unit issue expenses 17.9 24.9 37.5 17.3 12.5
---------------------------------------------------------------------------
Tax Pools U.S. 286.7 - - - -
---------------------------------------------------------------------------
(1) Excludes derivative liabilities and assets and future income tax
assets and liabilities.
FIVE-YEAR OPERATING SUMMARY
---------------------------------------------------------------------------
2006 2005 2004 2003 2002
---------------------------------------------------------------------------
Average Daily Production
Natural gas (mmcf/day) 166.0 178.2 145.1 134.1 113.5
Crude oil (bbls/day) 7,816 6,861 8,282 8,116 9,239
Natural gas liquids
(bbls/day) 3,835 3,797 3,107 2,855 2,030
---------------------------------------------------------------------------
Total (BOE/day) 39,321 40,351 35,578 33,316 30,189
---------------------------------------------------------------------------
Average Selling Prices
(C$)
Natural gas ($/mcf) $ 7.09 $ 8.75 $ 6.70 $ 6.51 $ 3.81
Crude oil ($/bbl) 62.42 58.48 44.46 36.55 34.25
Natural gas liquids
($/bbl) 59.09 55.92 43.69 35.34 26.56
---------------------------------------------------------------------------
Total (BOE/day) $ 48.09 $ 53.82 $ 41.51 $ 38.14 $ 26.61
---------------------------------------------------------------------------
Benchmark Prices
Monthly AECO Spot
(C$/mcf) $ 6.99 $ 8.48 $ 6.79 $ 6.70 $ 4.07
West Texas Intermediate
(US$/bbl) $ 66.22 $ 56.56 $ 41.40 $ 31.04 $ 26.08
---------------------------------------------------------------------------
Operating Margin ($/BOE)
Revenues $ 48.99 $ 54.71 $ 42.29 $ 38.70 $ 27.24
Realized hedging
gains/(losses) 1.78 (2.95) (2.10) (2.47) 2.43
Royalties (10.09) (11.73) (9.20) (8.38) (5.13)
Transportation (0.52) (0.49) (0.63) (0.68) (0.57)
Operating expenses (9.68) (8.00) (6.89) (6.56) (5.51)
---------------------------------------------------------------------------
Operating margin ($/BOE) $ 30.48 $ 31.54 $ 23.47 $ 20.61 18.46
---------------------------------------------------------------------------
Reserves Summary (1)
Crude oil (mmbbls) 49.2 23.6 23.9 22.9 24.5
Natural gas liquids
(mmbbls) 17.9 18.1 18.3 11.9 10.2
Natural gas (bcf) 752.5 677.3 677.9 432.2 418.5
---------------------------------------------------------------------------
Total BOE (mmBOE) 192.5 154.6 155.2 106.8 104.4
---------------------------------------------------------------------------
Net Asset Value
($ millions, except per
Trust Unit)
Reserves (10% discount)
(3) $2,695.4 $2,684.0 $1,714.4 $ 904.6 $ 923.0
Market value of Viking
Energy Royalty Trust
Units - - 91.0 - -
Hedging Mark-to-Market 28.8 (11.5) 0.1 (0.5) (13.6)
Unproved lands and
reclamation fund 132.5 160.5 114.2 44.2 44.2
Long-term debt and
working capital (4) (781.9) (267.9) (378.5) (255.9) (225.7)
---------------------------------------------------------------------------
Total net asset value $2,074.8 $2,565.1 $1,541.2 $ 692.4 $ 727.9
Total net asset value
per Trust Unit- Diluted $ 24.18 $ 30.64 $ 19.15 $ 13.74 $ 18.52
---------------------------------------------------------------------------
Reserve Life Index
(years) 13.4 11.0 10.3 9.8 9.5
---------------------------------------------------------------------------
(1) Company Interest Proved plus Probable used for 2005, 2004 and 2003, all
prior years use established.
(2) Company interest Proved plus Probable reserves discounted at 10%.
(3) Excludes Debentures.
FIVE-YEAR TRADING, PERFORMANCE AND DISTRIBUTION SUMMARY
2006
Full
Q1 Q2 Q3 Q4 Year
---------------------------------------------------------------------------
Units Issued and Outstanding
Period end (000's) 80,627 81,439 82,719 83,257 83,257
Exchangeable Shares Issued and
Outstanding
Period end (000's) 1,172 1,136 1,124 1,162 1,162
Converted to Trust Units 682 683 694 741 741
Exchange ratio at period end 0.58188 0.60132 0.61771 0.63765 0.63765
TSX Unit Price (C$)
High 38.14 35.30 35.42 29.21 38.14
Low 29.82 30.62 27.33 20.87 20.87
Close 32.98 33.50 27.35 21.50 21.50
Average daily traded volume 249,527 258,294 225,732 391,293 280,868
Market capitalization at
end of period ($ Millions) 3,046 3,166 3,054 2,623 2,623
NYSE Unit Price (US$)
High 32.90 30.91 31.29 25.94 32.90
Low 25.25 27.76 24.45 18.03 18.03
Close 28.39 29.98 24.64 18.47 18.47
Average daily traded volume 441,508 438,995 463,411 796,677 535,439
Distribution Summary
($ Millions, except per
Trust Unit amounts)
Cash distributed to Unitholders 86.8 82.8 74.0 62.3 305.8
Per Trust Unit 1.08 1.02 0.90 0.75 3.75
Percentage paid out 84% 93% 77% 74% 84%
Cumulative cash
distributions 1,331.1 1,413.9 1,487.9 1,550.1 1,550.1
Per Trust Unit 48.28 49.30 50.20 50.95 50.95
---------------------------------------------------------------------------
2005 2004 2003 2002
---------------------------------------------------------------------------
Units Issued and Outstanding
Period end (000's) 79,666 69,886 48,752 37,005
Exchangeable Shares Issued and
Outstanding
Period end (000's) 1,219 1,294 3,041 5,179
Converted to Trust Units 688 652 1,347 1,940
Exchange ratio at period end 0.56399 0.50408 0.44302 0.37454
TSX Unit Price (C$)
High 37.68 28.35 28.15 29.56
Low 26.15 22.18 23.40 23.60
Close 35.90 26.62 27.56 25.40
Average daily traded volume 213,656 233,579 192,678 123,455
Market capitalization at end of
period ($ Millions) 2,885 1,878 1,381 989
NYSE Unit Price (US$)
High 32.57 22.98 21.48 16.69
Low 21.30 16.00 15.97 15.62
Close 30.92 22.18 21.27 16.16
Average daily traded volume 458,853 402,694 169,269 39,276
Distribution Summary ($ Millions,
except per Trust Unit amounts)
Cash distributed to Unitholders 276.6 196.1 192.6 158.0
Per Trust Unit 3.66 3.30 4.32 4.80
Percentage paid out 68% 75% 90% 95%
Cumulative cash distributions 1,244.3 967.7 771.5 578.9
Per Trust Unit 47.20 43.54 40.24 35.92
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Funds 2006 2005 2004 2003 2002
Paid In: C$ US$ C$ US$ C$ US$ C$ US$ C$ US$
---------------------------------------------------------------------------
Q1 1.08 0.94 0.90 0.74 0.82 0.62 1.20 0.81 1.20 0.75
Q2 1.02 0.92 0.90 0.72 0.75 0.55 1.20 0.87 1.20 0.77
Q3 0.90 0.75 0.90 0.76 0.83 0.64 0.96 0.70 1.20 0.77
Q4 0.75 0.66 0.96 0.82 0.90 0.74 0.96 0.73 1.20 0.76
---------------------------------------------------------------------------
Total 3.75 3.27 3.66 3.04 3.30 2.55 4.32 3.12 4.80 3.05
---------------------------------------------------------------------------
% Tax
Deferred 25% 17.52% 25% 18.75% 45% 55% 42% 100% 45% 100%
Exchange
Rate
(US$/C$)0.872 0.829 0.769 0.715 0.637
---------------------------------------------------------------------------
INCOME TAX CONSIDERATIONS
This commentary regarding income taxes is of a general nature only and is not intended
to be legal or tax advice applicable to a specific Unitholder. Unitholders and prospective
investors are, therefore, encouraged to consult a tax advisor with regard to their
specific circumstances.
Canadian Unitholders
PrimeWest is regarded as a mutual fund trust for purposes of the Canadian Income
Tax Act. Each year, an income tax return is filed by the Trust with the taxable
income allocated to, and taxable in the hands of Unitholders. Distributions paid
by the Trust have two components: (1) a tax-deferred return of capital (i.e. a repayment
of a portion of a Unitholders' investment) and (2) a taxable return on capital (i.e.
other income).
Each year, the return on capital or taxable portion of the distribution is reported
on the Trust's T3 return. It is then allocated to each Unitholder who received distributions
in the taxation year on the T3 supplementary forms, which are mailed in later February
or early March of the following calendar year. Registered Unitholders receive a
T3 from the Trust's transfer agent, Computershare Trust Company of Canada, while
Unitholders who hold their units beneficially will receive a T3 from their bank
or brokerage firm. The T3 form will indicate the taxable portion, or other income,
as it is regarded under Canadian tax law in box 26 and the return of capital portion
in box 42. The other income component is taxed on the same basis as interest income.
The tax-deferred return of capital portion of the distribution should be treated
as an adjustment to the cost base (ACB) of the Units. On disposition, the cost base
should be reduced by the accumulated value of returned capital, resulting in a capital
gain or loss for tax purposes.
For 2006, 25% of the distributions paid to Canadian residents were deemed a tax-deferred
return of capital, and 75% was deemed taxable as other income. For the tax year
2007, PrimeWest's distributions payable to Canadian residents are estimated to be
80% taxable and 20% a tax-deferred return of capital.
United States and Other Non-Resident Unitholders
Investors who do not qualify as residents of Canada for income tax purposes should
seek advice from a qualified tax advisor in their country of residence regarding
the tax treatment of the distributions paid by PrimeWest. Monthly distributions
payable to nonresidents of Canada are normally subject to a withholding tax of 25%
as prescribed by the Canadian Income Tax Act. However, the level of withholding
tax may be reduced in accordance with reciprocal tax treaties.
In the case of the Canada-United States Tax Convention, U.S. residents are subject
to a 15% withholding tax on the distributions paid by PrimeWest. For distributions
paid during tax years 2004 and prior, the 15% withholding tax is refundable for
that portion of the distributions deemed to be a tax-deferred return of capital.
U.S. residents may apply to the Canada Revenue Agency (CRA) of the Government of
Canada for this refund no later than two years after the calendar year in which
the distributions were paid. Application for refund may be made by filing CRA Form
NR7-R "Application for Refund of Non-Resident Tax", which can be obtained by contacting
the International Tax Services Office of the CRA at 1-800-267-5177 or on the internet
at
www.cra.gc.ca. U.S. investors
are cautioned that the administrative protocol required to apply for the refund
is burdensome, and they will require the assistance of their broker or tax advisor.
Alternatively, U.S. Unitholders may elect to claim a portion of the Canadian tax
withheld on distributions paid during 2006 as a deduction against income, or, subject
to certain restrictions, as a credit against their U.S. tax liability. U.S. Unitholders
wishing to claim a foreign tax credit must complete IRS Form 1116, "Foreign Tax
Credit" as an attachment to the Form 1040.
Due to differences in the income tax code of the United States, certain deductions
not available in Canada are available in the United States and could result in differences
in tax treatment of the distributions for U.S. Unitholders compared to those in
Canada. For Unitholders resident in the United States, the taxability of distributions
is derived using U.S. tax rules, which permit the deduction of Crown royalties and
accounting-based depletion. In the case of a U.S. Unitholder, the taxable portion
of the monthly distribution is determined based upon current and accumulated earnings
in accordance with the IRS tax code. The currently taxable portion is regarded as
a foreign issuer "qualified dividend" under the terms of the Jobs and Growth Reconciliation
Act of 2003 (P.L. 108-27, 117 Stat.752) for tax reporting purposes and registered
U.S. Unitholders should receive a CRA Form NR-4 from the Trust's transfer agent,
Computershare Trust Company of Canada. U.S. Unitholders who hold their Units beneficially
should receive an IRS Form 1099-DIV or similar document from their bank or brokerage
firm. As a result of the foregoing rules, in the case of a U.S. resident, 82.48%
of the distributions paid by PrimeWest during 2006 should be treated as a "qualified
dividend" with the remaining 17.52% treated as a tax-deferred return of capital.
The tax-deferred return of capital portion of the distribution should be treated
as an adjustment to the cost base (ACB) of the Units. The original cost of the Units
should be reduced by this accumulated amount when computing gains or losses at the
time of disposition, at which time this should be reported as a capital gain or
loss.
PREMIUM DISTRIBUTION, DISTRIBUTION REINVESTMENT AND OPTIONAL TRUST UNIT PURCHASE
PLAN
PrimeWest offers a number of attractive and economical options for Unitholders to
maximize their investment in PrimeWest, including a Premium Distribution (PREP),
Conventional Distribution Reinvestment (DRIP) and Optional Trust Unit Purchase Plan
(OTUPP). Investors are able to participate in all of these plans without paying
fees, including brokerage commissions.
Canadian Unitholders
The Premium Distribution (PREP), Distribution Reinvestment (DRIP) and Optional Trust
Unit Purchase Plans (OTUPP) provide eligible holders of Trust Units that are resident
in Canada the opportunity to either receive a premium cash payment in lieu of the
cash distribution declared payable by PrimeWest or accumulate additional Trust Units
at a 5% discount to the weighted average market price. Participants that are resident
in Canada may also purchase additional Trust Units at the same 5% discount by investing
additional sums within the limits and subject to the terms of the Plan.
The PREP enables Canadian Unitholders to receive a 2% cash premium on the monthly
distribution they receive. The more conventional DRIP allows eligible Canadian Unitholders
to reinvest distribution payments into Trust Units, acquired at a 5% discount to
the volume weighted average market price.
Additional Trust Units may be purchased by eligible Canadian Unitholders through
the OTUPP in minimum amounts of $100 per remittance up to a maximum amount of $100,000
per calendar year, at a 5% discount to the volume weighted average market price.
The number of Trust Units available under the OTUPP is limited by the TSX to a maximum
of 2% of the total Trust Units outstanding at the end of the previous fiscal year.
Most larger banks, trust companies and brokerage firms will allow investors to participate
in these programs, but many of the smaller firms do not. Please contact the bank,
trust company or brokerage firm that holds your account to determine if they permit
participation in these Plans. If you are unable to participate as a beneficial holder,
you will need to hold the Units directly as a registered Unitholder or transfer
the Trust Units to a financial institution that permits participation.
United States Unitholders
The DRIP plan is now available to Unitholders resident in the United States and
provides the opportunity to accumulate additional Trust Units at a 5% discount to
the Average Market Price. Unitholders that are resident in the United States are
not eligible to receive the premium cash payment under the PREP or to make optional
cash payments under the OTUPP to purchase additional Trust Units pursuant to the
Plan.
Please contact the brokerage firm that holds your account to determine if they permit
participation in the DRIP. If you are unable to participate as a beneficial holder,
you will need to hold the Trust Units directly as a registered Unitholder or transfer
the Units to a financial institution that permits participation.
Additional Information
We invite you to participate in these programs by completing the enrolment form
on the PrimeWest website at
www.primewestenergy.com. If you hold your Trust Units with a bank or brokerage
firm, you will need to inform the firm directly of your interest in enrolling in
the program. Additional information regarding the PREP, DRIP, and OTUPP can be obtained
by contacting the Computershare Trust Company of Canada toll-free at 1-800-564-6253,
or the Investor Relations group at PrimeWest toll-free at 1-877-968-7878, or via
e-mail at
investor@primewestenergy.com.
DEFINITIONS
AECO
Refers to a pricing point for gas produced in Western Canada located at a gas storage
facility adjacent to the TransCanada Pipelines' mainline near the Alberta-Saskatchewan
border.
Cash Distribution Date
The date Distributable Income is paid to Unitholders, currently being on or about
the 15th of each month, or the earlier business day if applicable, following any
record date.
Circular
Refers to the Trust's Management Proxy Circular, dated March 15, 2007.
Company Interest
Refers to, in relation to PrimeWest's interest in production or Reserves, its working
interest (operating or non operating) share before deduction of royalties and including
royalty interests of PrimeWest and the Trust.
Credit Facility
Refers, collectively, to certain credit facilities provided by a syndicate of Canadian
chartered banks and term debt provided by certain institutional investors, together
offering a maximum aggregate borrowing capability of $750 million.
EDGAR
Means the Electronic Data Gathering, Analysis and Retrieval System on which submissions
by companies and others required by law to file forms with the U.S. Securities and
Exchange Commission are filed and accessible at
www.sec.gov.
Forecast Prices and Costs
Refers to future prices and costs that are generally accepted as being a reasonable
outlook for the future; or fixed or presently determinable future prices or costs
to which PrimeWest is legally bound by a contractual or other obligation to supply
a physical product.
GAAP
Means Generally Accepted Accounting Principles.
General and Administrative Costs
The amount in aggregate representing all expenditures and costs incurred by or in
respect of PrimeWest in the management and administration of PrimeWest.
GLJ
Means GLJ Petroleum Consultants, Ltd.
GLJ Report
Means the reserve report dated January 24, 2007, prepared by GLJ, evaluating the
light and medium oil, heavy oil and associated and non-associated gas reserves attributable
to properties owned by the Trust as at December 31, 2006.
Gross
Refers to the Trust's "company gross reserves", which are PrimeWest's working interest
(operated or non operated) share before deduction of royalties and without including
any royalty interests of PrimeWest or the Trust; or in relation to wells, the total
number of wells in which PrimeWest has an interest; or in relation to properties,
the total area of properties in which PrimeWest has an interest.
Net
Refers to PrimeWest's interest in production or reserves, PrimeWest's working interest
(operated or non operated) share after deduction of royalty obligations, plus the
royalty interests of PrimeWest and the Trust in production or reserves; or in relation
to PrimeWest's interest in wells, the number of wells obtained by aggregating PrimeWest's
working interest in each of its Gross wells; or in relation to PrimeWest's interest
in a property, the total area in which PrimeWest has an interest multiplied by its
working interest.
NI 51-101
Means National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities
of the Canadian Securities Commissions.
Probable Reserves
Those additional reserves less certain to be recovered than Proved reserves. It
is equally likely that the actual remaining quantities recovered will be greater
or less than the sum of the estimated Proved plus Probable reserves. In addition,
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.
Production
Refers to recovering, gathering, treating, field or plant processing and field storage
of oil and natural gas.
Production Costs
Costs incurred to operate and maintain wells and related equipment and facilities,
including applicable operating costs of support equipment and facilities and other
cost of operating and maintaining those wells and related equipment and facilities.
Lifting costs become part of the cost of oil and natural gas produced.
Proved Reserves
Reserves that can be estimated with a high degree of certainty to be recoverable.
The reporting company must believe that there is at least a 90% probability that
the actual remaining quantities recovered will equal or exceed those estimated Proved
reserves.
Record Date
The date by which a Unitholder must officially own the Trust Units in order to be
entitled to receive a distribution.
Reserve Life Index
Is calculated by dividing the quantity of reserves by the total production of oil,
natural gas and natural gas liquids during the year.
SEDAR
Refers to the System for Electronic Document Analysis and Retrieval established
by the Canadian Securities Administrators as the system used for electronically
filing most securities related information with the Canadian securities regulatory
authorities and is accessible at
www.sedar.com.
Standard and Poors (S&P)
Refers to Standard and Poors, a division of the McGraw-Hill Companies, Inc.
Trust Units
Refers to the units of the Trust, each unit representing an equal undivided beneficial
interest in the Trust.
Trustee
Refers to Computershare Trust Company of Canada, or its successor, as trustee of
the Trust.
Undeveloped Reserves
Refers to those reserves expected to be recovered from known accumulations where
a significant expenditure is required to render them capable of Production. They
must fully meet the requirements of the Reserves classification (Proved, Probable
or Possible) to which they are assigned.
Unproved Properties
A property or part of a property to which no reserves have been specifically attributed.
Well Abandonment Costs
The costs of abandoning a well (net of salvage value) and of disconnecting the well
from the surface gathering system. They do not include costs of abandoning the gathering
system or reclaiming the wellsite.
West Texas Intermediate
A high-quality grade of crude oil produced in West Texas whose price is most commonly
used as a benchmark for crude oil pricing internationally.
Refer to PrimeWest's Renewal Annual Information Form dated March 15, 2007, for an
explanation of additional defined terms used in this MD&A.
CORPORATE INFORMATION EXCHANGES
CORPORATE OFFICES New York Stock Exchange:
Trust Units: PWI
5100, 150 - 6th Avenue S.W.
Calgary, Alberta Canada T2P 3Y7 Toronto Stock Exchange:
Telephone: (Main) 403-234-6600 Trust Units: PWI.UN
(Toll-Free) 1-877-968-7878 Exchangeable Shares: PWX
Email: investor@primewestenergy.com Series I Debentures: PWI.DB.A
Website:
www.primewestenergy.com Series II Debentures: PWI.DB.B
Series III Debentures: PWI.DB.C
BOARD OF DIRECTORS
REGISTRAR AND TRANSFER AGENT
Harold P. Milavsky, (1,2) Chair
Barry E. Emes, (1,2) Computershare Trust Company
Harold N. Kvisle, (3,4) of Canada
Kent J. MacIntyre, (3,4) Toll-Free: 1-800-564-6253
Michael W. O'Brien, (1,2)
James W. Patek, (3,4)
W. Glen Russell, (3,4) AUDITOR
Peter Valentine, (1)
PricewaterhouseCoopers LLP
(1) Audit & Finance Committee Calgary, Alberta
(2) Corporate Governance & EH&S Committee
(3) Compensation Committee
(4) Operations & Reserves Committee INDEPENDENT ENGINEERING
EVALUATORS
OFFICERS GLJ Petroleum Consultants Ltd.
Calgary, Alberta
Donald A. Garner
President and Chief Executive Officer
LEGAL COUNSEL
Timothy S. Granger
Chief Operating Officer Stikeman Elliott LLP
Calgary, Alberta
Dennis G. Feuchuk
Vice-President Finance and
Chief Financial Officer
Ronald J. Ambrozy
Vice-President Business Development
Brian J. Lynam
Vice-President, Operations
Gordon D. Haun
Vice-President Legal and General Counsel
FOR FURTHER INFORMATION PLEASE CONTACT:
PrimeWest Energy Trust
George Kesteven
Manager, Investor Relations
(403) 699-7367 or Toll Free: 1-877-968-7878