PrimeWest Energy Trust Announces First Quarter 2006 Results
MAY 3, 2006 - 18:24 ET
CALGARY, ALBERTA--(CCNMatthews - May 3, 2006) - PRIMEWEST ENERGY TRUST (TSX:PWI.UN)
(TSX:PWI.DB.A) (TSX:PWI.DB.B) (TSX:PWX) (NYSE:PWI) (PRIMEWEST OR THE TRUST) TODAY
ANNOUNCES INTERIM OPERATING AND FINANCIAL RESULTS FOR THE QUARTER ENDED MARCH 31,
2006. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT ARE IN CANADIAN
DOLLARS.
First Quarter 2006 Highlights:
- Distributions in the first quarter were $1.08 per Trust Unit representing a payout
ratio of approximately 84% of operating cash flow compared to fourth quarter 2005
distributions of $0.96 per Trust Unit, representing a payout ratio of approximately
57% of operating cash flow.
- First quarter cash flow from operations was $103.2 million ($1.28 per Trust Unit)
compared to $132.5 million ($1.66 per Trust Unit) in the previous quarter and $79.7
million ($1.12 per Trust Unit) in the first quarter 2005.
- First quarter 2006 production averaged 38,062 barrels of oil equivalent per day
(BOE per day), compared to the fourth quarter 2005 rate of 40,269 BOE per day. The
decrease in volumes is due to regulatory changes impacting the Nisku waterflood
project at Crossfield (250 BOE per day) and the re-instatement of maximum rate limitations
on oil production at Cecil and Grand Forks (500 BOE per day), third party unscheduled
plant outages at Princess (250 BOE per day), operational issues at Caroline and
Crossfield, natural production declines and scheduling changes affecting the tie-in
of the new production from wells drilled in late 2005. PrimeWest expects full year
2006 production volumes to average between 38,000 - 39,000 BOE per day.
- Development capital expenditures in the first quarter were $81.3 million, with
drilling completion and tie-in expenditures of $69.1 million, resulting in 52 gross
wells (29.7 net) being drilled with a success rate of 100%. PrimeWest has begun
to develop capital opportunities previously identified in its capital development
portfolio of approximately $800 million.
- Net debt to annualized first quarter 2006 cash flow was approximately 0.9 times
compared to net debt to annualized fourth quarter 2005 cash flow of 0.8 times at
December 31, 2005. PrimeWest has approximately $360 million of borrowing capacity
available on its existing credit facilities at March 31, 2006.
MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF MAY 3, 2006
The following is management's discussion and analysis (MD&A) of PrimeWest's operating
and financial results for the quarter ended March 31, 2006, compared with the preceding
quarter and the corresponding period in the prior year as well as information and
opinions concerning the Trust's future outlook based on currently available information.
Forward-Looking Information
This MD&A contains forward-looking or outlook information with respect to PrimeWest.
Certain statements contained in this MD&A, and any documents incorporated by reference
into this MD&A, constitute forward-looking statements. The use of any of the words
"anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project",
"should", "believe", "outlook" and similar expressions are intended to identify
forward-looking statements. In addition, statements relating to "reserves" or "resources"
are deemed to be forward-looking statements, as they involve implied assessment,
based on certain estimates and assumptions, that the resources and reserves described
can be profitably produced in the future. These statements involve known and unknown
risks, uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in our forward-looking statements.
We believe the expectations reflected in those forward-looking statements are reasonable.
However, we cannot assure you that these expectations will prove to be correct.
You should not unduly rely on forward-looking statements included in, or incorporated
by reference into this MD&A. These statements speak only as of the date of this
MD&A or as of the date specified in any documents incorporated by reference into
this MD&A, as the case may be.
In particular, this MD&A, and any documents incorporated by reference, contain forward-looking
statements pertaining to the following:
- the quantity and recoverability of our reserves;
- the timing and amount of future production;
- prices for oil, natural gas and natural gas liquids produced;
- operating and other costs;
- business strategies and plans of management;
- supply and demand for oil and natural gas;
- expectations regarding our ability to raise capital and to add to our reserves
through acquisitions and exploration and development;
- our treatment under governmental regulatory regimes;
- the focus of capital expenditures on development activity rather than exploration;
- the sale, farming in, farming out or development of certain exploration properties
using third-party resources;
- the objective to achieve a predictable level of monthly cash distributions;
- the intention of maintaining a payout ratio of distributions to cash flow from
operations within any range;
- the use of development activity and acquisitions to replace and add to reserves;
- the impact of changes in oil and natural gas prices on cash flow after hedging;
- drilling plans;
- the existence, operations and strategy of the commodity price risk management
program;
- the approximate and maximum amount of forward sales and hedging to be employed;
- our acquisition strategy, the criteria to be considered in connection therewith
and the benefits to be derived therefrom;
- the impact of the Canadian federal and provincial governmental regulation on us
relative to other oil and natural gas issuers of similar size;
- the goal to sustain or grow production and reserves through prudent management
and acquisitions;
- the emergence of accretive growth opportunities; and
- our ability to benefit from the combination of growth opportunities and the ability
to grow through the capital markets.
With respect to forward-looking statements contained in this MD&A, including any
documents incorporated herein by reference, we have made assumptions regarding,
among other things:
- future oil and natural gas prices and differentials between light, medium and
heavy oil prices;
- the cost of expanding our property holdings;
- our ability to obtain equipment in a timely manner to carry out development activities;
- our ability to market our oil and natural gas successfully to current and new
customers;
- the impact of increasing competition;
- our ability to obtain financing on acceptable terms; and
- our ability to add production and reserves through our development and exploitation
activities.
Our actual results could differ materially from those anticipated in these forward-looking
statements as a result of the risk factors set forth below and incorporated by reference
into this MD&A:
- volatility in market prices for oil and natural gas;
- the impact of weather conditions on seasonal demand;
- risks inherent in our oil and natural gas operations;
- uncertainties associated with estimating reserves;
- competition for, among other things: capital, acquisitions of reserves, undeveloped
lands and skilled personnel;
- incorrect assessments of the value of acquisitions;
- geological, technical, drilling and processing problems;
- general economic conditions in Canada, the United States and globally;
- industry conditions, including fluctuations in the price of oil and natural gas;
- royalties payable in respect of our oil and natural gas production;
- government regulation of the oil and natural gas industry, including environmental
regulation;
- fluctuation in foreign exchange or interest rates;
- unanticipated operating events that can reduce production or cause production
to be shut-in or delayed;
- failure to obtain industry partner and other third-party consents and approvals,
when required;
- stock market volatility and market valuations;
- OPEC's ability to control production and balance global supply and demand of crude
oil at desired price levels;
- political uncertainty, including the risks of hostilities in the petroleum producing
regions of the world;
- the need to obtain required approvals from regulatory authorities; and
- the other factors discussed under "Risk Factors" contained in this MD&A.
These factors should not be construed as exhaustive. The forward-looking statements
contained in this MD&A and any documents incorporated by reference herein are expressly
qualified by this cautionary statement. We undertake no obligation to publicly update
or revise any forward-looking statements.
PrimeWest does not endorse any analyst or consultant sourced material contained
herein.
All figures reported in Canadian dollars unless otherwise stated.
Production figures stated in this MD&A 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 March 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, interim filings or other reports (each as defined in National
Instrument 52-109 of the Canadian Securities Administrators) filed or submitted
by it under provincial securities legislation is recorded, processed, summarized
and reported within the time periods specified in the provincial securities legislation
and to ensure that information required to be disclosed by PrimeWest in its annual
filings, interim filings or other reports filed or submitted under provincial securities
legislation is accumulated and communicated to PrimeWest's management, including
its chief executive officer and chief financial officer, as appropriate to allow
timely decisions regarding required disclosure; and
- in its annual filings, interim filings or other reports with the United States
Securities and Exchange Commission (SEC) in the United States (US) under the Securities
Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported,
within the time periods specified in the Commission's rules and forms, and to ensure
that information required to be disclosed by PrimeWest in the reports that it files
under the Exchange Act is accumulated and communicated to PrimeWest's management,
including its principal executive officer and principal financial officer, as appropriate
to allow timely decisions regarding required disclosure.
The evaluation took into consideration PrimeWest's Communications and Disclosure
Policy and the functioning of its executive officers, board of directors and board
committees. In addition, the evaluation covered PrimeWest's processes, systems and
capabilities relating to regulatory filings, public disclosures and the identification
and communication of material information.
Changes to Internal Controls Over Financial Reporting
There were no changes to PrimeWest's internal control over financial reporting since
December 31, 2005 that have materially affected, or are reasonably likely to materially
affect PrimeWest's internal control over financial reporting.
Non-GAAP Measures
This MD&A contains the following measurements that are not defined by Canadian Generally
Accepted Accounting Principles (GAAP):
- Cash flow from operations on a total and per Trust Unit basis;
- Distributions per Trust Unit; and
- Net debt per Trust Unit.
These measurements do not have any standardized meaning prescribed by GAAP and are,
therefore, unlikely to be comparable to similar measures presented by other entities.
Cash flow from operations is calculated from the Trust's cash flow statement as
cash flow from operating activities before changes in working capital. Cash flow
from operations per Trust Unit on a basic basis is calculated by dividing cash flow
by the weighted average number of Trust Units outstanding plus Trust Units issuable
upon the exchange of the outstanding Exchangeable Shares of PrimeWest Energy Inc.
(Exchangeable Shares). Cash flow from operations per Trust Unit on a diluted basis
is calculated using cash flow and adding back the interest expense on the Convertible
Unsecured Subordinated Debentures (Debentures), divided by the diluted weighted
average number of Trust Units outstanding in the period. The diluted weighted average
number of Trust Units outstanding consists of the weighted average Trust Units plus
Trust Units issuable upon the exchange of outstanding Exchangeable Shares and includes
the Trust Units issuable pursuant to the conversion of the Debentures, and Trust
Units issuable pursuant to PrimeWest's Long Term Incentive Plan (LTIP). Cash flow
from operations is a key performance indicator of PrimeWest's ability to generate
cash and finance operations and pay monthly distributions.
Distributions per Trust Unit disclose the cash distributions accrued in 2006 based
on the number of Trust Units outstanding on the Record Date.
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 includes Trust Units issuable upon the exchange of outstanding Exchangeable
Shares and Trust Units issuable pursuant to the LTIP at March 31, 2006.
Business Strategy
PrimeWest is a conventional oil and natural gas royalty trust actively managed to
generate monthly cash distributions for Unitholders. The Trust's operations are
focused in Canada, with its assets concentrated in the Western Canada Sedimentary
Basin. PrimeWest is one of North America's largest natural gas-weighted energy trusts.
Maximizing total return to Unitholders, in the form of cash distributions and appreciation
in unit price, is PrimeWest's overriding objective. Our strategies for asset management
and growth, financial management and corporate governance are outlined in this MD&A,
along with a discussion of our performance in the first quarter of 2006 and our
goals for 2006 and beyond.
We believe that PrimeWest can maximize total return to Unitholders by continuing
to develop our core properties, making opportunistic acquisitions that emphasize
value creation, exercising disciplined financial management which broadens access
to capital while minimizing risk to Unitholders, and complying with strong corporate
governance principles to protect the interests of all stakeholders.
Asset Management and Growth
PrimeWest has a strategy to focus expansion efforts on existing Canadian core areas
and pursue depletion optimization strategies within those core areas to maximize
asset value. We make every effort to obtain operatorship of our asset base and maintain
high working interests in core areas. We currently maintain operatorship of 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, US-dollar-denominated Senior Secured Notes (Secured Notes) and the Debentures.
Our diversified debt instruments help to reduce our reliance on the bank syndicate.
PrimeWest's commodity hedging 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 August
2003, PrimeWest has followed a strategy of maintaining a distribution payout ratio
within 70-90% of cash flow, calculated on an annual basis, recognizing that during
periods of volatile commodity prices the payout ratio may temporarily 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.
The first quarter 2006 payout ratio was approximately 84% of operating cash flow.
Retained cash flow was utilized to fund a part of the Trust's capital spending program
and to repay debt. PrimeWest's net debt to annualized first quarter cash flow ratio
was 0.9 times at March 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 in the future. 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 available.
Corporate Governance
PrimeWest remains committed to high standards of corporate governance and upholds
the rules of the governing regulatory bodies under which it operates. Full disclosure
of our compliance with existing corporate governance rules and regulations is available
on our website at
www.primewestenergy.com.
PrimeWest actively monitors the corporate governance and disclosure environment
to ensure compliance with current and future requirements.
Our high standards of corporate governance are not limited to the boardroom. At
the field level, PrimeWest proactively manages environmental, health and safety
issues. We place a great deal of importance on community involvement and maintaining
good relationships with landowners.
Financial Highlights
Three Months Ended
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$ Millions, except per BOE (1) Mar 31, Dec 31, Mar 31,
and per Trust Unit amounts 2006 2005 2005
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Gross revenue (net of
transportation expense) 189.2 230.6 153.3
per BOE 55.25 62.97 41.94
Cash flow from operations 103.2 132.5 79.7
per BOE 30.14 35.76 21.79
per Trust Unit - basic (2) 1.28 1.66 1.12
per Trust Unit - diluted (3) 1.24 1.60 1.04
Royalty expense 44.7 55.9 36.0
per BOE 13.04 15.08 9.85
Operating expense 32.7 32.9 24.4
per BOE 9.54 8.88 6.68
Cash general and administrative
expense 5.3 6.9 5.5
per BOE 1.55 1.88 1.51
Non-cash general and administrative
expense 1.4 1.2 1.3
per BOE 0.42 0.33 0.36
Interest expense (4) 4.6 5.5 9.1
per BOE 1.34 1.48 2.49
Distributions to Unitholders 86.8 76.2 63.8
per Trust Unit (5) 1.08 0.96 0.90
Net debt (6) 364.5 323.7 516.1
per Trust Unit (7) 4.42 3.97 7.01
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(1) All calculations required to convert natural gas to a crude oil
equivalent (BOE) have been made using a ratio of 6,000 cubic feet
of natural gas to one barrel of crude oil. BOE's may be
misleading, particularly if used in isolation. The BOE conversion
ratio is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.
(2) The basic per Trust Unit calculation includes the weighted
average Trust Units and Trust Units issuable upon exchange of the
Exchangeable Shares of PrimeWest Energy Inc.
(Exchangeable Shares).
(3) The diluted per Trust Unit calculation includes the weighted
average Trust Units outstanding, Trust Units issuable upon
exchange of the outstanding Exchangeable Shares, the deemed
conversion of the Debentures and Trust Units issuable 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 Date.
(6) Net debt is long-term debt including Debentures adjusted for
working capital, excluding current financial derivative and
future income tax assets and liabilities.
(7) The net debt per Trust Unit calculation includes outstanding
Trust Units, Trust Units issuable upon exchange of the
outstanding Exchangeable Shares and Trust Units issuable
pursuant to the LTIP at the end of the period.
Operating Highlights
Three Months Ended
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Mar 31, Dec 31, Mar 31,
Daily Production Volumes 2006 2005 2005
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Natural gas (mmcf/day) 166.0 176.8 180.6
Crude oil (bbls/day) 6,867 6,752 6,948
Natural gas liquids (bbls/day) 3,525 4,046 3,563
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Total (BOE per day) 38,062 40,269 40,616
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Average Realized Sales Prices
Three Months Ended
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Mar 31, Dec 31, Mar 31,
2006 2005 2005
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Natural gas ($/Mcf) (1)(2) 9.13 10.98 6.79
Without hedging 9.09 11.99 6.79
Crude oil ($/bbl)(1) 54.51 51.89 42.18
Without hedging 57.09 59.78 50.90
Natural gas liquids ($/bbl) 59.34 59.07 50.82
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Total Oil Equivalent ($/BOE)(1) 55.17 62.87 41.88
Without hedging 55.44 68.59 43.35
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Realized hedging loss included in
prices above ($/BOE) 0.27 5.72 1.47
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(1) Includes hedging gains and losses.
(2) Excludes sulphur.
Cash Flow Reconciliation
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($ Millions)
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Fourth quarter 2005 cash flow from operations $ 132.5
Volumes (19.3)
Commodity prices (44.8)
Net hedging change from prior quarter 20.3
Operating expenses 0.2
Royalties 10.8
General and administrative expenses 1.6
Other 1.9
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First quarter 2006 cash flow from operations $ 103.2
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The above table includes non-GAAP measurements. (Refer to discussion
on Non-GAAP Measures on Page 4)
A key performance driver for the Trust is cash flow from operations,
which directly affects PrimeWest's ability to pay monthly
distributions. Cash flow is generated through the production and sale
of crude oil, natural gas and natural gas liquids, and is dependent
on production levels, commodity prices, operating expenses, interest
expense, general and administrative expense (G&A), hedging gains or
losses, royalties and currency exchange rates. Some of these factors
such as commodity prices, the currency exchange rate and royalties
are uncontrollable from PrimeWest's perspective. Other factors that
are to a certain extent controllable by PrimeWest are production
levels and operating expenses, as well as interest and G&A expenses.
Quarterly Performance - Selective Measures
The table below highlights PrimeWest's performance for the first
quarter ended March 31, 2006 and the preceding seven quarters through
2005 and 2004.
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2006 2005
($ millions, except per
Trust Unit Amounts) Q1 Q4 Q3 Q2 Q1
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Net Revenues $170.0 $236.4 $101.5 $155.3 $111.2
Net (Loss)/Income 68.9 101.5 27.3 54.7 24.0
Cash Flow 103.2 132.5 106.4 95.5 79.7
Cash Flow Per Unit - basic 1.28 1.66 1.36 1.29 1.12
Cash Flow Per Unit - diluted 1.24 1.60 1.31 1.21 1.04
Net (Loss)/Income Per Unit
- basic 0.85 1.27 0.35 0.74 0.34
Net (Loss)/Income Per Unit
- diluted 0.83 1.23 0.35 0.72 0.34
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2004
($ millions, except per
Trust Unit Amounts) Q4 Q3 Q2
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Net Revenues $158.2 $ 84.5 $ 84.9
Net (Loss)/Income 42.2 27.1 16.5
Cash Flow 83.3 66.8 58.2
Cash Flow Per Unit - basic 1.17 1.09 1.05
Cash Flow Per Unit - diluted 1.07 1.08 1.05
Net (Loss)/Income Per Unit -
basic 0.59 0.44 0.30
Net (Loss)/Income Per Unit -
diluted 0.58 0.44 0.30
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Net revenues are impacted primarily by commodity prices, production
volumes, royalties and unrealized gains or losses on derivatives.
Net income and net income per Trust Unit are secondary measures for a
royalty trust because they include both cash and non-cash items. The
non-cash items, which include depletion, depreciation and
amortization (DD&A), non-cash G&A, future income taxes, unrealized
foreign exchange gains or losses and unrealized gains or losses on
derivatives will not affect PrimeWest's ability to pay a monthly
distribution.
Capital Expenditures
Three Months Ended
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Mar 31, Dec 31, Mar 31,
($ millions) 2006 2005 2005
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Land and lease acquisitions $ 3.4 $ 1.9 $ 6.7
Geological and geophysical 1.5 0.9 1.6
Drilling and completions 53.5 25.6 35.4
Investment in facilities
Equipping and tie-in 15.6 6.2 5.8
Gas gathering and compression 1.2 1.6 7.2
Production facilities 4.7 4.2 2.7
Capitalized G&A 1.4 0.8 0.6
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Development capital 81.3 41.2 60.0
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Corporate/property acquisitions 0.2 0.5 0.5
Dispositions (3.1) (16.9) (3.3)
Leasehold improvements,
furniture and equipment 1.3 0.8 1.1
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Net capital expenditures $ 79.7 $ 25.6 $ 58.3
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During the first quarter of 2006, PrimeWest's development capital expenditures totaled
$81.3 million, compared to $41.2 million invested in the fourth quarter of 2005
and $60.0 million in the first quarter of 2005. Of the $81.3 million total, $69.1
million or 85% was invested in drilling, completions and tie-ins, which contribute
to new reserve additions and help offset natural production decline.
Dispositions in the fourth quarter of 2005 of $16.9 million consisted mainly of
proprietary seismic data.
Through acquisitions as well as development drilling, workovers and re-completion
activities, PrimeWest strives to offset natural production declines and add to reserves
in order to sustain cash flows. Capital resources are allocated to projects on the
basis of anticipated rate of return. At PrimeWest, every capital project is measured
against stringent economic evaluation criteria prior to approval. These criteria
include expected return, risks and further development opportunities.
Development Capital Update
During the first three months of 2006, PrimeWest invested $81.3 million on development
opportunities, drilling 52 gross wells (29.7 net) with a success rate of 100%. A
large part of the drilling activity in the quarter was focused on winter-access
areas including Valhalla, Laprise and Columbia where results from the drilling program
were as expected or better. PrimeWest's four key development plays are Conventional
Development, Tight Gas, Southeast Alberta Shallow Gas and Coalbed Methane (CBM).
PrimeWest's development capital expenditures for 2006 are expected to be $275 million,
allocated $100 to $110 million to Conventional Development, $70 to $80 million to
Tight Gas development, $30 to $35 million to Southeast Alberta Shallow Gas development
and $5 to $10 million to CBM. PrimeWest has begun to develop opportunities previously
identified in its capital development portfolio of approximately $800 million.
Conventional Development
PrimeWest continues to invest in development opportunities at our conventional plays,
which include properties at Lone Pine Creek/Crossfield, Wilson Creek, Boundary,
Laprise, Grand Forks and Valhalla. Development expenditures during the first quarter
totaled $45.6 million, comprised of $29.6 million for drilling and completions,
$2.7 million for land and seismic and $13.3 million for equipping, tie-in and facilities.
A total of 34 gross wells have been drilled during the quarter.
The following provides a description of the Wilson Creek and Lone Pine Creek/Crossfield
areas, which are major properties in our conventional development play.
Wilson Creek
In the Wilson Creek area, PrimeWest drilled 4 operated wells in the first three
months of 2006, and participated in 7 non-operated wells targeted at various formations
including Edmonton, Belly River, Glauconitic, Mannville, and Rock Creek. Development
capital expenditures at Wilson Creek were $10.0 million, comprised of $7.6 million
for drilling and completions, $0.9 million for land and seismic and $1.5 million
for equipping, tie-in and facilities.
Lone Pine Creek/Crossfield Area
The 2004 Calpine acquisition increased PrimeWest's land base at Crossfield making
it the Trust's second largest area. Development capital expenditures at Crossfield
of $5.8 million were comprised of $3.9 million for drilling and completions, $0.1
million for land and seismic and $1.8 million for equipping, tie-in and facilities.
Tight Gas Plays
PrimeWest's Tight Gas plays are located in west central Alberta, and target the
deeper Viking, Mannville and Cardium sandstones. Tight Gas wells are characterized
by high initial production rates that settle into a low decline stabilized rate
and production of high heat content, liquids-rich gas.
PrimeWest continued its development program in its Tight Gas plays in the first
quarter. Capital expenditures for the three months ended March 31, 2006 included
$19.7 million for drilling and completions, $1.5 million for land and seismic and
$7.6 million for equipping, tie-in and facilities. Seven gross wells were drilled
during the quarter. Previous expenditures on land and seismic have increased PrimeWest's
inventory of drilling opportunities. The following provides an overview of activity
in the Tight Gas region.
Caroline Area
Development expenditures at Caroline during the first quarter 2006 of $11.3 million
were comprised of $7.9 million for drilling and completion, $2.0 million for equipping,
tie-in and facilities and $1.4 million for land and seismic. During the quarter,
3 gross wells were drilled at Caroline.
Columbia Area
Development expenditures at Columbia of $16.7 million were comprised of $11.1 million
for drilling and completions, $5.4 million for equipping, tie-in and facilities
and $0.2 million for land and seismic. During the quarter 3 gross wells have been
drilled at Columbia.
Southeast Alberta Shallow Gas
PrimeWest's Southeast Alberta Shallow Gas Play consists of shallow gas pools in
the Medicine Hat and Milk River formations plus deeper, more prolific pools in Glauconitic
zones. Lying at typical depths of 600 to 1,000 metres, the shallow zones are amenable
to a low-risk, low-cost "manufacturing" development approach. The main properties
that comprise the Shallow Gas Play are Medicine Hat, Princess/Dinosaur, Bindloss
and Brant Farrow. This area has evolved through a combination of development activities
and acquisitions. During the first quarter of 2006, development expenditures were
$7.0 million, with $4.6 million invested in drilling and completions, $1.2 million
in equipping, tie-ins and facilities, and $1.2 million in land and seismic. Eleven
gross wells have been drilled year to date in this play.
The following provides a description of the Brant Farrow area, which is a major
property in the Southeast Alberta Shallow Gas play that has evolved to include development
of the seismically identified Glauconitic channels.
Brant Farrow Area
Development expenditures at Brant Farrow during the first quarter were $6.2 million,
with $4.3 million invested in drilling and completions, $0.8 million in equipping,
tie-ins and facilities and $1.1 million in land and seismic. The drilling program
is on schedule, with 11 gross operated wells drilled to date in 2006.
Coalbed Methane
CBM is an emerging resource play in Western Canada. PrimeWest has approximately
124,000 net acres of land on the developing Horseshoe Canyon CBM trend. PrimeWest
is involved in preliminary assessments of the area. Acreage is concentrated within
three large operated properties with gas plants and extensive field infrastructure.
Daily Production Volumes
Three Months Ended
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Mar 31, Dec 31, Mar 31,
2006 2005 2005
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Natural gas (mmcf/day) 166.0 176.8 180.6
Crude oil (bbls/day) 6,867 6,752 6,948
Natural gas liquids (bbls/day) 3,525 4,046 3,563
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Total (BOE per day) 38,062 40,269 40,616
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PrimeWest's production volumes averaged 38,062 BOE per day in the first quarter
of 2006 compared to 40,269 BOE per day in the fourth quarter of 2005. The decrease
in volumes is due to regulatory changes impacting the Nisku waterflood project at
Crossfield (250 BOE per day) and the re-instatement of maximum rate limitations
on oil production at Cecil and Grand Forks (500 BOE per day), third party unscheduled
plant outages at Princess (250 BOE per day) as well as operational issues at Caroline
and Crossfield, natural production declines and scheduling changes affecting the
tie-in of new production from wells drilled in late 2005. At Caroline, a compressor
overhaul planned for later in 2006 was accelerated into the first quarter, and at
Crossfield, a long lead time submersible pump replacement required the shut-in of
a key Leduc oil producer during most of the quarter (250 BOE per day). The pump
was replaced and the well placed back on production prior to the end of the quarter.
The decrease in production reflects the production profile of wells drilled in our
Tight Gas Plays at Caroline and Columbia, where the wells were brought on production
at their typical high production rates in the fourth quarter of 2005 and have declined
to lower more stabilized rates in the first quarter of 2006.
At the end of the first quarter of 2006, approximately 2,800 BOE per day of production
volumes remained behind pipe, awaiting tie-in. This is an increase of 600 BOE per
day from the production awaiting tie-in at the end of 2005, reflecting our drilling
successes, in particular at Valhalla and Wilson Creek.
Production Outlook
Prime West expects full year 2006 production volumes to average between 38,000 -
39,000 BOE per day.
Commodity Prices
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
Benchmark Prices 2006 2005 2005
---------------------------------------------------------------------
Natural gas
NYMEX (US$/mcf) 9.08 12.85 6.32
AECO (Cdn$/mcf) 9.27 11.69 6.69
Crude oil WTI (US$/bbl ) 63.48 60.02 49.85
---------------------------------------------------------------------
---------------------------------------------------------------------
Benchmark Commodity Prices
The following table sets forth benchmark historical and estimated
future commodity prices.
---------------------------------------------------------------------
Past Four Quarters Next Four Quarters
(Actual) (Forward Markets)(1)
---------------------------------------------------------------------
Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
2005 2005 2005 2006 2006 2006 2006 2007
---------------------------------------------------------------------
Natural gas AECO
(Cdn$/mcf) 7.38 8.17 11.69 9.27 6.79 7.32 8.78 10.22
Crude oil WTI
(US$/bbl) 53.17 63.19 60.02 63.48 68.00 69.35 69.69 69.84
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) As at March 31, 2006
Average Realized Sales Prices
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
2006 2005 2005
---------------------------------------------------------------------
Natural gas ($/Mcf) (1)(2) 9.13 10.98 6.79
Without hedging 9.09 11.99 6.79
Crude oil ($/bbl)(1) 54.51 51.89 42.18
Without hedging 57.09 59.78 50.90
Natural gas liquids ($/bbl) 59.34 59.07 50.82
---------------------------------------------------------------------
Total Oil Equivalent ($/BOE)(1) 55.17 62.87 41.88
Without hedging 55.44 68.59 43.35
---------------------------------------------------------------------
Realized hedging loss included in
prices above ($/BOE) 0.27 5.72 1.47
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes hedging losses.
(2) Excludes sulphur.
Realized natural gas prices were 24% lower in the first quarter of 2006 compared
to the previous quarter, excluding the effect of hedging. Natural gas prices declined
after December 31, 2005 due to lower heating demand as North America experienced
one of the warmest winters on record. Realized natural gas prices were 34% higher
during the first quarter of 2006 compared to the first quarter of 2005.
Realized crude oil prices were 4% lower in the first quarter of 2006 compared to
the previous quarter, excluding the effect of hedging despite the 6% increase in
benchmark WTI prices during the same period. The realized prices for crude oil were
negatively affected by a wider price differential between the price of light and
heavy crude oil, as well as a greater discount on Canadian light crude versus the
benchmark WTI crude. During the first quarter of 2006, higher than normal levels
of refinery turn-around on the U.S. Gulf Coast resulted in a drop in refinery demand
for Canadian light and heavy crude. Realized oil prices were 5% higher during the
first quarter of 2006 compared to the first quarter of 2005.
Sales Revenue
Three Months Ended
---------------------------------------------------------------------
Mar 31, % of Dec 31 % of Mar 31, % of
Revenue ($ millions)(1)(2) 2006 total 2005 total 2005 total
---------------------------------------------------------------------
Natural gas 136.5 72 178.7 77 110.4 72
Crude oil 33.7 18 32.2 14 26.4 17
Natural gas liquids 18.8 10 22.0 9 16.3 11
---------------------------------------------------------------------
Total 189.0 100 232.9 100 153.1 100
---------------------------------------------------------------------
Hedging losses included
above (0.9) (21.2) (5.4)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Excludes sulphur.
(2) Net of transportation expenses.
First quarter 2006 revenues were 19% lower than the previous quarter mainly due
to lower realized natural gas prices and lower natural gas production volumes offset
by a reduction in the realized hedging loss.
First quarter 2006 revenues were 23% higher than the same period in 2005, due to
higher commodity prices offset by decreased production volumes.
PrimeWest derives approximately 72% of its revenues from natural gas; therefore,
the Trust has greater sensitivity to changes in natural gas prices than crude oil
prices.
Financial Derivatives
As part of our financial management strategy, PrimeWest uses a consistent commodity
hedging approach. The purpose of the hedging program is to reduce volatility in
cash flows, protect acquisition economics and to stabilize cash flow against the
unpredictable commodity price environment. The hedging policy reflects a willingness
to risk forfeiting a portion of the pricing upside in return for protection against
a significant downturn in prices.
The following table sets forth the approximate percentage of future anticipated
production volumes hedged at March 31, 2006, net of anticipated royalties, reflecting
full production declines with no offsetting additions.
---------------------------------------------------------------------
Q2 Q3 Q4 Q1 Q2 Q3
Production Volumes Hedged(%) 2006 2006 2006 2007 2007 2007
---------------------------------------------------------------------
Crude Oil 55 50 52 27 19 0
Natural Gas 47 49 54 28 5 0
---------------------------------------------------------------------
---------------------------------------------------------------------
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 gas price
fluctuations.
A listing of hedging contracts in place at March 31, 2006 follows:
Crude Oil
---------------------------------------------------------------------
Period Volume (bbls/d) Type WTI Price (US$/bbl)
---------------------------------------------------------------------
Apr - Jun 06 500 Costless Collar 40.00/71.25
Apr - Jun 06 500 Costless Collar 50.00/70.00
Apr - Jun 06 500 Costless Collar 50.00/75.70
Apr - Jun 06 1000 Costless Collar 50.00/82.75
Apr - Jun 06 500 Costless Collar 50.00/75.05
Apr - Jun 06 500 Costless Collar 50.00/80.35
Jul - Sep 06 500 Costless Collar 50.00/75.30
Jul - Sep 06 1000 Costless Collar 50.00/82.05
Jul - Sep 06 500 Costless Collar 50.00/76.05
Jul - Sep 06 500 Costless Collar 50.00/80.50
Jul - Sep 06 500 Costless Collar 55.00/91.00
Oct - Dec 06 500 Costless Collar 50.00/75.03
Oct - Dec 06 1000 Costless Collar 50.00/81.50
Oct - Dec 06 500 Costless Collar 50.00/75.00
Oct - Dec 06 500 Costless Collar 50.00/81.00
Oct - Dec 06 500 Costless Collar 55.00/91.50
Jan - Mar 07 500 Costless Collar 50.00/76.00
Jan - Mar 07 500 Costless Collar 50.00/80.80
Jan - Mar 07 500 Costless Collar 55.00/91.65
Apr - Jun 07 500 Costless Collar 50.00/80.00
Apr - Jun 07 500 Costless Collar 55.00/91.30
---------------------------------------------------------------------
---------------------------------------------------------------------
Natural Gas
---------------------------------------------------------------------
AECO Price
Period Volume (mmcf/d) Type (Cdn$/mcf)
---------------------------------------------------------------------
Apr - Jun 06 5.0 3 Way 4.22/5.28/8.12
Apr - Jun 06 5.0 Costless Collar 5.28/9.50
Apr - Jun 06 5.0 Costless Collar 6.33/8.91
Apr - Jun 06 10.0 Costless Collar 6.86/10.55
Apr - Jun 06 5.0 Costless Collar 6.86/10.63
Apr - Jun 06 5.0 Costless Collar 7.39/13.72
Apr - Jun 06 5.0 Costless Collar 8.44/12.98
Apr - Jun 06 5.0 Costless Collar 8.44/15.30
Apr - Jun 06 10.0 Costless Collar 8.44/16.62
Jul - Sep 06 5.0 3 Way 4.22/5.28/9.34
Jul - Sep 06 5.0 Costless Collar 5.28/10.55
Jul - Sep 06 10.0 Costless Collar 6.86/10.55
Jul - Sep 06 5.0 Costless Collar 6.86/10.68
Jul - Sep 06 5.0 Costless Collar 7.39/13.56
Jul - Sep 06 5.0 Costless Collar 8.44/13.98
Jul - Sep 06 5.0 Costless Collar 8.44/15.72
Jul - Sep 06 5.0 Costless Collar 8.44/15.83
Jul - Sep 06 10.0 Costless Collar 8.44/16.30
Oct - Dec 06 5.0 3 Way 5.28/6.33/13.03
Oct - Dec 06 5.0 Costless Collar 6.86/11.92
Oct - Dec 06 10.0 Costless Collar 6.86/12.66
Oct - Dec 06 5.0 3 Way 5.28/6.33/14.19
Oct - Dec 06 5.0 Costless Collar 7.39/15.83
Oct - Dec 06 5.0 Costless Collar 8.44/11.87
Oct - Dec 06 5.0 Costless Collar 8.44/15.83
Oct - Dec 06 5.0 Costless Collar 8.44/17.94
Oct - Dec 06 5.0 Costless Collar 8.44/18.99
Oct - Dec 06 10.0 Costless Collar 8.44/19.25
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
Apr - Jun 07 5.0 3 Way 6.33/7.39/11.24
---------------------------------------------------------------------
---------------------------------------------------------------------
A 3-way option is similar to a traditional collar, except that PrimeWest has resold
the put at a lower price. Utilizing the first 3-way natural gas contract above as
an example, PrimeWest has sold a call at $8.12, purchased a put at $5.28, and resold
the put at $4.22. Should the market price drop below $5.28, PrimeWest will receive
$5.28 until the price is less than $4.22, at which time PrimeWest will then receive
market price plus $1.06. However, should market prices rise above $8.12, PrimeWest
will receive a maximum of $8.12. Should the market price remain between $5.28 and
$8.12, PrimeWest will receive the market price.
Electrical Power
---------------------------------------------------------------------
Power
Period Amount (MW) Type Price ($/MW-hr)
---------------------------------------------------------------------
Apr - Jun 06 5.0 Swap 58.00
Apr - Jun 06 5.0 Swap 54.00
Jul - Sep 06 5.0 Swap 69.00
Jul - Sep 06 5.0 Swap 62.75
Oct - Dec 06 5.0 Swap 70.50
Oct - Dec 06 5.0 Swap 66.00
---------------------------------------------------------------------
---------------------------------------------------------------------
PrimeWest's derivatives are marked-to-market at the end of each reporting period
with the resulting gain or loss reflected in earnings for that period.
The first quarter 2006 income statement includes an unrealized gain of $22.2 million
on derivatives resulting from the change in the Mark-to-Market valuation of the
derivative financial instruments during the period. The gain was comprised of a
$0.5 million gain for crude oil hedges and a $21.7 million gain for natural gas
hedges. The unrealized gain is a point-in-time measurement of PrimeWest's hedging
position at the end of the first quarter. The magnitude of the gain or loss will
continue to fluctuate with changes in commodity prices.
The mark-to-market valuation of the electrical power swaps is zero at March 31,
2006.
For the three month period ended March 31, 2006 the cash impact of contract settlements
was a $0.9 million loss comprised of a $1.6 million loss in crude oil and a $0.7
million gain in natural gas.
Royalties
PrimeWest pays royalties to the owners of mineral rights with whom PrimeWest holds
leases. PrimeWest has mineral leases with the Crown (Provincial and Federal Governments),
freeholders (individuals or other companies) and other operators.
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions, except per BOE) 2006 2005 2005
---------------------------------------------------------------------
Royalty expense $ 44.7 $ 55.9 $ 36.0
Per BOE $ 13.04 $ 15.08 $ 9.85
---------------------------------------------------------------------
Royalties as a % of sales revenues
With hedge loss 23.7% 23.9% 23.5%
Excluding hedge loss 23.5% 21.9% 22.7%
---------------------------------------------------------------------
---------------------------------------------------------------------
Royalty expenses as a percentage of sales excluding the impact of hedges have increased
when compared to the previous quarter and the prior year.
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, future changes
to commodity prices will result in changes in royalty rates and expenses.
Operating Expenses
Three Months Ended
---------------------------------------------------------------------
($ millions, Mar 31, Dec 31, Mar 31,
except per BOE) 2006 2005 2005
---------------------------------------------------------------------
Operating expense $ 32.7 $ 32.9 $ 24.4
Per BOE $ 9.54 $ 8.88 $ 6.68
---------------------------------------------------------------------
First quarter 2006 operating expense remained at approximately the same level as
the fourth quarter of 2005. On a per BOE basis, operating costs were 7% higher than
the previous quarter due in part to the decrease in production volumes. Included
in the first quarter were non-recurring costs for compressor failures at Barrhead,
compressor overhauls and maintenance projects previously scheduled for later in
2006 at Caroline and Thorsby ($0.9 million) and unexpected expenses associated with
non-operated properties, including equalizations at Wilson Creek. Operating expenses
also included $0.4 million for 2005 field labour bonuses, as well as the full costs
of operating the bio-desulphurization train at the Valhalla gas plant, which was
scheduled to shut down early in the first quarter, but was deferred to the second
quarter of 2006. The bio-desulphurization plant was de-commissioned in April and
the Valhalla gas is being redirected through the existing amine unit with added
off-load capability to re-direct gas to a third party processor in the area. These
changes should result in higher plant reliability and lower operating costs for
the remainder of the year.
Operating expenses for the three months ended March 31, 2006 were $8.3 million higher
than the same period in the prior year due to the foregoing factors as well as inflationary
pressures on the price of goods and services and the increased well count from our
successful 2005 drilling program.
Operating Expenses Outlook
Given the record high industry activity levels currently being experienced, PrimeWest
expects the price of oilfield goods and services to continue to increase, putting
upward pressure on operating expenses throughout the year. Despite cost efficiencies
being realized from our maintenance programs and chemical and power consumption
reduction initiatives, the large number of variables involved in predicting operating
expenses in this environment make forecasting difficult. However, PrimeWest anticipates
its full year operating expense could reach as high as $9.00 per BOE given the current
operating environment. PrimeWest continues to evaluate and implement operating cost
reduction projects in various areas. Cost reduction initiatives planned for the
remainder of 2006 include the recently completed shutdown of the bio-desulphurization
plant at Valhalla, consolidation of facilities at Thorsby and Grand Forks, and the
installation of production surveillance programs at select key fields.
Operating Margin
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ per BOE) 2006 2005 2005
---------------------------------------------------------------------
Sales price and
other revenue(1) $ 55.68 $ 63.19 $ 41.94
Royalties (13.04) (15.08) (9.85)
Operating expenses (9.54) (8.88) (6.68)
---------------------------------------------------------------------
Operating margin $ 33.10 $ $39.23 $ 25.41
---------------------------------------------------------------------
(1) Includes hedging and sulphur.
Operating margin per BOE decreased in the first quarter of 2006 compared to the
previous quarter mainly due to lower realized natural gas prices, higher operating
expenses and higher royalties. Operating margin is an important measure of our business
because it gives an indication of the amount of cash flow PrimeWest realizes per
BOE that is produced, before head office expenses and financing charges.
The first quarter 2006 operating margin was higher than the same period in 2005
due to higher realized sales prices offset by increases in operating costs and royalties.
General & Administrative Expense
Three Months Ended
---------------------------------------------------------------------
($ millions, Mar 31, Dec 31, Mar 31,
except per BOE) 2006 2005 2005
---------------------------------------------------------------------
Cash G&A expense $ 5.3 $ 6.9 $ 5.5
Per BOE 1.55 1.88 1.51
Non-cash G&A expense 1.4 1.2 1.3
Per BOE 0.42 0.33 0.36
---------------------------------------------------------------------
Cash G&A expense in the first quarter of 2006 decreased 23% on a gross and 18% on
a per BOE basis from the previous quarter due to lower short term incentive bonus
accruals and increases to G&A recoveries offset by annual report costs, stock exchange
listing fees and increases to information technology expenses.
First quarter 2006 cash G&A expenses remained relatively flat when compared to the
first quarter of 2005. Increases to labour costs were offset by increases to G&A
recoveries resulting from increases to capital expenditures and operating expenses.
Included in non-cash G&A expense is $1.0 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 non-cash G&A expense is $0.4
million related to the Special Employee Retention Plan (SERP). See note 18 to the
Consolidated Financial Statements in the 2005 Annual Report.
Interest Expense
Three Months Ended
---------------------------------------------------------------------
($ millions,
except per Trust Mar 31, Dec 31, Mar 31,
Unit amounts) 2006 2005 2005
---------------------------------------------------------------------
Interest expense $ 4.6 $ 5.5 $ 9.1
Period end net debt level $ 364.5 $ 323.7 $ 516.1
Debt per Trust Unit $ 4.42 $ 3.97 $ 7.01
---------------------------------------------------------------------
Average cost of debt 5.0% 4.8% 5.3%
---------------------------------------------------------------------
Interest expense, representing interest on bank debt, the Secured Notes and the
Debentures decreased in the first quarter of 2006 compared to the fourth quarter
of 2005, due to a lower average net debt balance.
The average cost of debt was higher in the first quarter of 2006 compared to the
previous quarter due to the increase in interest rates related to the bank credit
facility.
Foreign Exchange
The foreign exchange loss of $0.7 million for the three months ended March 31, 2006
resulted from the translation of the U.S. dollar denominated Secured Notes and related
interest payable into Canadian dollars.
Depletion, Depreciation and Amortization
Three Months Ended
---------------------------------------------------------------------
($ millions, Mar 31, Dec 31, Mar 31,
except per BOE) 2006 2005 2005
---------------------------------------------------------------------
Depletion, depreciation
and amortization $ 53.9 $ 60.4 $ 57.3
Per BOE $ 15.75 $ 16.31 15.67
---------------------------------------------------------------------
The DD&A rate for the three months ended March 31, 2006 is lower than the previous
quarter due to the impact of reserve additions resulting from our successful drilling
program during the first quarter of 2006.
Site Reclamation and Restoration Reserve
Since the inception of the Trust, PrimeWest has maintained a site reclamation fund
to pay for future costs related to well abandonment and site clean up. The fund
is used to pay for such costs as they are incurred. The 2006 contribution rate for
the fund is unchanged from 2005 at $0.50 per BOE. As at March 31, 2006 the site
reclamation fund contained a balance of $9.1 million.
The abandonment and reclamation costs incurred in the first quarter 2006 were $1.9
million, compared to $0.9 million for the same period in 2005, and $3.9 million
for the previous quarter.
Income and Capital Taxes
Three Months Ended
---------------------------------------------------------------------
($ millions, Mar 31, Dec 31, Mar 31,
except per BOE) 2006 2005 2005
---------------------------------------------------------------------
Income and capital taxes $ 0.6 $ 1.2 $ 0.7
Future income tax expense
recovery (0.7) 24.1 (14.5)
---------------------------------------------------------------------
Total (0.1) 25.3 (13.8)
---------------------------------------------------------------------
Cash taxes paid $ 0.7 $ 0.7 $ 0.6
---------------------------------------------------------------------
The increase in the future income tax recovery for the three months
ended March 31, 2006 compared to the previous quarter was due to
lower net income in the current quarter.
Net (Loss)/Income
Three Months Ended
---------------------------------------------------------------------
($ millions, Mar 31, Dec 31, Mar 31,
except per BOE) 2006 2005 2005
---------------------------------------------------------------------
Net income $ 68.9 $ 101.5 $ 24.0
---------------------------------------------------------------------
Cash flow from operations, as opposed to net income, is the primary measure of performance
for an energy trust. The generation of cash flow is critical for an energy trust
to continue paying its distributions to Unitholders.
Conversely, net income is an accounting measure impacted by both cash and non-cash
items. The largest non-cash items impacting PrimeWest's net income are DD&A, the
unrealized gain or loss on derivatives and future income taxes.
Net income for the three months ended March 31, 2006 of $68.9 million was lower
than the previous quarter net income of $101.5 million primarily due to the decrease
in oil and gas revenues resulting from lower realized natural gas and natural gas
liquids prices, to lower production volumes, and to a reduced unrealized gain on
the mark to market value of the derivatives. Lower royalties, DD&A and future income
tax expense had a positive impact on net income.
Net income for the first quarter of 2006 is higher than the same period in the prior
year due to higher oil and gas revenues resulting from increases to commodity prices.
These increases were offset by higher royalties and operating expenses and lower
future income tax recoveries.
Liquidity & Capital Resources
Long-Term Debt
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions) 2006 2005 2005
---------------------------------------------------------------------
Long-term debt $ 321.6 $ 354.2 $ 504.5
Deficit/(working
capital)(1) 42.9 (30.5) 11.6
---------------------------------------------------------------------
Net debt 364.5 323.7 516.1
Market value of
Trust Units and
Exchangeable Shares
outstanding (2)(3) 2,681.7 2,884.7 2,112.6
---------------------------------------------------------------------
Total capitalization $ 3,046.2 $ 3,208.4 $ 2,628.7
---------------------------------------------------------------------
Net debt as a % of
total capitalization 12% 10% 20%
---------------------------------------------------------------------
(1) Excludes derivative and future income tax assets and liabilities
included in current assets or liabilities.
(2) Based on March 31, 2006 Trust Unit closing price of $32.98 and
March 15, 2006 exchange ratio of 0.58188:1.
(3) Excludes the Debentures.
Long-term debt is comprised of bank credit facilities, Secured Notes and Debentures
of $127.0 million, $146.0 million and $48.6 million respectively.
PrimeWest had a borrowing base of $650 million at March 31, 2006. The bank credit
facilities consist of an available revolving term loan facility of $458.7 million
and an operating facility of $35 million with the balance being attributed to the
Secured Notes valued at $156.3 million based on the U.S. dollar exchange rate at
the time of last renewal. In addition to amounts outstanding under the bank credit
facility, PrimeWest has outstanding letters of credit in the amount of $6.6 million
(2005 - $4.8 million). The bank credit facility revolves until June 30, 2006, by
which time the lenders will have conducted their annual borrowing base review.
At March 31, 2006 PrimeWest's net debt to annualized first quarter cash flow was
approximately 0.9 times compared to 0.8 times at December 31, 2005. Net debt as
a percentage of total capitalization was 12% at March 31, 2006, compared to 10%
at December 31, 2005.
During the first quarter of 2006, $3.0 million of the Series I and $4.3 million
of the Series II Debentures long-term debt component were converted to Trust Units.
Accretion of $0.1 million was realized during this period.
Unitholders' Equity
At March 31, 2006, the Trust had 80,627,204 Trust Units outstanding. In addition,
PrimeWest had 1,180,935 Exchangeable Shares outstanding that are exchangeable into
a total of 687,162 Trust Units using the March 15, 2006 exchange ratio of 0.58188:1.
The equity component of the Series I and Series II Debentures has been reduced by
$0.1 million and $0.2 million respectively, due to conversions to Trust Units in
the quarter.
During the first quarter of 2006, PrimeWest issued 147,942 Trust Units for $4.9
million under the DRIP, 200,835 Trust Units for $6.6 million pursuant to the PREP
and 169,744 Trust Units for proceeds of $5.7 million under the OTUPP.
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 2006 to
be similar to that experienced in 2005. Proceeds from these plans are used for debt
reduction of PrimeWest's credit facility and to help fund ongoing capital development
programs.
For additional information or to join the DRIP, OTUPP and PREP plans, contact the
Plan Agent, Computershare Trust Company of Canada, at 1-800-564-6253 or visit PrimeWest's
website at
www.primewestenergy.com.
Exchangeable Shares
Exchangeable Shares were issued in connection with both the Venator Petroleum Company
Ltd. acquisition in April 2000 and the Cypress Energy Inc. acquisition in March
2001. These shares were issued to provide a tax-deferred rollover of the adjusted
cost base from the shares being exchanged to the Exchangeable Shares. Exchangeable
Shares were also issued as part of PrimeWest's internalization transaction (See
Note 18 in the Consolidated Financial Statement of the 2005 Annual Report) whereby
PrimeWest agreed to issue Exchangeable Shares to the Executive Officers pursuant
to a Special Employee Retention Plan.
The Exchangeable Shares do not receive cash distributions. In lieu of receiving
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 March 31, 2006, there were 1,180,935 Exchangeable Shares outstanding. The exchange
ratio on these shares was 0.58188:1 Trust Units for each Exchangeable Share as at
March 15, 2006. For purposes of calculating basic per Trust Unit amounts these Exchangeable
Shares have been assumed to be exchanged into Trust Units at the current exchange
ratio.
Cash Distributions
Cash distributions to Unitholders are at the discretion of the Board of Directors
and can fluctuate depending on the cash flow generated from operations and other
factors. The cash flow available for distribution is dependent upon many factors
including commodity prices, production levels, debt levels, capital spending requirements,
and factors in the overall industry environment.
The Board of Directors targets a long-term distribution payout ratio that is a percentage
of cash flow from operations. However, the actual distribution payout ratio may
periodically vary from the target 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 cash flow from operations.
In the first quarter of 2006, cash distributions totaled $86.8 million, or $1.08
per Trust Unit representing a payout ratio of approximately 84%, compared to $63.8
million, or $0.90 per Trust Unit (80% payout ratio) for the same period in 2005.
In the fourth quarter of 2005 cash distributions totaled $76.2 million, or $0.96
per Trust Unit representing a payout ratio of approximately 57%.
Distribution payments to U.S. Unitholders are subject to a 15% Canadian withholding
tax, which is deducted from the entire distribution amount prior to deposit into
Unitholder accounts.
Contractual Obligations
PrimeWest enters into many contractual obligations as part of conducting day-to-day
business. Material contractual obligations include debt obligations, lease rental
commitments that run from 2006 through 2009 and various pipeline transportation
commitments that run through 2011. The details of the timing of these contractual
obligations are included in the following table.
As at March 31, 2006 Payments due by period
---------------------------------------------------------------------
Less than 1-3 4-5 More than
($ millions) Total 1 year years years 5 years
---------------------------------------------------------------------
Long-term debt
obligations 273.0 - 200.0 73.0 -
Debentures 50.1 - - 30.5 19.6
Lease rental
obligations 10.4 3.6 6.8 - -
Pipeline
Transportation
obligations 9.0 6.2 2.5 0.3 -
---------------------------------------------------------------------
Total contractual
obligations 342.5 9.8 209.3 103.8 19.6
---------------------------------------------------------------------
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 pursuant to the SERP. On November 6, 2004 and 2005, 94,340 Exchangeable
Shares were issued to those officers. An additional 94,340 Exchangeable Shares will
be issued on November 6, 2006 and 2007. For the three months ended March 31, 2006,
$0.4 million has been recorded in non-cash G&A expenses related to the SERP.
Business Risks
PrimeWest's operations are affected by a number of underlying risks, both internal
and external to the Trust. These risks are similar to those affecting others in
both the conventional oil and gas royalty trust sector and the conventional oil
and gas producers sector. The Trust's financial position, results of operations,
and cash available for distribution to Unitholders are directly impacted by these
factors. These factors are discussed under two broad categories - "Commodity Price,
Foreign Exchange and Interest Rate Risk" and "Operational and Other Business Risks."
For additional information on Business Risks, including Risks Related to the Trust
Structure and the Ownership of Trust Units, see PrimeWest's most recently filed
Annual Information Form.
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
the Trust's control. Some of these factors include:
- World market forces, specifically the actions of OPEC and other large crude oil
producing countries including Russia and their implications on the supply of crude
oil;
- World and North American economic conditions which influence the demand for both
crude oil and natural gas and the level of interest rates set by the governments
of Canada and the U.S.;
- Weather conditions that influence the demand for natural gas and heating oil;
- The Canadian/U.S. dollar exchange rate that affects the price received for crude
oil, as the price of crude oil is referenced in U.S. dollars;
- Transportation availability and costs; and
- Price differentials among World and North American markets based on transportation
costs to major markets and quality of production.
To mitigate these risks, PrimeWest has an active hedging program in place based
on an established set of criteria that has been approved by the Board of Directors.
The results of the hedging program are reviewed against these criteria and the results
actively monitored by the Board.
Beyond our hedging strategy, PrimeWest also mitigates risk by having a well-diversified
marketing portfolio and by transacting with a number of counterparties and limiting
exposure to each counterparty. For the first quarter of 2006 approximately 17% of
natural gas production was sold to aggregators and 83% of production was sold into
the Alberta and British Columbia 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 objective of our commodity risk management program is to reduce the
volatility of our cash distributions, to lock in the economics on major acquisitions
and to protect our capital structure when commodity prices cycle downwards. In the
first quarter 2006, PrimeWest realized a $0.9 million loss from commodity hedges.
Operational And Other Business Risks
PrimeWest is also exposed to a number of risks related to its activities within
the oil and gas industry that have an impact on the amount of cash available to
Unitholders. These risks, and the manner in which PrimeWest seeks to mitigate these
risks include, but are not limited to:
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Risk We Mitigate By
---------------------------------------------------------------------
Production
Risk associated with the Performing regular and proactive
production of oil and gas - protective well, facility and pipeline
includes well operations, maintenance supported by telemetry,
processing and the physical physical inspection and diagnostic
delivery of commodities to tools.
market.
---------------------------------------------------------------------
Commodity Price
Fluctuations in natural Hedging. See page 12 of this quarterly
gas, crude oil and natural report.
gas liquid prices.
---------------------------------------------------------------------
Transportation
Market risk related to the Diversifying the transportation systems
availability of on which we rely to get our product to
transportation to market market.
and potential disruption in
delivery systems.
---------------------------------------------------------------------
Natural Decline
Development risk associated Diversifying our capital spending
with capital enhancement program over a large number of projects
activities undertaken - the so that large amounts of capital are
risk that capital spending not risked on any one activity. We also
on activities such as have a highly skilled technical team
drilling, well completions, of geologists, geophysicists and
well workovers and other engineers working to apply the
capital activities will not latest technology in planning and
result in reserve additions executing capital programs.
or in quantities sufficient Capital is spent only after strict
to replace annual economic criteria for production and
production declines. reserve additions are assessed.
---------------------------------------------------------------------
Acquisitions
Acquisition risk associated Continually scanning the marketplace
with acquiring producing for opportunities to acquire assets.
properties at low cost to Our technical acquisition specialists
renew our inventory of evaluate potential corporate or property
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
period.
---------------------------------------------------------------------
Reserves
Reserve risk in respect of Contracting our reserves evaluation to a
the quantity and quality of reputable third party consultant, GLJ
recoverable reserves. Petroleum Consultants (GLJ). The
Operations and Reserves Committee of the
Board of Directors and PrimeWest review
the work and independence of GLJ. Our
strategy is to invest in mature, longer
life properties having a higher proved
producing component where the reserve
risk is generally lower and cash flows
are more stable and predictable.
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Environmental Health and Safety (EH&S)
Environmental, health and Establishing and adhering to strict
safety risks associated guidelines for EH&S including training,
with oil and gas properties proper reporting of incidents,
and facilities. supervision and awareness. PrimeWest
has active community involvement in
field locations including regular
meetings with stakeholders in the area.
PrimeWest carries adequate insurance to
cover property losses, liability and
business interruption.
These risks are reviewed regularly by
the Corporate Governance and EH&S
Committee of the Board.
---------------------------------------------------------------------
Regulation, Tax and Royalties
Changes in government Keeping informed of proposed changes in
regulations including regulations and laws to properly respond
reporting requirements, to and plan for the effects that these
income tax laws, operating changes may have on our operations.
practices, environmental
protection requirements and
royalty rates.
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Historical Liability to Unitholders is Uncertain
Because of uncertainties in On July 1, 2004, a new statute entitled
the law prior to July 1, the Income Trusts Liability Act
2004, relating to (Alberta) was proclaimed in force,
investments in trusts, creating a statutory limitation on the
there is a risk that a liability of Unitholders of Alberta
Unitholder could be held income trusts such as PrimeWest.
personally liable for The legislation provides that a
obligations of the Trust. Unitholder is not, as beneficiary,
liable for any act, default, obligation
or liability of the Trust that arises
after July 1, 2004. Similar legislation
was proclaimed in force in Ontario in
December of 2004.
---------------------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
---------------------------------------------------------------------
Unaudited
($ millions) Mar 31, 2006 Dec 31, 2005
---------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 3.2 $ 36.8
Accounts receivable 102.1 125.0
Derivative assets 12.7 -
Future income taxes - 3.9
Prepaid expenses 15.8 16.3
Inventory - 3.5
---------------------------------------------------------------------
133.8 185.5
Cash reserved for site restoration
and reclamation 9.1 9.2
Other assets and deferred charges 8.3 8.8
Property, plant and equipment 1,887.2 1,859.9
Goodwill 68.5 68.5
---------------------------------------------------------------------
$ 2,106.9 $ 2,131.9
---------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable $ 57.4 $ 50.2
Accrued liabilities 82.1 75.9
Future income taxes 3.7 -
Derivative liabilities 1.6 11.3
Accrued distributions to Unitholders 24.5 25.0
---------------------------------------------------------------------
169.3 162.4
Long-term debt (note 3) 321.6 354.2
Derivative liabilities 0.4 0.2
Future income taxes 206.5 214.8
Asset retirement obligation (note 2) 40.7 40.4
---------------------------------------------------------------------
738.5 772.0
UNITHOLDERS' EQUITY
Net capital contributions (note 4) 2,319.6 2,294.3
Capital issued but not distributed 4.5 3.6
Convertible unsecured subordinated
debentures 1.5 1.8
Contributed surplus (note 5) 9.2 8.7
Accumulated income 372.7 303.8
Accumulated cash distributions (1,331.1) (1,244.3)
Accumulated dividends (8.0) (8.0)
---------------------------------------------------------------------
1,368.4 1,359.9
---------------------------------------------------------------------
$ 2,106.9 $ 2,131.9
---------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY
Unaudited Three Months Ended
---------------------------------------------------------------------
($ millions) Mar 31, 2006 Mar 31, 2005
---------------------------------------------------------------------
Unitholders' equity, beginning
of period $ 1,359.9 $ 1,180.4
Net income for the period 68.9 24.0
Net capital contributions (note 4) 25.3 58.1
Convertible Unsecured Subordinated
Debentures (0.3) (1.2)
Capital issued but not distributed 0.9 (0.3)
Contributed surplus (note 5) 0.5 0.4
Cash distributions (86.8) (63.8)
---------------------------------------------------------------------
Unitholders' equity, end of period $ 1,368.4 $ 1,197.6
---------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW
Unaudited Three Months Ended
---------------------------------------------------------------------
($ millions) Mar 31, 2006 Dec 31, 2005
---------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the period $ 68.9 $ 24.0
Add/(deduct) items not involving
cash from operations
Depletion, depreciation and
amortization 53.9 57.3
Non-cash general and administrative 1.4 1.3
Non-cash foreign exchange loss 0.6 0.9
Cash distributions from marketable
securities - 1.0
Gain on sale of marketable securities - (26.9)
Unrealized (gain)/loss on derivatives (22.2) 35.2
Future income taxes recovery (0.7) (14.5)
Accretion on asset retirement obligation 0.7 0.6
Other non-cash items 0.6 0.8
---------------------------------------------------------------------
Cash flow from operations 103.2 79.7
Expenditures on site restoration
and reclamation (1.9) (0.9)
Change in non-cash working capital 23.2 (21.6)
---------------------------------------------------------------------
124.5 57.2
---------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust
Units, net of issue costs 5.7 7.6
Net cash distributions to Unitholders (74.4) (54.5)
Decrease in bank credit facilities (26.0) (114.0)
Change in non-cash working capital (2.3) 0.4
---------------------------------------------------------------------
(97.0) (160.5)
---------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant
and equipment (82.6) (61.6)
Acquisition of capital/corporate assets (0.2) -
Proceeds on disposal of property,
plant and equipment 3.1 8.7
Proceeds on sale of marketable securities - 94.5
(Decrease)/Increase in cash
reserved for future site restoration
and reclamation 0.1 (1.0)
Change in non-cash working capital 18.5 17.0
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(61.1) 57.6
---------------------------------------------------------------------
Decrease in cash for the period (33.6) (45.7)
Cash beginning of the period 36.8 54.4
---------------------------------------------------------------------
Cash end of the period 3.2 8.7
---------------------------------------------------------------------
Cash interest paid 2.7 7.7
Cash taxes paid 0.7 0.6
---------------------------------------------------------------------
Non-cash transactions - conversion of
Convertible Unsecured Subordinated
Debentures into Trust Units 7.6 40.3
---------------------------------------------------------------------
Consolidated Statements of Income
Unaudited Three Months Ended
---------------------------------------------------------------------
($ millions) Mar 31, 2006 Mar 31, 2005
---------------------------------------------------------------------
REVENUES
Sales of crude oil, natural gas
and natural gas liquids $ 191.1 $ 155.2
Crown and other royalties (44.7) (36.0)
Unrealized gain/(loss) on
derivatives 22.2 (35.2)
Gain on sale of marketable
securities - 26.9
Other income 1.4 0.3
---------------------------------------------------------------------
170.0 111.2
---------------------------------------------------------------------
EXPENSES
Operating 32.7 24.4
Transportation 1.9 1.9
Cash general and administrative 5.3 5.5
Non-cash general and
administrative 1.4 1.3
Depletion, depreciation and
amortization 53.9 57.3
Interest 4.6 9.1
Accretion on asset retirement
obligation 0.7 0.6
Foreign exchange loss 0.7 0.9
---------------------------------------------------------------------
101.2 101.0
---------------------------------------------------------------------
Income before taxes for the period 68.8 10.2
---------------------------------------------------------------------
Income and capital taxes 0.6 0.7
Future income taxes recovery (0.7) (14.5)
---------------------------------------------------------------------
(0.1) (13.8)
---------------------------------------------------------------------
Net income for the period 68.9 24.0
---------------------------------------------------------------------
Net income per Trust Unit - basic 0.85 0.34
Net income per Trust Unit - diluted 0.83 0.34
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31,2006, all amounts (except per Trust Unit amounts)
are expressed in millions of Canadian dollars unless otherwise indicated.
1. Significant Accounting Policies
These interim consolidated financial statements of PrimeWest have been prepared
in accordance with Canadian generally accepted accounting principles. The specific
accounting principles used are described in the annual consolidated financial statements
of the Trust appearing on pages 52 and 53 of the Trust's 2005 annual report and
should be read in conjunction with these interim financial statements.
2. Asset Retirement Obligations
Management has estimated the total future asset retirement obligation based on the
Trust's net ownership interest in all wells and facilities. This includes all estimated
costs to dismantle, remove, reclaim and abandon the wells and facilities and the
estimated time period during which these costs will be incurred in the future.
The following table reconciles the asset retirement obligation associated with the
retirement of oil and gas properties:
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Asset Retirement Obligation ($ millions)
---------------------------------------------------------------------
Asset Retirement Obligation,
December 31, 2005 $ 40.4
Change in estimate of liability 1.6
Liabilities settled (1.9)
Accretion expense 0.7
Sale of capital assets (0.1)
---------------------------------------------------------------------
Asset Retirement Obligation, March
31, 2006 $ 40.7
---------------------------------------------------------------------
---------------------------------------------------------------------
As at March 31, 2005, the undiscounted amount of estimated cash flows required to
settle the obligation is $223.2 million. The estimated cash flow has been discounted
using a credit-adjusted risk free rate of 7.0 percent and an inflation rate of 1.5
percent. Although the expected period until settlement ranges from a minimum of
1 year to a maximum of 50 years, the expectation is that costs will be paid over
an average of 33 years. These future asset retirement costs will be funded from
the cash reserved for site restoration and reclamation. This cash reserve is currently
funded at $0.50 per BOE from PrimeWest's operating resources.
3. Long-Term Debt
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($ millions) Mar 31, 2006 Dec 31, 2005
---------------------------------------------------------------------
Bank credit facilities $ 127.0 $ 153.0
Senior Secured Notes 146.0 145.4
Convertible Unsecured Subordinated
Debentures 48.6 55.8
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$ 321.6 $ 354.2
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---------------------------------------------------------------------
4. Unitholders' Equity
The authorized capital of the Trust consists of an unlimited number
of Trust Units.
---------------------------------------------------------------------
Number
Trust Units of Units ($ millions)
---------------------------------------------------------------------
Balance, December 31, 2005 79,666,352 $ 2,282.0
Conversion of Convertible
Unsecured Subordinated Debentures 286,661 7.6
Issued on exchange of Exchangeable
Shares 21,870 0.3
Issued pursuant to Distribution
Reinvestment Plan 147,942 4.9
Issued pursuant to the Premium
Distribution Plan 200,835 6.6
Issued pursuant to Long-Term
Incentive Plan 133,754 0.5
Issued pursuant to Optional Trust
Unit Purchase Plan 169,744 5.7
Issued pursuant to Consolidation/
Fractional Units 46 -
---------------------------------------------------------------------
Balance, March 31, 2006 80,627,204 $ 2,307.6
---------------------------------------------------------------------
---------------------------------------------------------------------
The weighted average number of Trust Units and Exchangeable Shares outstanding for
the three months ended March 31, 2006 was 80,865,379 (2005 - 71,239,168). For purposes
of calculating diluted net income per Trust Unit for the three months ended March
31, 2006, 1,183,796 (2005 - 5,432,754) and 772,352 (2005 - 3,677,367) Trust Units
issuable pursuant to the conversion of the Convertible Unsecured Subordinated Debentures
Series I and II respectively and 1,226,608 Trust Units (2005 - 699,737) issuable
pursuant to the Long-Term Incentive Plan were added to the weighted average number.
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 a distribution
to its Unitholders. The exchange ratio, which was 1:1 on the date that the Exchangeable
Shares were first issued, is based on the total monthly distribution, divided by
the closing unit price on the distribution payment date. The exchange ratio effective
March 15, 2006 was 0.58188:1.
---------------------------------------------------------------------
Number
Exchangeable Shares of Shares ($ millions)
---------------------------------------------------------------------
Balance, December 31, 2005 1,219,335 $ 12.3
Exchanged for Trust Units (38,400) (0.3)
---------------------------------------------------------------------
Balance, March 31, 2006 1,180,935 12.0
---------------------------------------------------------------------
---------------------------------------------------------------------
5. Contributed Surplus
Contributed surplus includes the accumulated unit-based compensation charge in respect
of PrimeWest's unexercised Unit Appreciation Rights granted under the Long-Term
Incentive Plan 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, 2005 $ 8.7
Non-cash general and administrative expense 1.0
Unit Appreciation Rights exercised (0.5)
---------------------------------------------------------------------
Balance, March 31, 2006 $ 9.2
---------------------------------------------------------------------
---------------------------------------------------------------------
6. Long-Term Incentive Plan
Under the terms of the Long-Term Incentive Plan, a maximum of 1,800,000 Trust Units
are reserved for issuance pursuant to the exercise of Unit Appreciation Rights (UARs)
granted to Directors and employees of PrimeWest. Payouts under the plan are based
on total Unitholder return, calculated using both the change in the Trust Unit price
as well as cumulative distributions paid. The plan requires that a hurdle return
of 5% per annum be achieved before payouts accrue. UARs have a term of up to six
years and vest equally over a three-year period, except for those issued to the
members of the Board, which vest immediately. The Board of Directors has the option
of settling payouts under the plan in PrimeWest Trust Units or in cash. To date,
all payouts under the plan have been in the form of Trust Units.
Effective January 1, 2005, PrimeWest adopted the fair value method of accounting
for its Long-Term Incentive Plan 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 non-cash general and administrative
expenses offset by an increase to contributed surplus. When the UARs are exercised,
contributed surplus is decreased and net capital contributions are increased.
PrimeWest recorded $1.0 million in non-cash general and administrative expense related
to the Long-Term Incentive Plan for the three months ended March 31, 2006 ($0.9
million - 2005) using the fair value method of accounting.
PrimeWest used a recognized option 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 Mar 31, 2006 Mar 31, 2005
---------------------------------------------------------------------
Risk-free interest rate 3.84% 3.25%
Expected volatility in Trust Unit
price 22.3% 19.8%
Expected time until exercise 3.5 years 3 years
Expected forfeiture rate 10.6% 13%
Expected annual dividend yield zero zero
---------------------------------------------------------------------
---------------------------------------------------------------------
Summary of Changes in Unit Weighted Average
Appreciation Rights Number of UARS Exercise Price
---------------------------------------------------------------------
Balance outstanding at December
31, 2005 4,169,675 $ 29.09
Granted 535,875 39.72
Forfeited/expired (140,250) (30.30)
Exercised (209,004) (28.22)
---------------------------------------------------------------------
Balance outstanding at March 31,
2006 4,356,296 $ 31.15
---------------------------------------------------------------------
Summary of UARS Outstanding at March 31, 2006
---------------------------------------------------------------------
Year of UARs Issued & Range of
Grant Outstanding UARs Vested Exercise Prices Expiry Date
---------------------------------------------------------------------
2002 grants 545,518 543,724 25.90 - 33.94 2008
2003 grants 721,300 580,994 25.25 - 32.24 2009
2004 grants 1,209,512 606,786 24.24 - 32.49 2010
2005 grants 1,343,801 327,399 28.90 - 40.51 2011
2006 grants 536,165 - 33.93 - 43.41 2012
---------------------------------------------------------------------
Total grants 4,356,296 2,058,903 24.24 - 43.41
---------------------------------------------------------------------
7. Cash Distributions
---------------------------------------------------------------------
($ millions, except per
Trust Unit amounts) Mar 31, 2006 Mar 31, 2005
---------------------------------------------------------------------
Cash flow from operations $ 103.2 $ 79.7
Deduct amounts to reconcile to
distribution: