PrimeWest Energy Trust Announces First Quarter 2007 Results
MAY 2, 2007 - 17:38 ET
CALGARY, ALBERTA--(CCNMatthews - May 2, 2007) - PRIMEWEST ENERGY TRUST (TSX:PWI.UN)
(TSX:PWX) (TSX:PWI.DB.A) (TSX:PWI.DB.B) (TSX:PWI.DB.C) (NYSE:PWI) (PRIMEWEST OR
THE TRUST) TODAY ANNOUNCES INTERIM OPERATING AND FINANCIAL RESULTS FOR THE QUARTER
ENDED MARCH 31, 2007. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT
ARE IN CANADIAN DOLLARS.
First Quarter 2007 Highlights:
- Distributions in the first quarter were $0.75 per Trust Unit representing a payout
ratio of approximately 72% of funds flow from operations compared to fourth quarter
2006 distributions of $0.75 per Trust Unit, which represented a payout ratio of
approximately 74% of funds flow from operations.
- Funds flow from operations for the first quarter was $93.8 million ($1.04 per
Trust Unit) compared to $84.6 million ($1.01 per Trust Unit) in the previous quarter
and $101.3 million ($1.25 per Trust Unit) in the first quarter of 2006.
- First quarter 2007 production averaged 41,748 BOE per day, compared to the fourth
quarter 2006 rate of 41,386 BOE per day. The increase in volumes is mainly due to
the incremental volumes from development capital exceeding natural decline. PrimeWest
expects full year 2007 production volumes to average between 39,000 - 40,000 BOE
per day which includes the planned divestitures of approximately 1,000 BOE per day
in the second quarter of 2007.
- Development capital expenditures in the first quarter were $71.5 million with
drilling, completion and tie-in expenditures of $57.4 million resulting in 26 gross
wells (18.7 net) being drilled with a cased success rate of 100%.
- On January 11, 2007, PrimeWest issued 6,420,000 Trust Units for net proceeds of
$142.4 million and Series III Convertible Unsecured Subordinated Debentures which
bear interest at 6.5% for net proceeds of $192.0 million.
- Net debt to annualized first quarter 2007 funds flow from operations was approximately
1.9 times at March 31, 2007, compared to net debt to annualized fourth quarter 2006
funds flow from operations of 2.4 times at December 31, 2006.
Subsequent Event
- Mr. Dennis Feuchuk, Vice President Finance and Chief Financial Officer tendered
his resignation effective July 6, 2007. Mr. Douglas Fraser will assume the role
of Vice President Finance and Chief Financial Officer effective June 1, 2007.
MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF MAY 2, 2007
The following is management's discussion and analysis (MD&A) of PrimeWest's operating
and financial results for the three months ended March 31, 2007, 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 quarterly report contains forward-looking or outlook information with respect
to PrimeWest.
Certain statements contained in this quarterly report constitute forward-looking
statements. The use of any of the words "anticipate", "continue", "estimate", "expect",
"forecast", "may", "will", "project", "should", "believe", "outlook" and similar
expressions are intended to identify forward-looking statements. In addition, statements
relating to "reserves" or "resources" are deemed to be forward-looking statements,
as they involve implied assessment, based on certain estimates and assumptions,
that the resources and reserves described can be profitably produced in the future.
These statements involve known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from those anticipated
in our forward-looking statements.
We believe the expectations reflected in those forward-looking statements are reasonable.
However, we cannot assure you that these expectations will prove to be correct.
You should not unduly rely on forward-looking statements included in this quarterly
report. These statements speak only as of the date of this quarterly report.
In particular, this quarterly report contains forward-looking statements pertaining
to the following:
- The quantity and recoverability of our reserves;
- The timing and amount of future production;
- Prices for oil, natural gas and natural gas liquids produced;
- Operating and other costs;
- Business strategies and plans of management;
- Supply and demand for oil and natural gas;
- Expectations regarding our ability to raise capital and to add to our reserves
through acquisitions and exploration and development;
- Our treatment under governmental regulatory regimes;
- The focus of capital expenditures on development activity rather than exploration;
- The sale, farming in, farming out or development of certain exploration properties
using third-party resources;
- The objective to achieve a predictable level of monthly cash distributions;
- The use of development activity and acquisitions to replace and add to reserves;
- The impact of changes in oil and natural gas prices on cash flow after hedging;
- Drilling plans;
- The existence, operations and strategy of the commodity price risk management
program;
- The approximate and maximum amount of forward sales and hedging to be employed;
- Our acquisition strategy, the criteria to be considered in connection therewith
and the benefits to be derived there from;
- The impact of the Canadian federal and provincial governmental regulations on
us relative to other oil and natural gas issuers of similar size;
- The goal to sustain or grow production and reserves through prudent management
and acquisitions;
- The emergence of accretive growth opportunities; and
- Our ability to benefit from the combination of growth opportunities and the ability
to grow through the capital markets.
With respect to forward-looking statements contained in this quarterly report 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 in this quarterly report:
- Volatility in market prices for oil and natural gas;
- The impact of weather conditions on seasonal demand;
- Risks inherent in our oil and natural gas operations;
- Uncertainties associated with estimating reserves;
- Competition for, among other things: capital, acquisitions of reserves, undeveloped
lands and skilled personnel;
- Incorrect assessments of the value of acquisitions;
- Geological, technical, drilling and processing problems;
- General economic conditions in Canada, the United States and globally;
- Tax treatment of the trust and its subsidiaries;
- Industry conditions, including fluctuations in the price of oil and natural gas;
- Royalties payable in respect of our oil and natural gas production;
- Government regulation of the oil and natural gas industry, including environmental
regulation;
- Fluctuation in foreign exchange or interest rates;
- Unanticipated operating events that could reduce production or cause production
to be shut-in or delayed;
- Failure to obtain industry partner and other third-party consents and approvals,
when required;
- Stock market volatility and market valuations;
- OPEC's ability to control production, and balance global supply and demand of
crude oil at desired price levels;
- Political uncertainty, including the risks of hostilities, in the petroleum-producing
regions of the world;
- The need to obtain required approvals from regulatory authorities; and
- The other factors discussed under Risk Factors contained in this quarterly report.
These factors should not be construed as exhaustive. The forward-looking statements
contained in this quarterly report are expressly qualified by this cautionary statement.
Except as may be required by applicable securities laws we undertake no obligation
to publicly update or revise any forward-looking statements.
All figures reported in Canadian dollars unless otherwise stated.
Production figures stated are 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, 2007, and concluded that PrimeWest's disclosure controls and procedures
were effective to ensure that information PrimeWest is required to disclose:
- In its annual filings and interim filings (each as defined in National Instrument
52-109 of the Canadian Securities Administrators) filed or submitted by it under
provincial securities legislation is recorded, processed, summarized and reported
within the time periods specified in the provincial securities legislation and to
ensure that information required to be disclosed by PrimeWest in its annual filings
and interim filings filed or submitted under provincial securities legislation is
accumulated and communicated to PrimeWest's management, including its chief executive
officer and chief financial officer, as appropriate to allow timely decisions regarding
required disclosure; and
- In its annual filings, interim filings or other reports with the United States
Securities and Exchange Commission (SEC) in the United States under the Securities
Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported,
within the time periods specified in the SEC's rules and forms, and to ensure that
information required to be disclosed by PrimeWest in the reports that it files under
the Exchange Act is accumulated and communicated to PrimeWest's management, including
its principal executive officer and principal financial officer, as appropriate
to allow timely decisions regarding required disclosure.
The evaluation took into consideration PrimeWest's Communications and Disclosure
Policy and the functioning of its executive officers, board of directors and board
committees. In addition, the evaluation covered PrimeWest's processes, systems and
capabilities relating to regulatory filings, public disclosures and the identification
and communication of material information.
Changes to Internal Controls Over Financial Reporting
There were no changes to PrimeWest's internal control over financial reporting since
December 31, 2006, which have materially affected, or are reasonably likely to materially
affect PrimeWest's internal control over financial reporting.
Non-GAAP Measures
This MD&A contains the following measurements that are not defined by Canadian Generally
Accepted Accounting Principles (GAAP):
- Funds flow from operations on a total and per Trust Unit basis;
- Distributions per Trust Unit; and
- Net debt per Trust Unit.
These measures do not have any standardized meaning prescribed by GAAP and are therefore
unlikely to be comparable to similar measures presented by other issuers.
Funds flow from operations is measured as cash flow from operating activities before
changes in non-cash working capital. Funds flow from operations does not represent
operating cash flows or operating profits for the period and should not be viewed
as an alternative to cash flow from operating activities calculated in accordance
with GAAP. Funds flow from operations is a key performance indicator of PrimeWest's
ability to generate cash and finance operations and pay monthly distributions.
Funds flow from operations per Trust Unit on a basic basis is calculated by dividing
funds flow from operations by the weighted average number of Trust Units outstanding
plus Trust Units issueable upon the exchange of the outstanding Exchangeable Shares
of PrimeWest Energy Inc. (Exchangeable Shares). Funds flow from operations per Trust
Unit on a diluted basis is calculated using funds flow from operations and adding
back the interest expense on the 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 issueable upon the exchange
of outstanding Exchangeable Shares and includes the Trust Units issueable pursuant
to the conversion of the Debentures, and Trust Units issueable pursuant to the Long-Term
Incentive Plan (LTIP).
Distributions per Trust Unit disclose the cash distributions accrued in the period
based on the number of Trust Units outstanding on the applicable record dates.
Net debt per Trust Unit is calculated as long-term debt, including Debentures, less
working capital, excluding financial derivative assets and liabilities and current
future income tax assets and liabilities divided by the number of Trust Units outstanding
and Trust Units issueable upon the exchange of outstanding Exchangeable Shares and
Trust Units issueable pursuant to the LTIP at March 31, 2007.
Business Strategy
PrimeWest Energy Trust is an Alberta based conventional oil and natural gas royalty
trust actively managed to generate monthly cash distributions for the holders of
Trust Units (Unitholders). The Trust's operations are focused in the Western Canada
Sedimentary Basin and Montana, North Dakota and Wyoming in the United States. PrimeWest
is one of North America's largest natural gas-weighted energy trusts.
Maximizing total return to Unitholders, in the form of cash distributions and appreciation
in unit price, is PrimeWest's overriding objective. Our strategies for asset management
and growth, financial management and corporate governance are outlined in this MD&A,
along with a discussion of our performance for the three months ended March 31,
2007, and our goals for 2007 and beyond.
We believe that PrimeWest can maximize total return to Unitholders by continuing
to develop our core properties, making opportunistic acquisitions that emphasize
value creation, exercising disciplined financial management which broadens access
to capital while minimizing risk to Unitholders, and complying with strong corporate
governance principles to protect the interests of all stakeholders.
Asset Management and Growth
PrimeWest has a strategy to focus expansion efforts on existing core areas and pursue
depletion optimization strategies within those core areas to maximize asset value.
We make every effort to obtain operatorship of our asset base and maintain high
working interests in core areas. We currently maintain operatorship of approximately
80% of our assets, which allows us to use existing infrastructure and synergies
within our core areas. We believe this high level of control can translate into
cost efficiencies and timing of capital outlays and projects. The current size of
the Trust gives us the ability and critical mass to make acquisitions of significant
size, while being able to add value by transacting smaller acquisitions.
Financial Management
PrimeWest strives to maintain a prudent debt position, to allow us to fund smaller
acquisitions and to fund ongoing development activities without tapping the capital
markets. Our long-term debt is comprised of bank credit facilities through a bank
syndicate, U.S.-dollar-denominated Senior Secured Notes (U.S. Secured Notes), Pounds
Sterling denominated Senior Secured Notes (U.K. Secured Notes) and Debentures. Our
diversified debt instruments help to reduce our reliance on the bank syndicate.
PrimeWest's commodity hedging strategy is designed to reduce the volatility of cash
flow by providing some near term downside price protection. Hedging a portion of
our production protects acquisition economics and our capital structure and provides
partial protection against short-term declines in commodity prices. Since 2003,
PrimeWest has followed a strategy of maintaining a distribution payout ratio within
70-90% of funds flow from operations, calculated on an annual basis, recognizing
that during periods of volatile commodity prices the payout ratio may move out of
this range. The Board of Directors of PrimeWest considers a variety of factors in
establishing the monthly distribution level including, but not limited to: commodity
price outlook, cash flow forecast, capital development plans, debt levels, tax considerations
and competitive industry distribution practices. Further, the October 31 proposals
discussed under Taxation of the Trust, have created additional uncertainty with
respect to the payout ratio. At this time, PrimeWest is unable to predict what payout
ratio it will maintain in the future.
The first quarter 2007 payout ratio (being the ratio of distributions paid or declared
to funds flow from operations) was approximately 72% of funds flow from operations.
Retained cash flow was utilized to fund a part of the Trust's capital spending program.
PrimeWest's ratio of net debt to annualized first quarter funds flow from operations
was approximately 1.9 times at March 31, 2007.
PrimeWest's dual listing on the Toronto Stock Exchange (TSX) and New York Stock
Exchange (NYSE) provides increased liquidity and a broadened investor base. The
NYSE listing enables U.S. Unitholders to conveniently trade in our Trust Units,
and allows us to access the U.S. capital markets. Our status as a corporation for
U.S. tax purposes simplifies tax reporting for our U.S. Unitholders.
For eligible Canadian and U.S. Unitholders, PrimeWest offers participation in the
conventional Distribution Reinvestment Plan (DRIP), which represents a convenient
way to maximize an investment in PrimeWest. Canadian residents may also participate
in the Optional Trust Unit Purchase Plan (OTUPP) and the Premium Distribution Plan
(PREP). For alternate investment requirements, PrimeWest also has Exchangeable Shares
and Debentures issued and outstanding.
Corporate Governance
PrimeWest is committed to high standards of corporate governance and upholds the
rules of the governing regulatory bodies under which it operates. Full disclosure
of our compliance with existing corporate governance rules and regulations is contained
in the Trust's Management Proxy Circular dated March 15, 2007, for its upcoming
annual general meeting and is available on our website at
www.primewestenergy.com. PrimeWest actively monitors the
corporate governance and disclosure environment to ensure compliance with current
and future requirements.
Our high standards of corporate governance are not limited to the boardroom. At
the field level, PrimeWest proactively manages environmental, health and safety
issues. We place a great deal of importance on community involvement and maintaining
good relationships with landowners.
Financial Highlights
Three Months Ended
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$ Millions, except per BOE (1) and
per Trust Unit amounts Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Gross revenue 189.7 173.6 191.1
per BOE 50.49 45.59 55.79
Funds flow from operations 93.8 84.6 101.3
per BOE 24.98 22.23 29.57
per Trust Unit - basic (2) 1.04 1.01 1.25
per Trust Unit - diluted (3) 0.98 1.00 1.22
Royalty expense 40.0 33.7 44.7
per BOE 10.65 8.86 13.04
Operating expense 38.9 39.6 32.7
per BOE 10.36 10.40 9.54
General and administrative expense
(G&A) 9.3 8.6 6.7
per BOE 2.47 2.27 1.97
Interest expense (4) 12.2 13.0 4.6
per BOE 3.25 3.42 1.34
Distributions to Unitholders 67.6 62.3 86.8
per Trust Unit (5) 0.75 0.75 1.08
Net debt (6) 716.3 820.8 364.5
per Trust Unit (7) 7.81 9.74 4.42
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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 issueable 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 issueable upon exchange of the
outstanding Exchangeable Shares, the deemed conversion of the
Convertible Unsecured Subordinated Debentures (Debentures) and Trust
Units issueable pursuant to the Long-Term Incentive Plan (LTIP).
Interest expense incurred on the Debentures is added back to net income
and to funds flow for the diluted per Trust Unit calculation.
(4) Interest expense includes the interest on the Debentures.
(5) Based on Trust Units outstanding at the record dates for distributions
during the period.
(6) Net debt is long-term debt including the Debentures adjusted for working
capital, excluding current derivative and future income tax assets and
liabilities.
(7) The net debt per Trust Unit calculation includes outstanding Trust
Units, Trust Units issueable upon exchange of the outstanding
Exchangeable Shares and Trust Units issueable pursuant to the LTIP at
the end of the period.
Operating Highlights
Three Months Ended
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Daily Production Volumes Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Natural gas (mmcf/day) 169.4 169.9 166.0
Crude oil (bbls/day) 9,071 8,950 6,867
Natural gas liquids (bbls/day) 4,443 4,127 3,525
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Total (BOE per day) 41,748 41,386 38,062
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Total BOE 3,757,320 3,807,512 3,425,580
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Average Realized Sales Prices
Three Months Ended
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Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Natural gas ($/Mcf) (1) 7.79 6.79 9.09
Crude oil ($/bbl) 58.23 55.13 57.09
Natural gas liquids ($/bbl) 53.78 52.52 59.34
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Total Oil Equivalent ($/BOE) 50.00 45.03 55.44
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Realized derivative gains/(losses)
($/BOE) 1.60 2.99 (0.27)
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Net realized price ($/BOE) 51.60 48.02 55.17
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(1) Excludes sulphur.
Funds Flow From Operations Reconciliation
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$ Millions
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Fourth quarter 2006 funds flow from
operations $ 84.6
Volumes (1.9)
Commodity prices 18.3
Net hedging change from prior
quarter (6.7)
Operating expenses 0.7
Royalties (6.3)
Site restoration and reclamation 1.5
Interest 0.3
Other 3.3
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First quarter 2007 funds flow from operations $ 93.8
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The above table includes non-GAAP measurements. (Refer to section regarding Non-GAAP
Measurements)
A key performance driver for the Trust is funds flow from operations, which directly
affects PrimeWest's ability to pay monthly distributions. Funds flow from operations
is generated through the production and sale of crude oil, natural gas and natural
gas liquids, and is dependent on production levels, commodity prices, operating
expense, site restoration and reclamation expenditures, interest expense, general
and administrative (G&A) expense, derivative 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 expense, as well as interest and G&A expense.
Reconciliation of Non-GAAP Measure
Three Months Ended
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$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Funds flow from operations $ 93.8 $ 84.6 $ 101.3
Change in non-cash working capital (3.3) 8.5 23.2
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Cash flow from operating activities $ 90.5 $ 93.1 $ 124.5
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Selected Canadian and U.S. Financial Results
Prior to 2006, PrimeWest had focused on oil and natural gas plays in Western Canada.
In July 2006, PrimeWest acquired U.S. assets. The following table provides selected
financial results from PrimeWest's Canadian and U.S. operations for the three months
ended March 31, 2007.
Three Months Ended Mar 31, 2007
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$ Millions, except production volumes and
per unit prices (2) Canada U.S. Total
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Daily Production Volumes
Natural gas (mmcf/day) 168.5 0.9 169.4
Crude oil (bbls/day) 6,718 2,353 9,071
Natural gas liquids (bbls/day) 4,394 49 4,443
Total daily sales (BOE per day) 39,193 2,555 41,748
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Three Months Ended Mar 31, 2007
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Pricing (1)
Natural gas ($/Mcf) 7.80 7.40 7.79
Crude oil ($/bbl) 58.17 58.41 58.23
Natural gas liquids ($/bbl) 54.0 34.53 53.78
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Revenues (1)
Natural gas 118.2 0.6 118.8
Crude oil 35.1 12.4 47.5
Natural gas liquids 21.3 0.2 21.5
Royalties (37.4) (2.6) (40.0)
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Expenses
Operating 35.4 3.5 38.9
G&A 8.6 0.7 9.3
Depletion, depreciation and amortization 62.0 4.9 66.9
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Capital expenditures
Development and head office 60.8 11.8 72.6
Acquisition of oil and gas properties 9.8 1.7 11.5
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(1) Net of transportation expense. Excludes derivative gains and losses.
(2) Comparative segmented information is not provided for the three months
ended March 31, 2006, as the U.S. assets were acquired in July, 2006.
Quarterly Performance - Selective Measures
The table below highlights PrimeWest's performance for the first quarter
ended March 31, 2007, and the preceding seven quarters through 2005.
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2007 2006 2005
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$ Millions, except per
Trust Unit Amounts Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
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Net Revenues 126.0 158.4 160.7 134.8 170.0 237.1 101.7 155.3
Net Income 5.5 9.6 64.0 65.7 68.9 101.5 27.3 54.7
Funds Flow from
Operations 93.8 84.6 91.4 86.8 101.3 128.6 105.1 92.8
Net income per Trust
Unit - basic 0.06 0.11 0.78 0.81 0.85 1.27 0.35 0.74
Net income per Trust
Unit - diluted 0.06 0.11 0.76 0.79 0.83 1.23 0.35 0.72
Funds flow per Trust
Unit - basic 1.04 1.01 1.11 1.06 1.25 1.61 1.34 1.26
Funds flow per Trust
Unit - diluted 0.98 1.00 1.09 1.03 1.22 1.56 1.29 1.18
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Net revenues are impacted primarily by commodity prices, production volumes, royalties
and realized and unrealized gains or losses on derivatives.
The non-cash items, which include depletion, depreciation and amortization (DD&A),
unit-based compensation, future income taxes, unrealized foreign exchange gains
or losses and changes in 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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$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Land and lease acquisitions $ 1.1 $ 1.6 $ 3.4
Geological and geophysical 2.5 0.7 1.5
Drilling and completions 49.0 38.8 53.5
Investment in facilities
Equipping and tie-in 8.4 9.2 15.6
Gas gathering and compression 6.8 2.9 1.2
Production facilities 2.3 2.7 4.7
Capitalized G&A 1.4 1.3 1.4
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Development capital 71.5 57.2 81.3
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Acquisition of oil and gas assets 11.5 0.4 0.2
Dispositions - (0.1) (3.1)
Leasehold improvements, furniture
and equipment 1.1 0.5 1.3
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Net capital expenditures $ 84.1 $ 58.1 $ 79.7
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During the first quarter of 2007, PrimeWest's development capital expenditures totalled
$71.5 million, compared to $57.2 million invested in the fourth quarter of 2006
and $81.3 million in the first quarter of 2006. Of the $71.5 million total, $57.4
million or 80.3% was invested in drilling, completions and tie-ins, which contribute
to new reserve additions and help offset natural production decline. PrimeWest drilled
26 gross wells (18.7 net) with a 100% cased success rate.
In March 2007, PrimeWest acquired an additional working interest in its assets in
the Columbia area for $9.8 million. Annualized production from the acquisition is
expected to be approximately 190 BOE per day.
Given that production volumes will decline naturally over time as oil or natural
gas reservoirs are depleted, PrimeWest is continually striving to offset this natural
decline and add to reserves in an effort to sustain cash flows. Investment in activities
such as development drilling, workovers and recompletions can add incremental production
volumes and reserves.
Development Capital Update - Canada and U.S.
PrimeWest's four key development plays are Conventional Development, Tight Gas,
U.S. Oil assets and Coalbed Methane (CBM).
Conventional Development
PrimeWest continues to invest in development opportunities at our conventional plays,
which include key properties at: Valhalla, Laprise, Wilson Creek, and Crossfield/Lone
Pine Creek. Development expenditures during the first quarter totalled $46.1 million,
including $30.6 million for drilling and completions, $2.2 million for land and
seismic and $13.3 million for equipping, tie-in and facilities. A total of 23 gross
wells were drilled during the quarter.
The following provides a description of the Wilson Creek, Crossfield/Lone Pine Creek,
Valhalla and Laprise areas, which are major properties in our conventional development
play.
Wilson Creek
In the Wilson Creek area, PrimeWest drilled 9 operated wells in the first quarter
of 2007, targeted at various formations including Edmonton, Belly River, Glauconitic,
Mannville, and Rock Creek. Capital expenditures at Wilson Creek were $15.6 million,
including $12.3 million for drilling and completions, $3.2 million for equipping,
tie-in and facilities and $0.1 for land and seismic.
Crossfield/Lone Pine Creek
Crossfield/Lone Pine Creek development targets deeper prospects in the Leduc and
Nisku pools. First quarter development capital expenditures at Crossfield/Lone Pine
Creek were $7.0 million.
Valhalla and Laprise
Valhalla provides the Trust with low-risk downspacing and infill drilling opportunities
in the Montney and Doig formations with additional multi-zone natural gas targets
in the Gething and Halfway formations. PrimeWest invested $3.5 million for drilling
and completions and tie-ins and drilled two wells in the quarter.
At Laprise, PrimeWest invested $8.1 million in drilling and completions, $1.2 million
on seismic and $4.0 million on equipping, tie-in and facilities. Five wells were
drilled during the first quarter of 2007.
Tight Gas Plays
PrimeWest's Tight Gas plays (Caroline, Columbia, Harlech, Edson and Ferrier) 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
quickly level off at a lower more 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 2007. Capital expenditures for the three months ended March 31, 2007, included
$12.7 million for drilling and completions, equipping, tie-in and facilities. Two
gross wells were drilled and completed during the quarter and three wells were re-completed.
U.S. Oil Assets
In 2006, PrimeWest acquired producing oil and gas assets located in Montana, North
Dakota and Wyoming. The acquisition established a new operating area within the
Williston Basin, providing considerable waterflood and development drilling potential.
The major fields acquired were Flat Lake, Dwyer and Goose Lake in Montana; Rival,
Grenora, Alexander, Wiley, Glenburn and Sherwood in North Dakota; and Rocky Point
in Wyoming.
Expenditures in the first quarter of $11.8 million included $9.8 million for drilling,
completions and tie-ins, $1.0 million for seismic and $1.0 million on capital workovers.
Two wells were drilled and four were completed in the first quarter.
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 in the preliminary assessment stage of its CBM assets and successes in 2006 resulted
in the first booking of CBM reserves at year end. Commencement on commercial development
of the CBM will be contingent on the natural gas price. PrimeWest incurred minimal
expenditures in the CBM play during the first quarter of 2007.
Daily Production Volumes
Three Months Ended
----------------------------------------------------------------------------
Daily Production Volumes Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Natural gas (mmcf/day) 169.4 169.9 166.0
Crude oil (bbls/day) 9,071 8,950 6,867
Natural gas liquids (bbls/day) 4,443 4.127 3,525
----------------------------------------------------------------------------
Total (BOE per day) 41,748 41,386 38,062
----------------------------------------------------------------------------
PrimeWest's production volumes averaged 41,748 BOE per day in the first quarter
of 2007, compared to 41,386 BOE per day in the fourth quarter 2006. The 1% increase
in volumes is mainly due to the continued success with the Canadian drilling program.
Incremental volumes resulting from PrimeWest's capital development expenditures
offset volume reductions due to natural decline.
For the three months ended March 31, 2007, production volumes increased by approximately
10% when compared to the same period in 2006 due to the acquisition of the U.S.
assets early in the third quarter of 2006 and to incremental volumes from development
capital exceeding natural decline.
Production Outlook
PrimeWest expects full year 2007 production volumes to average between 39,000 -
40,000 BOE per day in 2007.
Commodity Prices
Three Months Ended
----------------------------------------------------------------------------
Benchmark Prices Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Natural gas
NYMEX (US$/mcf) 6.96 6.62 9.08
AECO (C$/mcf) 7.46 6.36 9.27
Crude oil WTI (US$/bbl) 58.27 60.21 63.48
----------------------------------------------------------------------------
Benchmark Commodity Prices
The following table sets forth benchmark historical and estimated future
commodity prices.
----------------------------------------------------------------------------
Past Four Next Four Quarters
Quarters (Actual) (Forward Markets)(1)
----------------------------------------------------------------------------
Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
2006 2006 2006 2007 2007 2007 2007 2008
----------------------------------------------------------------------------
Natural gas AECO
(C$/mcf) 6.27 6.03 6.36 7.46 7.81 8.12 8.96 9.81
Crude oil WTI
(US$/bbl) 70.70 70.48 60.21 58.27 67.48 69.14 69.73 69.96
----------------------------------------------------------------------------
(1) As at March 31, 2007.
Average Realized Sales Prices
Three Months Ended
----------------------------------------------------------------------------
Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)(2) 8.01 7.38 9.13
Without derivatives 7.79 6.79 9.09
Crude oil ($/bbl)(1) 61.54 57.72 54.51
Without derivatives 58.23 55.13 57.09
Natural gas liquids ($/bbl) 53.78 52.52 59.34
----------------------------------------------------------------------------
Total Oil Equivalent ($/BOE) (1) 51.60 48.02 55.17
Without derivatives 50.00 45.03 55.44
----------------------------------------------------------------------------
Realized derivative gains/(losses)
included in prices above ($/BOE) 1.60 2.99 (0.27)
----------------------------------------------------------------------------
(1) Includes derivatives gains/losses.
(2) Excludes sulphur.
Realized natural gas prices increased by 15% in the first quarter of 2007 compared
to the previous quarter, excluding the effect of derivatives.
Natural gas prices began to recover from earlier softness by late January as weather
turned cold again in North America. Record cold temperature during February resulted
in a larger than normal withdrawal of gas volume from storage. By March end, the
U.S. gas storage level has fallen to around 1.5 Tcf, below the level of last year.
Even though current gas storage is still higher than the average of the last 5 years,
the significant storage overhang that had burdened the gas market since last October
has been lifted. Going forward, weather will continue to play an important role
in determining gas supply and demand balances, as will the increased LNG import,
and the impact of reduced Canadian supply.
First quarter realized crude oil prices were 6% higher than the previous quarter,
excluding the effect of derivatives. The crude oil market started the New Year in
a similar trend as natural gas, driven down by the concerns for build up in inventory
that was caused partially by warm weather. A combination of colder temperatures
later on in the quarter, OPEC quota reduction and geopolitical events have resulted
in oil price recovery above the US $60/Bbl level by the end of March.
Sales Revenue
Three Months Ended
----------------------------------------------------------------------------
Revenue ($ Millions) Mar 31, % of Dec 31, % of Mar 31, % of
(1) (2) (3) 2007 Total 2006 Total 2006 Total
----------------------------------------------------------------------------
Natural gas $ 118.8 63 $ 106.1 62 $ 135.8 72
Crude oil 47.5 25 45.4 26 35.3 19
Natural gas liquids 21.5 12 19.9 12 18.8 9
----------------------------------------------------------------------------
Total $ 187.8 $ 171.4 $ 189.0
----------------------------------------------------------------------------
(1) Excludes sulphur.
(2) Net of transportation expenses.
(3) Excludes impact of derivatives.
First quarter 2007 revenues were 10% higher than the previous quarter mainly due
to the increases in realized crude oil and natural gas prices.
First quarter 2007 revenues were relatively flat compared to the same period in
2006, due to lower natural gas prices offset by increases to crude oil prices and
crude oil volumes.
Approximately 68% of PrimeWest's production on an energy equivalent basis is natural
gas; therefore, the Trust has greater sensitivity to changes in natural gas prices
than crude oil prices.
Financial Derivatives
As part of our risk management strategy PrimeWest uses financial instruments to
manage commodity prices. These instruments are commonly referred to as "hedges."
The purpose of the hedging program is to reduce volatility in cash flows and to
protect acquisition economics against the unpredictable commodity price environment.
PrimeWest did not elect to adopt hedge treatment for accounting purposes.
PrimeWest also entered into a financial swap which converts the interest and principal
payments associated with the U.K. Senior Notes into Canadian dollars from pounds
sterling. The pounds sterling debt and interest payable are converted to Canadian
dollars at the foreign currency exchange rate in effect at the period end date.
PrimeWest's derivatives are marked-to-market at the end of each reporting period
with the resulting change in the gain or loss from the prior period reflected in
earnings for that period. The unrealized gain is a point-in-time measurement of
PrimeWest's hedging position at the end of the period. The magnitude of the gain
or loss will fluctuate with changes to commodity prices.
The table below provides a summary of net realized and unrealized gains and losses
on financial derivatives for the three months ended March 31, 2007 and 2006.
Three Months Ended March 31, 2007
----------------------------------------------------------------------------
Foreign
($ millions except per BOE) Oil Gas Exchange Total
----------------------------------------------------------------------------
Realized gains on derivatives $ 2.7 $ 3.3 $ - $ 6.0
Unrealized losses on
derivatives (5.9) (23.4) (2.2) (31.5)
----------------------------------------------------------------------------
Total losses on derivatives $ (3.2) $ (20.1) $ (2.2) $ (25.5)
----------------------------------------------------------------------------
Realized gains on derivatives
per BOE $ 0.72 $ 0.88 $ - $ 1.60
Unrealized losses in
derivatives per BOE $ (1.57) $ (6.23) $ (0.58) $ (8.38)
----------------------------------------------------------------------------
Three Months Ended March 31, 2006
----------------------------------------------------------------------------
Foreign
($ millions except per BOE) Oil Gas Exchange Total
----------------------------------------------------------------------------
Realized gains/(losses) on
derivatives $ (1.6) $ 0.7 $ - $ (0.9)
Unrealized gains on
derivatives 0.5 21.7 - 22.2
----------------------------------------------------------------------------
Total gains/(losses) on
derivatives $ (1.1) $ 22.4 $ - $ 21.3
----------------------------------------------------------------------------
Realized gains/(losses) on
derivatives per BOE $ (0.46) $ 0.19 $ - $ (0.27)
----------------------------------------------------------------------------
Unrealized gains on
derivatives per BOE $ 0.13 $ 6.34 $ - $ 6.47
----------------------------------------------------------------------------
The following table sets forth the approximate percentage of future anticipated
production volumes hedged at March 31, 2007, net of anticipated royalties, reflecting
full production declines with no offsetting additions.
----------------------------------------------------------------------------
Production Volumes Hedged
(%) Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008
----------------------------------------------------------------------------
Crude Oil 66 64 60 39 27 14
Natural Gas 63 62 51 49 31 16
----------------------------------------------------------------------------
A listing of derivative contracts in place at March 31, 2007, follows:
Crude Oil
----------------------------------------------------------------------------
Period Volume (bbls/d) Type WTI Price (US$/bbl)
----------------------------------------------------------------------------
Apr - Jun 07 500 Costless Collar 50.00/80.00
Apr - Jun 07 500 Costless Collar 55.00/91.30
Apr - Jun 07 500 Costless Collar 55.00/90.08
Apr - Jun 07 500 Costless Collar 60.00/95.40
Apr - Jun 07 500 Costless Collar 65.00/93.90
Apr - Jun 07 1300 Costless Collar 70.00/84.25
Apr - Jun 07 500 Costless Collar 55.00/75.00
Apr - Jun 07 500 Costless Collar 60.00/73.45
Apr - Jun 07 500 Costless Collar 60.00/70.25
Apr - Jun 07 500 Costless Collar 60.00/75.65
Jul - Sep 07 500 Costless Collar 60.00/92.75
Jul - Sep 07 500 Swap 75.20
Jul - Sep 07 500 Costless Collar 65.00/92.60
Jul - Sep 07 900 Costless Collar 70.00/83.25
Jul - Sep 07 500 Costless Collar 55.00/77.80
Jul - Sep 07 500 Costless Collar 60.00/75.10
Jul - Sep 07 500 Costless Collar 60.00/73.20
Jul - Sep 07 500 Costless Collar 60.00/75.03
Jul - Sep 07 500 Costless Collar 60.00/71.25
Jul - Sep 07 500 Costless Collar 60.00/75.70
Oct - Dec 07 500 Costless Collar 60.00/90.25
Oct - Dec 07 500 Swap 74.58
Oct - Dec 07 500 Costless Collar 65.00/91.35
Oct - Dec 07 800 Costless Collar 70.00/82.10
Oct - Dec 07 500 Costless Collar 55.00/78.25
Oct - Dec 07 500 Costless Collar 60.00/76.60
Oct - Dec 07 500 Costless Collar 60.00/75.20
Oct - Dec 07 500 Costless Collar 60.00/76.60
Oct - Dec 07 500 Costless Collar 60.00/75.05
Jan - Mar 08 500 Costless Collar 55.00/78.00
Jan - Mar 08 500 Costless Collar 60.00/77.10
Jan - Mar 08 500 Costless Collar 60.00/76.60
Jan - Mar 08 500 Costless Collar 60.00/70.00
Jan - Mar 08 500 Costless Collar 60.00/75.10
Jan - Mar 08 500 Costless Collar 60.00/75.25
Apr - Jun 08 500 Costless Collar 60.00/77.35
Apr - Jun 08 500 Costless Collar 60.00/70.00
Apr - Jun 08 500 Costless Collar 60.00/75.95
Apr - Jun 08 500 Costless Collar 60.00/75.10
Jul - Sep 08 500 Costless Collar 60.00/75.05
Jul - Sep 08 500 Costless Collar 60.00/75.25
Natural Gas
----------------------------------------------------------------------------
Period Volume (mmcf/d) Type AECO Price (C$/mcf)
----------------------------------------------------------------------------
Apr - Jun 07 5.0 3 Way 6.33/7.39/11.24
Apr - Jun 07 5.0 Costless Collar 6.33/10.64
Apr - Jun 07 5.0 Costless Collar 6.33/10.23
Apr - Jun 07 5.0 Costless Collar 5.28/9.34
Apr - Jun 07 5.0 Costless Collar 6.33/11.39
Apr - Jun 07 5.0 Costless Collar 6.33/11.66
Apr - Jun 07 10.0 Swap 7.71
Apr - Jun 07 10.0 Swap 7.74
Apr - Jun 07 5.0 Swap 8.17
Apr - Jun 07 5.0 Swap 7.10
Apr - Jun 07 5.0 Swap 7.41
Apr - Jun 07 5.0 Costless Collar 6.86/8.55
Apr - Jun 07 5.0 Costless Collar 6.86/8.55
Jul - Sep 07 5.0 Costless Collar 6.33/11.61
Jul - Sep 07 5.0 Costless Collar 6.33/10.87
Jul - Sep 07 5.0 Costless Collar 5.28/10.02
Jul - Sep 07 5.0 Costless Collar 6.33/12.05
Jul - Sep 07 5.0 Costless Collar 6.33/12.45
Jul - Sep 07 10.0 Swap 7.90
Jul - Sep 07 10.0 Swap 7.90
Jul - Sep 07 5.0 Swap 8.33
Jul - Sep 07 5.0 Costless Collar 6.33/8.81
Jul - Sep 07 5.0 Swap 7.64
Jul - Sep 07 5.0 3 Way 6.33/7.39/9.29
Jul - Sep 07 5.0 Costless Collar 6.86/9.18
Oct - Dec 07 5.0 Costless Collar 7.39/12.28
Oct - Dec 07 5.0 Costless Collar 5.28/12.66
Oct - Dec 07 5.0 Costless Collar 7.39/12.77
Oct - Dec 07 5.0 Costless Collar 7.39/13.40
Oct - Dec 07 10.0 Costless Collar 7.39/9.84
Oct - Dec 07 10.0 Costless Collar 7.39/10.29
Oct - Dec 07 5.0 Costless Collar 7.39/9.71
Oct - Dec 07 5.0 Costless Collar 7.39/10.76
Oct - Dec 07 5.0 Costless Collar 7.39/10.60
Jan - Mar 08 5.0 Costless Collar 6.33/12.71
Jan - Mar 08 5.0 Costless Collar 8.44/15.67
Jan - Mar 08 10.0 Costless Collar 7.39/12.40
Jan - Mar 08 10.0 Costless Collar 7.39/11.61
Jan - Mar 08 5.0 Costless Collar 7.39/11.56
Jan - Mar 08 5.0 Costless Collar 7.39/11.61
Jan - Mar 08 5.0 Costless Collar 7.39/12.55
Jan - Mar 08 5.0 Costless Collar 7.39/12.87
Apr - Jun 08 10.0 Costless Collar 7.39/8.97
Apr - Jun 08 5.0 Costless Collar 6.33/9.76
Apr - Jun 08 5.0 Costless Collar 7.39/8.91
Apr - Jun 08 5.0 3 Way 6.33/7.39/10.13
Apr - Jun 08 5.0 Costless Collar 7.39/8.97
Apr - Jun 08 5.0 Costless Collar 7.39/9.50
Jul - Sep 08 5.0 Costless Collar 7.39/9.39
Jul - Sep 08 5.0 Costless Collar 7.39/9.50
Jul - Sep 08 5.0 3 Way 6.33/7.39/10.97
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 $11.24, purchased a put at $7.39, and resold
the put at $6.33. Should the market price drop below $7.39, PrimeWest will receive
$7.39 until the price is less than $6.33, at which time PrimeWest will then receive
market price plus $1.06. However, should market prices rise above $11.24, PrimeWest
will receive a maximum of $11.24. Should the market price remain between $7.39 and
$11.24, PrimeWest will receive the market price.
Foreign Exchange
----------------------------------------------------------------------------
Amount
Period Pounds Sterling (000's) Type Price
----------------------------------------------------------------------------
Principal 63,000 $2.0748 Cdn per Pounds
Apr -Jun 2016 Interest 34,474 Swap Sterling 1.00
----------------------------------------------------------------------------
Royalties
PrimeWest pays Crown, freehold and overriding royalties to the owners of mineral
rights with whom PrimeWest holds leases. These royalties vary for each property
and product. The Crown royalty system is based on a sliding scale structure that
increases the royalty rates as commodity prices rise. Because of the sliding scale
Crown royalty system, future changes to commodity prices will result in changes
to royalty rates and expenses. In certain situations, the Crown grants royalty "holidays"
which eliminate royalties on specific wells.
Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Royalty expense $ 40.0 $ 33.7 $ 44.7
Per BOE $ 10.65 $ 8.86 $ 13.04
Royalties as a % of sales revenues 21.3% 19.7% 23.5%
----------------------------------------------------------------------------
Operating Expenses
Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Operating expense $ 38.9 $ 39.6 $ 32.7
Per BOE $ 10.36 $ 10.40 $ 9.54
----------------------------------------------------------------------------
First quarter 2007 operating expense totalled $38.9 million, a decrease of 2% from
$39.6 million in the fourth quarter 2006. On a per BOE basis operating expenses
decreased slightly from the previous quarter.
Year over year operating expense and operating expense per BOE increased in the
first quarter of 2007 compared to the same period in 2006 due to the impact of the
U.S. assets on operating costs, which are higher than the Canadian assets' operating
costs, and to the impact of inflationary pressures on the prices of goods and services.
Operating Expense Outlook
PrimeWest anticipates that its full year operating expense will be
approximately $10.00 per BOE.
Operating Margin
Three Months Ended
----------------------------------------------------------------------------
$ per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Sales price and other revenue (1) $ 50.49 $ 45.17 $ 55.95
Royalties $ (10.65) $ (8.86) $ (13.04)
Operating expense $ (10.36) $ (10.40) $ (9.54)
----------------------------------------------------------------------------
Operating margin before realized
derivative gains/(losses) $ 29.48 $ 25.91 $ 33.37
Realized derivative gain/loss $ 1.60 $ 3.34 $ (0.27)
----------------------------------------------------------------------------
Operating margin after realized
derivative gains/(losses) $ 31.08 $ 29.25 $ 33.10
----------------------------------------------------------------------------
(1) Includes sulphur.
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 operating margin per BOE increased in the first quarter of 2007 compared to
the previous quarter mainly due to an increase in realized commodity prices partially
offset by higher royalties.
First quarter 2007 operating margin was lower than the same period in 2006 due to
lower natural gas prices and increases in operating costs partially offset by lower
royalties.
General & Administrative Expense
Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
G&A expense $ 9.3 $ 8.6 $ 6.7
Per BOE $ 2.47 $ 2.27 $ 1.97
----------------------------------------------------------------------------
G&A expense in the first quarter of 2007 increased by 8% compared to the previous
quarter mainly due to the increase in the amount of the semi-annual Unit Appreciation
Rights (UARs) grant under the LTIP.
First quarter 2007 G&A expense was 39% higher when compared to the first quarter
of 2006 due to increases in labour costs, audit fees, costs associated with the
Denver office, and reductions in overhead recoveries. G&A expense per BOE for the
three months ended March 31, 2007, was 25% higher than the same period in the prior
year due to higher G&A expense offset partially by increases to production volumes.
Included in G&A expense for the three ended March 31, 2007, was $1.7 million relating
to the (UARs), granted under the LTIP. UARs in the Trust are similar to stock options
in a corporation. The program rewards employees based on total Unitholder return,
which is comprised of cumulative distributions on a reinvested basis plus growth
in Unit price. No benefit accrues to the UARs until the Unitholders have first achieved
a 5% total annual return from the time of grant. PrimeWest continues to pay for
the exercise of UARs in Trust Units. Also included in G&A expense is $0.3 million
for the three months ended March 31, 2007, related to the Special Employee Retention
Plan (SERP). See note 15 to the Consolidated Financial Statements in the 2006 Annual
Report.
Interest Expense
Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per
Trust Unit Amounts and Cost
of Debt Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Interest expense $ 12.2 $ 13.0 $ 4.6
Period end net debt level (1) $ 716.3 $ 820.8 $ 364.5
Debt per Trust Unit $ 7.81 $ 9.74 $ 4.42
Average cost of debt% 5.8% 5.9% 5.0%
----------------------------------------------------------------------------
(1) Excludes derivative and future income tax assets and liabilities
included in current assets and liabilities.
Interest expense, representing interest on bank debt, the U.S. Secured Notes, the
U.K. Secured Notes and the Debentures decreased in the first quarter of 2007 compared
to the fourth quarter of 2006 due to the decrease in the average net debt balance
as proceeds from the January equity offering were used to repay a portion of the
outstanding credit facility.
Interest expense was higher for the three months ended March 31, 2007, compared
to the same period in 2006 due to higher average debt balances resulting from additional
borrowing against the credit facility to finance the U.S. asset acquisition in the
third quarter of 2006.
The average cost of debt was higher for the three months ended March 31, 2007,compared
to the same period in 2006, primarily due to an increase in banker's acceptance
rates which are the basis for calculating interest on the Canadian portion of the
credit facility. The drawdown under the U.S. portion of the credit facility, to
acquire the U.S. assets in 2006, which bears interest at the London Inter Bank Offer
Rate (LIBOR), which is higher than the Canadian rate, also increased the average
cost of debt.
Foreign Exchange
The foreign exchange gain of $2.1 million for the three months ended March 31, 2007,
resulted from the translation of the U.S. dollar denominated Secured Notes, the
U.K. Secured Notes and related interest payable into Canadian dollars.
Depletion, Depreciation and Amortization
Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Depletion, depreciation and
amortization $ 66.9 $ 68.5 $ 53.9
Per BOE $ 17.82 $ 17.98 $ 15.75
----------------------------------------------------------------------------
The DD&A rate for the three months ended March 31, 2007, increased by 13% when compared
to the same period in the prior year due to an increase in future development costs
which are included in the calculation of DD&A. The increase in future development
costs reflects the high level of activity throughout the industry which has resulted
in increased capital costs. The DD&A rate will fluctuate from one period to the
next depending on the amount and type of capital spending and the amount of reserves
added. Expenditures on maintenance capital, land and seismic do not contribute to
reserve additions and may cause DD&A rates per BOE to increase disproportionately.
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 2007 contribution rate remains
unchanged from 2006 at $0.50 per BOE resulting in $1.7 million being contributed
to the fund in the first quarter. Additional contributions will be made to the fund
in 2007 to accommodate the recent increase in expenditures.
As at March 31, 2007, the site reclamation fund contained a balance of $0.5 million.
The abandonment and reclamation costs incurred in the first quarter 2007 were $3.8
million, compared to $1.9 million for the same period in 2006, and $5.3 million
for the previous quarter.
Income and Capital Taxes
Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Income and capital taxes $ 0.2 $ 1.6 $ 0.6
Future income tax recovery $ (16.3) $ (4.5) $ (0.7)
----------------------------------------------------------------------------
Total $ (16.1) $ (2.9) $ (0.1)
----------------------------------------------------------------------------
The future income tax recovery for the three months ended March 31, 2007, increased
to $16.3 million from $4.5 million in the previous quarter and $0.7 in the first
quarter of 2006 due to a reduction in net income before taxes.
Net Income
Three Months Ended
----------------------------------------------------------------------------
$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Net income $ 5.5 $ 9.6 $ 68.9
----------------------------------------------------------------------------
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, 2007, of $5.5 million was 43% lower
than the previous quarter's net income of $9.6 million primarily due to increases
in the change in unrealized loss on derivatives of $37.0 million, debt issue costs
of $8.0 million relating to the debentures issued in January and a lower realized
gain on derivatives of $6.7 million. These losses were partially offset by increases
to the foreign exchange gain of $20.6 million and future income tax recoveries of
$11.8 million.
Net income for the first quarter of 2007 was $5.5 million compared to $68.9 million
in the same period of 2006 primarily due to the change in unrealized loss on derivatives
of $53.7 million, increases to interest expense of $7.6 million, debt issue costs
of $8.0 million and DD&A of $13.0 million partially offset by increases to future
income tax recoveries of $15.6 million.
Liquidity & Capital Resources
Long-Term Debt
As at
----------------------------------------------------------------------------
$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Long-term debt $ 716.3 $ 619.4 $ 321.6
Deficit (1) $ - $ 201.4 $ 42.9
----------------------------------------------------------------------------
Net debt $ 716.3 $ 820.8 $ 364.5
Market value of Trust Units and
Exchangeable Shares outstanding
(2)(3) $ 2,070.8 $ 1,805.9 $ 2,681.7
----------------------------------------------------------------------------
Total capitalization $ 2,787.1 $ 2,626.7 $ 3,046.2
----------------------------------------------------------------------------
Net debt as a % of total
capitalization 26% 31% 12%
----------------------------------------------------------------------------
(1) Excludes derivative and future income tax assets and liabilities
included in current assets or liabilities.
(2) Based on March 31, 2007, Trust Unit closing price of $22.72 and
March 15, 2007, exchange ratio of 0.65910:1.
(3) Excludes the Debentures.
Long-term debt is comprised of senior bank credit facilities, the U.S. Secured Notes,
the U.K. Secured Notes and the Debentures of $233.3 million, $144.3 million, $143.0
million and $231.8 million respectively. $36.1 million relating to the U.S. Secured
Notes was included in working capital as a current portion of long-term debt. In
addition to amounts outstanding under the bank credit facility, PrimeWest has outstanding
letters of credit in the amount of $2.9 million (2006 - $6.8 million).
The indebtedness under the senior credit facilities, the U.S. Secured Notes and
the U.K. Secured Notes is supported by a borrowing base of $750 million and is comprised
of Canadian revolving facilities having a borrowing limit of $220.5 million, the
U.S. bank revolving credit facilities having a borrowing limit of Cdn $255.0 million,
the U.S. Secured Notes valued at $143.8 million based on a U.S. dollar exchange
rate of U.S. $0.87 and the U.K. Secured Notes valued at Cdn $130.7 million.
On January 11, 2007, PrimeWest issued $200 million of Series III Convertible Unsecured
Debentures for net proceeds of $192.0 million. The Debentures bear interest at 6.5
% payable semi-annually at January 31 and July 31 commencing July 31, 2007. The
Debentures are convertible at any time at the option of the debenture holder into
PrimeWest Trust units at a conversion price of $26.25 per Trust unit prior to maturity
on January 31, 2012. The Debentures may be redeemed in whole or in part at the option
of the Trust at a price of $1,050 per Debenture after February 1, 2010, and on or
before January 31, 2011, and at a price of $1,025 per Debenture after February 1,
2011, and on or before January 31, 2012. On redemption or maturity the Trust may
opt to satisfy its obligations to repay the principal by issuing PrimeWest Trust
Units.
At March 31, 2007, PrimeWest's net debt to annualized first quarter cash flow was
approximately 1.9 times compared to 2.4 times annualized fourth quarter 2006 cash
flow at December 31, 2006. Net debt as a percentage of total capitalization was
26% at March 31, 2007, compared to 31% at December 31, 2006.
Unitholders' Equity
At March 31, 2007, the Trust had 90,378,337 Trust Units outstanding. In addition,
PrimeWest had 1,161,568 Exchangeable Shares outstanding that are exchangeable into
a total of 765,589 Trust Units using the March 15, 2007, exchange ratio of 0.65910:1.
On January 11, 2007, PrimeWest issued 6,420,000 Trust Units for net proceeds of
$142.4 million.
The DRIP gives Canadian and U.S. Unitholders the opportunity to reinvest their monthly
distributions at a 5% discount to the volume-weighted average market price of the
Trust Units. As an alternative to the DRIP component of the Plan, the PREP allows
eligible Canadian Unitholders to elect to receive a premium cash distribution of
up to 102% of the cash that the Unitholder would otherwise have received on the
distribution date, subject to proration in certain events. The OTUPP gives Canadian
Unitholders an opportunity to purchase additional Trust Units directly from PrimeWest
at the same 5% discount. The DRIP and PREP components are mutually exclusive. Participation
in the OTUPP requires enrolment in either the DRIP or PREP. During the first quarter
of 2007, PrimeWest issued 206,971 Trust Units under the DRIP for $4.3 million, 305,278
Trust Units for $6.4 million pursuant to the PREP and 173,868 Trust Units for $3.6
million pursuant to the OTUPP.
These plan components benefit Unitholders by offering alternatives to maximize their
investment in PrimeWest, while providing the Trust with a relatively inexpensive
method of raising additional capital. 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 certain acquisitions and as part
of PrimeWest's management internalization transaction. Exchangeable shares continue
to be issued to certain Executive Officers pursuant to a Special Employee Retention
Plan (SERP) instituted as part of the management internalization transaction.
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, 2007, there were 1,161,568 Exchangeable Shares outstanding. The exchange
ratio on these shares was 0.65910:1 Trust Units for each Exchangeable Share as at
March 31, 2007. For purposes of calculating basic per Trust Unit amounts, it is
assumed that the Exchangeable Shares have been exchanged into Trust Units at the
current exchange ratio.
Cash Distributions
Cash distributions to Unitholders are at the discretion of the Board of Directors
and can fluctuate depending on the 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
vary from such targets due to fluctuations in commodity prices and their impact
on cash flow forecasts, as well as other factors. The current distribution payout
ratio is targeted to be approximately 70-90% of annual funds flow from operations.
The October 31, 2006, proposals by the federal government to change the way royalty
trusts and income funds are taxed has created additional uncertainty with respect
to the payout ratio. At this time, PrimeWest is unable to predict what payout rate
it will maintain in the future. In the first quarter of 2007, cash distributions
totalled $67.6 million, or $0.75 per Trust Unit representing a payout ratio of approximately
72% of funds flow from operations, compared to $62.3 million, or $0.75 per Trust
Unit (74% payout ratio) in the previous quarter and $86.7 million or $1.08 per Trust
unit (84% payout ratio) in the first quarter of 2006.
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 2007 through 2024 and various pipeline transportation
commitments that run through 2013. The details of the timing of these contractual
obligations are included in the following table.
As at March 31, 2007 Payments due by period
----------------------------------------------------------------------------
Less than More than
$ Millions Total 1 year 1-3 years 4-5 years 5 years
----------------------------------------------------------------------------
Long-term debt obligations 520.6 36.1 305.4 36.1 143.0
Debentures 238.4 - 23.7 14.7 200.0
Interest (1) 94.3 15.8 26.3 17.6 34.6
Lease rental obligations 83.5 3.8 5.1 9.6 65.0
Pipeline transportation
obligations 4.8 3.7 0.8 0.3 -
----------------------------------------------------------------------------
Total contractual
obligations 941.6 59.4 361.3 78.3 442.6
----------------------------------------------------------------------------
(1) Includes interest on the U.S. Secured Notes, U.K. Secured Notes and the
Debentures assuming foreign exchange rates in effect as at March 31,
2007.
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, 2005 and 2006, 94,340 Exchangeable
Shares were issued to those officers. An additional 94,340 Exchangeable Shares will
be issued on November 6, 2007. For the three months ended March 31, 2007, $0.3 million
has been recorded in G&A expenses related to the SERP.
In October 2006, PrimeWest entered into an agreement containing a new office lease
rental commitment that runs from 2010 to 2024. Payments that will become due under
this agreement will commence in mid-2010 at approximately $4.7 million per year
and will escalate by approximately $0.2 million every three years until 2021, at
which point they will increase by $0.1 million per year for the final three years
of the term of the commitment. The agreement contains customary additional obligations
regarding the responsibility of PrimeWest for tenant improvements.
Future Accounting Changes
The CICA has issued the following accounting standards which will be effective January
1, 2008: Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial
Instruments - Presentation" and Section 1535 "Capital Disclosures."
These new accounting standards will require the Trust to provide additional disclosures
relating to its financial instruments, including hedging instruments, and the Trust's
capital. Section 3863 does not change the presentation guidance provided in Section
3861 "Financial Instruments - Disclosure and Presentation" which it replaces. It
is not anticipated that the adoption of these new accounting standards will impact
the amounts reported in the Trust's financial statements as they primarily relate
to disclosure.
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 2007 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 2007, PrimeWest realized a $6.0 million gain from commodity hedges.
Taxation of the Trust
On October 31, 2006, the Minister of Finance (Canada) ("Finance") announced proposed
changes to the taxation of certain publicly-traded trusts and partnerships and their
unitholders. These changes, assuming they are enacted, would apply, in the case
of trusts, to a trust that is resident in Canada for purposes of the Tax Act, holds
one or more "non-portfolio properties", and the units of which are listed on a stock
exchange or other public market (a "specified investment flow-through trust", or
"SIFT trust"). In the case of a SIFT trust the units of which were already publicly
traded on October 31, 2006, the proposed changes generally would not take effect
until January 1, 2011, provided the trust experiences only "normal growth" and no
"undue expansion" before then. On December 15, 2006, Finance issued guidelines with
respect to what would be considered "normal growth" for this purpose, and on December
21, 2006, Finance released draft legislative proposals to implement the changes
previously announced on October 31, 2006. On January 30, 2007, Finance confirmed
the Government's intention to proceed with these proposals. The October 31, 2006
proposals, December 15, 2006 guidelines and December 21, 2006 draft legislation,
are hereinafter collectively referred to as the "October 31 Proposals".
Until such time as the October 31 Proposals apply to the Trust, which is not expected
to be until January 1, 2011, it is expected that:
- The Trust will continue not to be liable for any material amount of Canadian income
tax;
- Returns on capital will generally be taxed as ordinary income or as dividends
in the hands of a Unitholder who is resident in Canada for purposes of the Tax Act,
and will be subject to withholding tax at a rate of 25% (subject to a reduction
in such rate under the terms of an applicable tax treaty or convention) when paid
to a non-resident Unitholder;
- Returns of capital paid to a Unitholder who is resident in Canada for purposes
of the Tax Act generally will not be included in the Unitholder's income but will
reduce the adjusted cost base of the Unitholder's Trust Units; and
- Returns of capital paid to a non-resident Unitholder will be subject to the special
15% Canadian withholding tax under Part XIII.2 of the Tax Act.
Pursuant to the October 31 Proposals, commencing January 1, 2011, the Trust will
be subject to tax on its income from non-portfolio properties and taxable capital
gains from dispositions of non-portfolio properties, that is paid or payable to
Unitholders, at a rate of 31.5% (comparable to the projected combined federal and
provincial corporate income tax rate in 2011), and distributions of such income
to Unitholders will be treated as dividends paid by a taxable Canadian corporation.
The Royalty and the shares and notes of PrimeWest will constitute "non-portfolio
properties" of the Trust under the October 31 Proposals, with the result that virtually
all of the Trust's income, including any taxable capital gains, would be subject
to the 31.5% tax, and distributions of such income by the Trust to its Unitholders
would be treated as dividends paid by a taxable Canadian corporation. Returns of
capital by the Trust to its Unitholders would not be affected by the October 31
Proposals and would continue to be taxed in the same manner as under the current
rules.
As noted above, the Trust could become subject to these changes before 2011 if it
experiences growth, other than "normal growth", before that time. Under the December
15, 2006 guidelines, the Trust will be considered to have experienced only "normal
growth" if its issuances of new equity (which for this purpose includes Trust Units
and debt that is convertible into Trust Units, but does not include non-convertible
debt) do not exceed, for each of the intervening periods set forth below, a safe
harbour measured by reference to the Trust's market capitalization as of the end
of trading on October 31, 2006 (measured solely by the value of the Trust's issued
and outstanding publicly-traded Trust Units as of that date). The Trust's market
capitalization as of October 31, 2006, was approximately $2.379 billion. The intervening
periods and their respective safe harbour amounts are as follows:
- November 1, 2006 to December 31, 2007 - 40% of the Trust's market capitalization
as of October 31, 2006;
- January 1, 2008 to December 31, 2008 - 20% of the Trust's market capitalization
as of October 31, 2006;
- January 1, 2009 to December 31, 2009 - 20% of the Trust's market capitalization
as of October 31, 2006;
- January 1, 2010 to December 31, 2010 - 20% of the Trust's market capitalization
as of October 31, 2006.
The December 15, 2006 guidelines provide that these annual safe harbour amounts
are cumulative, and that replacing debt that was outstanding as of October 31, 2006
with new equity, whether through a debenture conversion or otherwise, will not be
considered growth for these purposes. In addition, an issuance of new equity will
not be considered growth to the extent that the issuance is made in satisfaction
of the exercise by another person of a right in place on October 31, 2006 to exchange
an interest in a partnership, or a share of a corporation, for Trust Units.
Operational And Other Business Risks
PrimeWest is also exposed to a number of risks related to its activities within
the oil and gas industry that have an impact on the amount of cash available to
Unitholders. These risks, and the manner in which PrimeWest seeks to mitigate these
risks include, but are not limited to:
----------------------------------------------------------------------------
Risk We Mitigate By
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production
Risk associated with the production Performing regular and proactive
of oil and gas - includes well protective well, facility and
operations, processing and the pipeline maintenance supported by
physical delivery of commodities to telemetry, physical inspection and
market. diagnostic tools.
----------------------------------------------------------------------------
Commodity Price
Fluctuations in natural gas, crude Hedging. See page 9 of this
oil and natural gas liquids prices. quarterly report.
----------------------------------------------------------------------------
Transportation
Market risk related to the Diversifying the transportation
availability of transportation to systems on which we rely to get our
market and potential disruption in product to market.
delivery systems.
----------------------------------------------------------------------------
Natural Decline
Development risk associated with Diversifying our capital spending
capital enhancement activities program over a large number of
undertaken - the risk that capital projects so that large amounts of
spending on activities such as capital are not risked on any one
drilling, well completions, well activity. We also have a highly
workovers and other capital skilled technical team of geologists,
activities will not result in geophysicists and engineers working
reserve additions or in quantities to apply the latest technology in
sufficient to replace annual planning and executing capital
production declines. programs. Capital is spent only after
strict economic criteria for
production and reserve additions are
assessed.
----------------------------------------------------------------------------
Acquisitions
Acquisition risk associated with Continually scanning the marketplace
acquiring producing properties at for opportunities to acquire assets.
low cost to renew our inventory of Our technical acquisition specialists
assets. evaluate potential corporate or
property acquisitions and identify
areas for value enhancement through
operational efficiencies or capital
investment. All prospects are
subjected to rigorous economic review
against established acquisition and
economic hurdle rates. In some cases
we may also hedge commodity prices to
protect the acquisition economics in
the near term period.
----------------------------------------------------------------------------
Reserves
Reserve risk in respect of the Contracting our reserves evaluation
quantity and quality of recoverable to a reputable third party
reserves. consultant, GLJ Petroleum Consultants
Ltd (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.
----------------------------------------------------------------------------
Environmental Health and Safety
(EH&S)
Environmental, health and safety Establishing and adhering to strict
risks associated with oil and gas guidelines for EH&S including
properties and facilities. training, proper reporting of
incidents, supervision and awareness.
PrimeWest has active community
involvement in field locations
including regular meetings with
stakeholders in the area. PrimeWest
carries adequate insurance to cover
property losses, liability and
business interruption.
These risks are reviewed regularly by
the Operations and Reserves
Committee of the Board.
----------------------------------------------------------------------------
Regulation, Tax and Royalties
Changes in government regulations Keeping informed of proposed changes
including reporting requirements, in regulations and laws to properly
income tax laws, operating practices, respond to and plan for the effects
environmental protection requirements that these changes may have on our
and royalty rates. operations.
----------------------------------------------------------------------------
Historical Liability to Unitholders
is Uncertain
Because of uncertainties in the law On July 1, 2004, a new statute
prior to July 1, 2004, relating to entitled the Income Trusts Liability
investments in trusts, there is a Act (Alberta) was proclaimed in
risk that a Unitholder could be held force, creating a statutory
personally liable for obligations of limitation on the liability of
the Trust. Unitholders of Alberta income
trusts such as PrimeWest. The
legislation provides that a
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
----------------------------------------------------------------------------
($ millions) Mar 31, 2007 Dec 31, 2006
----------------------------------------------------------------------------
ASSETS (unaudited)
Current Assets
Cash and cash equivalents $ 78.1 $ 22.0
Accounts receivable 99.8 104.5
Derivative assets (note 6) 0.8 23.5
Future income taxes 2.6 2.3
Prepaid expenses 17.7 19.6
Inventory 0.6 0.3
----------------------------------------------------------------------------
199.6 172.2
Cash reserved for site restoration and
reclamation 0.5 2.2
Other assets and deferred charges (note 2) 0.2 7.4
Derivative assets (note 6) 0.9 5.3
Property, plant and equipment 2,350.1 2,332.9
Goodwill 68.5 68.5
----------------------------------------------------------------------------
$ 2,619.8 $ 2,588.5
----------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 141.2 $ 143.3
Current portion of long-term debt (note 4) 36.1 186.4
Future income taxes - 8.7
Derivative liabilities (note 6) 4.4 -
Accrued distributions to Unitholders 18.9 18.1
----------------------------------------------------------------------------
200.6 356.5
Long-term debt (note 4) 716.3 619.4
Future income taxes 146.9 153.9
Asset retirement obligation (note 3) 92.6 91.5
----------------------------------------------------------------------------
1,156.4 1,221.3
UNITHOLDERS' EQUITY
Net capital contributions (note 5) 2,548.1 2,391.2
Capital issued but not distributed 3.6 2.7
Convertible Unsecured Subordinated Debentures 8.8 1.2
Contributed surplus (note 7) 13.5 11.9
Accumulated other comprehensive income 4.8 6.2
Deficit (note 8) (1,115.4) (1,046.0)
----------------------------------------------------------------------------
1,463.4 1,367.2
----------------------------------------------------------------------------
$ 2,619.8 $ 2,588.5
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
----------------------------------------------------------------------------
Three months ended ($ millions) Mar 31, 2007 Mar 31, 2006
----------------------------------------------------------------------------
OPERATING ACTIVITIES (unaudited) (unaudited)
Net income for the period $ 5.5 $ 68.9
Add/(deduct) items not involving cash from
operations:
Depletion, depreciation and amortization 66.9 53.9
Non-cash general and administrative 2.0 1.4
Non-cash foreign exchange (gain)/loss (2.1) 0.6
Unrealized loss/(gain) on derivatives 31.5 (22.2)
Future income tax recovery (16.3) (0.7)
Accretion of asset retirement obligation 1.6 0.7
Other non-cash items 0.5 0.6
Debt issue costs 8.0 -
Expenditures on site restoration and reclamation (3.8) (1.9)
----------------------------------------------------------------------------
Funds flow from operations 93.8 101.3
Change in non-cash working capital (3.3) 23.2
----------------------------------------------------------------------------
90.5 124.5
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust Units (net of costs) 146.0 5.7
Proceeds from issue of Debentures (net of costs) 192.0 -
Net cash distributions to Unitholders (55.8) (74.4)
Decrease in bank credit facilities (242.0) (26.0)
Change in non-cash working capital 7.1 (2.3)
----------------------------------------------------------------------------
47.3 (97.0)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (72.6) (82.6)
Acquisition of capital assets (11.5) (0.2)
Proceeds on disposal of property, plant and
equipment - 3.1
Decrease in cash reserved for future site
reclamation 1.7 0.1
Change in non-cash working capital 0.7 18.5
----------------------------------------------------------------------------
(81.7) (61.1)
----------------------------------------------------------------------------
Increase/(decrease) in cash and cash equivalents
for the period 56.1 (33.6)
Cash and cash equivalents, beginning of period 22.0 36.8
----------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 78.1 $ 3.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash interest paid $ 4.8 $ 2.7
----------------------------------------------------------------------------
Cash taxes paid $ 0.4 $ 0.7
----------------------------------------------------------------------------
Non-cash transactions - conversion of debentures
into Trust Units $ 0.1 $ 7.6
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
----------------------------------------------------------------------------
Three months ended ($ millions, except per Trust
Unit amounts) Mar 31, 2007 Mar 31, 2006
----------------------------------------------------------------------------
REVENUES (unaudited) (unaudited)
Sales of crude oil, natural gas and natural gas
liquids $ 189.7 $ 192.0
Crown and other royalties (40.0) (44.7)
Realized gain/(loss) on derivatives 6.0 (0.9)
Change in unrealized (loss)/gain on derivatives (31.5) 22.2
Other income 1.8 1.4
----------------------------------------------------------------------------
126.0 170.0
----------------------------------------------------------------------------
EXPENSES
Operating 38.9 32.7
Transportation 1.8 1.9
General and administrative 9.3 6.7
Interest 12.2 4.6
Debt issue 8.0 -
Depletion, depreciation and amortization 66.9 53.9
Accretion of asset retirement obligation
(note 3) 1.6 0.7
Foreign exchange (gain)/loss (2.1) 0.7
----------------------------------------------------------------------------
136.6 101.2
----------------------------------------------------------------------------
Income before taxes for the period (10.6) 68.8
----------------------------------------------------------------------------
Income and capital taxes 0.2 0.6
Future income taxes recovery (16.3) (0.7)
----------------------------------------------------------------------------
(16.1) (0.1)
----------------------------------------------------------------------------
Net income for the period $ 5.5 $ 68.9
Other comprehensive income
Unrealized foreign exchange loss on translation
of self sustaining foreign operations (1.0) -
Tax effect on unrealized foreign exchange loss
on translation of self sustaining foreign
operations (0.4) -
----------------------------------------------------------------------------
Other comprehensive income $ (1.4) $ -
----------------------------------------------------------------------------
Comprehensive income $ 4.1 $ 68.9
----------------------------------------------------------------------------
Net income per Trust Unit - basic (note 5) $ 0.06 $ 0.85
Net income per Trust Unit - diluted (note 5) $ 0.06 $