PrimeWest Energy Trust Announces Second Quarter 2007 Results
AUG 1, 2007 - 16:39 ET
CALGARY, ALBERTA--(Marketwire - Aug. 1, 2007) - PRIMEWEST ENERGY TRUST (PRIMEWEST
OR THE TRUST) (TSX:PWI.UN) (TSX:PWX) (TSX:PWI.DB.A) (TSX:PWI.DB.B) (TSX:PWI.DB.C)
(NYSE:PWI) TODAY ANNOUNCES INTERIM OPERATING AND FINANCIAL RESULTS FOR THE QUARTER
ENDED JUNE 30, 2007. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT
ARE IN CANADIAN DOLLARS.
Second Quarter 2007 Highlights:
- Distributions in the second quarter were $0.75 per PrimeWest Trust Unit (Trust
Unit) representing a payout ratio of approximately 66% of funds flow from operations.
- Funds flow from operations for the second quarter was $103.5 million ($1.15 per
Trust Unit) compared to $85.8 million ($0.95 per Trust Unit) in the previous quarter
and $86.8 million ($1.06 per Trust Unit) in the second quarter of 2006.
- Second quarter 2007 production averaged 40,226 BOE per day, compared to the first
quarter 2007 rate of 41,748 BOE per day. The decrease in volumes is mainly due to
turnarounds, asset sales and natural decline exceeding incremental volumes additions
from development capital spending. PrimeWest expects full year 2007 production volumes
to average approximately 50,000 BOE per day which includes the impact of divestitures
and the Shiningbank merger for the remaining six months of 2007. The exit production
rate at the end of 2007 is expected to be approximately 59,000 BOE per day.
- Operating expense was $34.6 million ($9.46 per BOE) in the second quarter of 2007
compared to $38.9 million ($10.36 per BOE) in the first quarter of 2007. The decrease
in operating expense is mainly due to lower well servicing and repair and maintenance
costs, decreases in power costs, increases to processing income and the impact of
asset sales. PrimeWest expects full year operating expense per BOE to be approximately
$9.50 per BOE including the impact of the Shiningbank merger.
- Development capital expenditures in the second quarter were $33.0 million with
drilling, completion and tie-in expenditures of $24.0 million. Three wells were
drilled in Flat Lake, Montana and several wells were completed and tied at Wilson
Creek, Caroline and Crossfield. Full year development capital expenditures are expected
to be approximately $250 million.
- In the second quarter of 2007, PrimeWest initiated a divestment program of approximately
1,700 BOE per day which will generate net proceeds of approximately $104 million.
At June 30, 2007, net proceeds of $47.6 million had been received. The remaining
proceeds will be received in the third quarter. PrimeWest intends to initiate an
additional divestment program of approximately 1,800 BOE per day in the third quarter
of 2007 to be completed by year end.
- Net debt to annualized second quarter 2007 funds flow from operations was approximately
1.5 times at June 30, 2007, compared to net debt to annualized first quarter 2007
funds flow from operations of 2.1 times at March 31, 2007.
Subsequent Event
- On July 11, 2007, PrimeWest Energy Trust merged with Shiningbank Energy Income
Fund (Shiningbank). Shiningbank Trust Units were exchanged for 0.62 of a PrimeWest
Trust Unit. The combined entity will have production weighted 70% to natural gas
and 30% to crude oil and natural gas liquids. Projected funds flow from operations
and proceeds from the PrimeWest DRIP and dispositions are expected to be sufficient
to adequately fund development activities for 2007 without the need for incremental
debt, assuming a payout rato of 60% - 75% of funds flow from operations. This transaction
directionally moves PrimeWest towards a business model where future development
capital spending and distributions are generally expected to be financed with funds
flow from operations.
- Upon the completion of the merger with Shiningbank on July 11, 2007, PrimeWest
entered into a new 3-year unsecured extendible revolving credit facility with a
syndicate of chartered banks and other financial institutions. The credit facility
provides for Cdn $1.1 billion of credit capacity for PrimeWest's operations in Canada
and US $235 million of credit capacity for PrimeWest's operations in the United
States (US).
MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF AUGUST 1, 2007
The following is management's discussion and analysis (MD&A) of PrimeWest's operating
and financial results for the three and six months ended June 30, 2007, compared
with the preceding quarter and the corresponding periods 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 may contain 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 may 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;
- The goal to adequately fund development activities and distributions for any period
from funds flow from operations;
- Our treatment under governmental regulatory regimes;
- The focus of capital expenditures on development activity rather than exploration;
- The sale, farming in, farming out or development of certain exploration properties
using third-party resources;
- The objective to achieve a predictable level of monthly cash distributions;
- The use of development activity and acquisitions to replace and add to reserves;
- The impact of changes in oil and natural gas prices on cash flow after hedging;
- Drilling plans;
- The existence, operations and strategy of the commodity price risk management
program;
- The approximate and maximum amount of forward sales and hedging to be employed;
- Our acquisition strategy, the criteria to be considered in connection therewith
and the benefits to be derived therefrom;
- The impact of the Canadian federal and provincial governmental 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, natural gas prices and natural gas liquids 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, natural gas and natural gas liquids;
- 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 US 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;
- Increasing globalization of natural gas supply and demand;
- 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 Business Risks 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, Donald A. Garner, and the Chief Financial Officer,
Douglas S. Fraser, evaluated the effectiveness of PrimeWest's disclosure controls
and procedures as of June 30, 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 US Securities
and Exchange Commission (SEC) in the US 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 controls over financial reporting
since March 31, 2007, 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 to finance operations and to 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 June 30, 2007.
Business Strategy
PrimeWest 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 US. 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 and six months ended June
30, 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 optimize timing of capital outlays and projects. The current
size of the Trust gives us the ability 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 credit facilities through a bank syndicate,
US-dollar-denominated Senior Secured Notes (US 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.
Projected funds flow from operations and proceeds from the PrimeWest DRIP and dispositions
are expected to be sufficient to adequately fund development activities for 2007
without the need for incremental debt, assuming a payout ratio of 60% - 75% of funds
flow from operations. PrimeWest is moving towards a business model where future
development capital spending and distributions are generally expected to be financed
with funds flow from operations.
PrimeWest's dual listing on the Toronto Stock Exchange (TSX) and New York Stock
Exchange (NYSE) provides increased liquidity and a broadened investor base. The
NYSE listing enables US Unitholders to conveniently trade in our Trust Units, and
allows us to access the US capital markets. Our status as a corporation for US tax
purposes simplifies tax reporting for our US Unitholders.
For eligible Canadian and US Unitholders, PrimeWest offers participation in the
conventional Distribution Reinvestment Plan (DRIP), which represents a convenient
way to maximize an investment in PrimeWest. Canadian residents may also participate
in the Optional Trust Unit Purchase Plan (OTUPP) and the Premium Distribution Plan
(PREP). Additionally, investors may also purchase 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, which 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 Six Months Ended
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$ Millions, except per BOE (1) Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
and per Trust Unit amounts 2007 2007 2006 2007 2006
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Gross revenue 186.5 189.7 156.8 376.2 348.9
per BOE 50.94 50.49 46.09 50.71 51.09
Funds flow from operations (2) 103.5 85.8 86.8 189.3 188.2
per BOE 28.27 22.85 25.51 25.53 27.55
per Trust Unit - basic (3) 1.15 0.95 1.06 2.09 2.32
per Trust Unit - diluted (4) 1.08 0.90 1.03 1.97 2.26
Royalty expense 30.3 40.0 31.9 70.3 76.5
per BOE 8.27 10.65 9.36 9.47 11.20
Operating expense 34.6 38.9 31.1 73.6 63.8
per BOE 9.46 10.36 9.15 9.92 9.35
General and administrative
expense (G&A) 9.6 9.3 8.5 18.9 15.3
per BOE 2.64 2.47 2.49 2.55 2.24
Interest expense (5) 11.2 12.2 5.2 23.5 9.7
per BOE 3.07 3.25 1.52 3.16 1.43
Distributions to Unitholders 68.1 67.6 82.8 135.7 169.5
per Trust Unit (6) 0.75 0.75 1.02 1.50 2.10
Net debt (7) 619.2 716.3 415.5 619.2 415.5
per Trust Unit (8) 6.70 7.81 4.98 6.70 4.98
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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) Funds flow from operations has been restated to include $8.0 million of
debt issue costs related to the 6.5% Debentures incurred in the first
quarter of 2007.
(3) The basic per Trust Unit calculation includes the weighted average Trust
Units and Trust Units issueable upon exchange of the Exchangeable
Shares.
(4) The diluted per Trust Unit calculation includes the weighted average
Trust Units outstanding, Trust Units issueable upon exchange of the
outstanding Exchangeable Shares, the deemed conversion of the Debentures
and Trust Units issueable pursuant to the LTIP. Interest expense
incurred on the Debentures is added back to net income and to funds flow
for the diluted per Trust Unit calculation.
(5) Interest expense includes the interest on the Debentures.
(6) Based on Trust Units outstanding at the record dates for distributions
during the period.
(7) Net debt is long-term debt including the Debentures adjusted for working
capital, excluding current derivative and future income tax assets and
liabilities.
(8) 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 Six Months Ended
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Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
Daily Production Volumes 2007 2007 2006 2007 2006
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Natural gas (mmcf/day) 165.2 169.4 164.1 167.3 165.1
Crude oil (bbls/day) 8,666 9,071 6,305 8,867 6,584
Natural gas liquids (bbls/day) 4,027 4,443 3,748 4,234 3,637
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Total (BOE per day) 40,226 41,748 37,406 40,982 37,732
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Average Realized Sales Prices
Three Months Ended Six Months Ended
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Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
2007 2007 2006 2007 2006
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Natural gas ($/Mcf) (1) 7.57 7.79 6.29 7.68 7.69
Crude oil ($/bbl) 62.58 58.23 68.78 60.37 62.72
Natural gas liquids ($/bbl) 59.06 53.78 62.56 56.31 61.01
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Total Oil Equivalent ($/BOE) 50.50 50.00 45.46 50.25 50.47
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Realized derivative gains
($/BOE) 0.44 1.60 1.56 1.03 0.64
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Net realized price ($/BOE) 50.94 51.60 47.02 51.28 51.11
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(1) Excludes sulphur.
Funds Flow From Operations Reconciliation
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$ Millions
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First quarter 2007 funds flow from operations (1) 85.8
Volumes (5.1)
Commodity prices 2.1
Net hedging change from prior quarter (4.4)
Operating expenses 4.3
Royalties 9.7
Site restoration and reclamation 1.8
Debt issue costs 8.0
Interest 1.0
Other 0.3
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Second quarter 2007 funds flow from operations 103.5
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(1) First quarter 2007 funds flow from operations has been restated to
include $8.0 million of debt issue costs related to the 6.5% Debentures
incurred in the first quarter of 2007.
The above table includes a non-GAAP measure. (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, 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
The following table reconciles a non-GAAP measure, funds flow from operations, to
the nearest GAAP measure, cash flow from operating activities.
Three Months Ended Six Months Ended
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Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ Millions 2007 2007 2006 2007 2006
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Funds flow from operations 103.5 85.8 86.8 189.3 188.2
Change in non-cash working
capital 1.5 (3.3) 2.6 (1.8) 25.7
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Cash flow from operating
activities 105.0 82.5 89.4 187.5 213.9
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Selected Canadian and US Financial Results
Prior to 2006, PrimeWest focused on oil and natural gas plays in Western Canada.
In July 2006, PrimeWest acquired US assets. The following table provides selected
financial results from PrimeWest's Canadian and US operations for the six months
ended June 30, 2007.
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Six Months Ended Jun 30, 2007
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$ Millions, except production volumes
and per unit prices (2) Canada US Total
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Daily Production Volumes
Natural gas (mmcf/day) 166.4 0.9 167.3
Crude oil (bbls/day) 6,537 2,330 8,867
Natural gas liquids (bbls/day) 4,186 48 4,234
Total daily sales (BOE per day) 38,451 2,531 40,982
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Pricing (1)
Natural gas ($/Mcf) 7.69 7.21 7.68
Crude oil ($/bbl) 60.15 61.00 60.37
Natural gas liquids ($/bbl) 56.51 38.82 56.31
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Revenues (1)
Natural gas 231.5 1.2 232.7
Crude oil 71.2 25.7 96.9
Natural gas liquids 42.8 0.3 43.1
Royalties (64.8) (5.5) (70.3)
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Expenses
Operating 66.4 7.2 73.6
G&A 17.7 1.2 18.9
Depletion, depreciation and amortization 121.4 9.6 131.0
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Capital expenditures
Development and head office 82.9 23.3 106.2
Acquisition of oil and gas properties 10.6 1.7 12.3
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(1) Net of transportation expense. Excludes derivative gains and losses.
(2) Comparative segmented information is not provided for the six months
ended June 30, 2006, as the US assets were acquired in July 2006.
Quarterly Performance - Selective Measures
The table following highlights PrimeWest's performance for the second quarter ended
June 30, 2007, and the preceding seven quarters through 2005.
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2007 2006 2005
----------------------------------------------------------------------------
$ Millions, except
per Trust Unit
Amounts Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
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Net Revenues 173.1 126.0 158.4 160.7 135.0 170.0 237.1 101.7
Net Income 112.4 5.5 9.6 64.0 65.7 68.9 101.5 27.3
Funds Flow from
Operations 103.5 85.8(1) 84.6 91.4 86.8 101.3 128.6 105.1
Net income per Trust
Unit - basic 1.24 0.06 0.11 0.78 0.81 0.85 1.27 0.35
Net income per Trust
Unit - diluted 1.17 0.06 0.11 0.76 0.79 0.83 1.23 0.35
Funds flow per Trust
Unit - basic 1.15 0.95(1) 1.01 1.11 1.06 1.25 1.61 1.34
Funds flow per Trust
Unit - diluted 1.08 0.90(1) 1.00 1.09 1.03 1.22 1.56 1.29
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(1) Funds flow from operations has been restated to include $8.0 million of
debt issue costs related to the 6.5% Debentures incurred in the first
quarter of 2007.
Net revenues are impacted primarily by commodity prices, production volumes, royalties
and realized and unrealized gains or losses on derivatives.
Net income includes the following non-cash items; 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. Non-cash
items will not affect PrimeWest's current ability to pay a monthly distribution.
Capital Expenditures
Three Months Ended Six Months Ended
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Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ Millions 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Land and lease acquisitions 1.6 1.1 3.5 2.7 6.9
Geological and geophysical 1.0 2.5 0.5 3.5 2.0
Drilling and completions 16.2 49.0 22.3 65.2 75.8
Investment in facilities
Equipping and tie-in 7.8 8.4 14.4 16.2 30.0
Gas gathering and compression 3.1 6.8 1.1 9.9 2.3
Production facilities 2.3 2.3 3.1 4.6 7.7
Capitalized G&A 1.0 1.4 1.2 2.4 2.6
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Development capital 33.0 71.5 46.1 104.5 127.3
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Acquisition of oil and gas
assets 0.8 11.5 0.2 12.3 0.4
Dispositions (47.6) - (0.1) (47.6) (3.2)
Leasehold improvements,
furniture and equipment 0.6 1.1 1.3 1.7 2.6
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Net capital expenditures (13.2) 84.1 47.5 70.9 127.1
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PrimeWest is continually striving to add to reserves and offset the natural decline
in its oil and natural gas reserves in an effort to create value for the unitholders.
Investment in activities such as development drilling, workovers and recompletions
can add incremental production volumes and reserves.
PrimeWest continues to focus on its four key development plays: conventional development,
tight gas, US oil assets and coalbed methane (CBM). During the second quarter $24.0
million was invested in drilling and completions and tie-ins. PrimeWest drilled
three wells in the Flat Lake area in Montana and completed and tied-in several wells
in the conventional development plays at Wilson Creek and Crossfield/Lone Pine Creek
and at its tight gas play in Caroline.
During the quarter PrimeWest sold non-core assets at Ells, Leaman/Thunder and Seal
for net proceeds of approximately $47.6 million. PrimeWest has signed a purchase
and sale agreement to sell other assets which is expected to close in the third
quarter for net proceeds of approximately $56.5 million.
Capital Outlook
Development activity for the remainder of the year will be focused on tight gas
assets at Caroline, Columbia and Ferrier as well as on conventional assets at Wilson
Creek, Valhalla and Whitecourt. PrimeWest will continue its development activities
in the US and plans to commence the first phase of drilling at the Crossfield CBM
project during the second half of 2007.
Total 2007 development capital expenditures are estimated to be $250 million
and will be allocated approximately as follows:
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$ Millions
----------------------------------------------------------------------------
Conventional development 100
Tight gas 50
US assets 25
Coalbed methane (CBM) 40
Land, seismic, central facilities and plants,
maintenance and capitalized G&A 35
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Total Development Capital 250
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Daily Production Volumes
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
Daily Production Volumes 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Natural gas (mmcf/day) 165.2 169.4 164.1 167.3 165.1
Crude oil (bbls/day) 8,666 9,071 6,305 8,867 6,584
Natural gas liquids (bbls/day) 4,027 4,443 3,748 4,234 3,637
----------------------------------------------------------------------------
Total (BOE per day) 40,266 41,748 37,406 40,982 37,732
----------------------------------------------------------------------------
The 4% decrease in production volumes from the first quarter of 2007 is attributable
to the turnarounds at Wilson Creek and Stowe, the impact of asset sales at Seal
and natural decline exceeding incremental volume additions from capital spending.
For the three and six months ended June 30, 2007, production volumes increased by
approximately 8% when compared to the same periods in 2006 due to the acquisition
of the US assets early in the third quarter of 2006 and to incremental volume additions
from development capital exceeding natural decline.
PrimeWest has initiated a divestment program of approximately 1,700 BOE per day
from non-core assets. The program began in May 2007 and will be completed in the
third quarter of 2007. An additional 1,800 BOE per day will be divested in the second
half of 2007.
Production Outlook
PrimeWest expects full year 2007 production volumes to average approximately 50,000
BOE per day which includes the impact of divestitures and the Shiningbank merger
for the remaining six months of 2007. The exit production rate at the end of 2007
is expected to be approximately 59,000 BOE per day.
Commodity Prices
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
Benchmark Prices 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Natural gas
NYMEX (US$/Mcf) 7.56 6.96 6.82 7.26 7.95
AECO (C$/Mcf) 7.37 7.46 6.27 7.41 7.77
Crude oil WTI (US$/bbl) 65.03 58.27 70.70 61.65 67.09
----------------------------------------------------------------------------
Benchmark Commodity Prices
The following table sets forth benchmark historical and estimated future
commodity prices.
Past Four Quarters Next Four Quarters
(actual) (Forward Markets)(1)
----------------------------------------------------------------------------
Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
2006 2006 2007 2007 2007 2007 2008 2008
----------------------------------------------------------------------------
Natural gas AECO
(C$/Mcf) 6.03 6.36 7.46 7.37 5.98 7.14 8.14 7.47
Crude oil WTI
(US$/bbl) 70.48 60.21 58.27 65.03 70.97 71.51 72.00 72.34
----------------------------------------------------------------------------
(1) As at June 30, 2007.
Average Realized Sales Prices
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
Average Realized Sale Prices 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)(2) 7.64 8.01 6.65 7.82 7.89
Without derivatives 7.57 7.79 6.29 7.68 7.69
Crude oil ($/bbl)(1) 63.46 61.54 68.72 62.48 61.35
Without derivatives 62.58 58.23 68.78 60.37 62.72
Natural gas liquids ($/bbl) 59.06 53.78 62.56 56.31 61.01
----------------------------------------------------------------------------
Total Oil Equivalent ($/BOE) (1) 50.94 51.60 47.02 51.28 51.11
Without derivatives 50.50 50.00 45.46 50.25 50.47
----------------------------------------------------------------------------
Realized derivative gains
included in prices above ($/BOE) 0.44 1.60 1.56 1.03 0.64
----------------------------------------------------------------------------
(1) Includes derivatives gains/losses.
(2) Excludes sulphur.
Natural gas prices in April reflected unseasonably cold weather in the early spring,
resulting in the expectation of a significant storage deficit at the end of June
compared to the previous year. Milder weather in May and less than expected natural
gas demand, coupled with high liquified natual gas (LNG) imports soon narrowed the
gas storage deficit. By the end of June, rising US domestic production along with
continued record LNG imports, more than offset declining Canadian gas production.
As a result, early bullish gas price sentiments turned decidedly more bearish by
the end of June. Weather continues to play a significant role in determining overall
supply and demand balances, with the resulting impact on pricing. Current underlying
gas fundamentals have resulted in an increasing supply surplus and lower prices.
Crude oil prices in April continued to respond to suppressed OPEC production. Prices
also responded to forecasts of demand for crude exceeding that of non-OPEC supply.
These tighter crude markets and political turmoil in oil producing regions, combined
with strong refining margins due to high North American gasoline demand, all contributed
to push prices to in excess of US $67/Bbl by the end of June.
Sales Revenue
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Revenue
($ Millions)
(1) (2) (3) Jun 30, % of Mar 31, % of Jun 30, % of Jun 30, Jun 30,
2007 Total 2007 Total 2006 Total 2007 2006
Natural gas 113.9 62 118.8 63 93.9 61 232.7 229.8
Crude oil 49.4 27 47.5 25 39.4 25 96.9 74.7
Natural gas
liquids 21.6 11 21.5 12 21.4 14 43.1 40.2
----------------------------------------------------------------------------
Total 184.9 100 187.8 100 154.7 100 372.7 344.7
----------------------------------------------------------------------------
(1) Excludes sulphur.
(2) Net of transportation expenses.
(3) Excludes impact of derivatives.
Second quarter 2007 revenues were 2% lower than the previous quarter mainly due
to lower realized natural gas prices and lower production volumes. Increases to
crude oil prices had a positive impact on revenues.
Second quarter 2007 revenues were 20% higher compared to the same period in 2006,
due to higher natural gas prices and increases to crude oil volumes resulting from
the US asset acquisition.
As at end of June 2007, 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 following table provides a summary of net realized and unrealized gains and
losses on financial derivatives for the three and six months ended June 30, 2007
and 2006.
----------------------------------------------------------------------------
Three Months Ended June 30, 2007
----------------------------------------------------------------------------
($ millions except per BOE) Oil Gas Foreign Total
Exchange
Realized gains on derivatives 0.7 0.9 - 1.6
Unrealized gains/(losses) on derivatives (1.7) 21.0 (7.9) 11.4
----------------------------------------------------------------------------
Total gains/(losses) on derivatives (1.0) 21.9 (7.9) 13.0
----------------------------------------------------------------------------
Realized gains on derivatives per BOE 0.19 0.25 - 0.44
Unrealized (gains)/losses in derivatives
per BOE (0.48) 5.74 (2.14) 3.12
----------------------------------------------------------------------------
Six Months Ended June 30, 2007
----------------------------------------------------------------------------
($ millions except per BOE) Oil Gas Foreign Total
Exchange
----------------------------------------------------------------------------
Realized gains on derivatives 3.4 4.2 - 7.6
Unrealized losses on derivatives (7.7) (2.4) (10.0) (20.1)
----------------------------------------------------------------------------
Total gains/(losses) on derivatives (4.3) 1.8 (10.0) (12.5)
----------------------------------------------------------------------------
Realized gains on derivatives per BOE 0.46 0.57 - 1.03
Unrealized losses on derivatives
per BOE (1.03) (0.32) (1.35) (2.70)
----------------------------------------------------------------------------
Three Months Ended June 30, 2006
----------------------------------------------------------------------------
($ millions except per BOE) Oil Gas Foreign Total
Exchange
Realized gains on derivatives - 5.3 0.2 5.5
Unrealized gains/(losses) on derivatives (0.9) 6.2 (2.3) 3.0
----------------------------------------------------------------------------
Total gains/(losses) on derivatives (0.9) 11.5 (2.1) 8.5
----------------------------------------------------------------------------
Realized gains on derivatives per BOE - 1.56 0.07 1.63
Unrealized gains/(losses) in derivatives
per BOE (0.25) 1.82 (0.67) 0.90
----------------------------------------------------------------------------
Six Months Ended June 30, 2006
----------------------------------------------------------------------------
($ millions except per BOE) Oil Gas Foreign Total
Exchange
----------------------------------------------------------------------------
Realized gains/(losses) on derivatives (1.6) 6.0 0.2 4.5
Unrealized gains/(losses) on derivatives (0.4) 27.8 (2.3) 25.1
----------------------------------------------------------------------------
Total gains/(losses) on derivatives (2.0) 33.8 (2.1) 29.6
----------------------------------------------------------------------------
Realized gains/(losses) on derivatives
per BOE (0.24) 0.88 0.04 0.68
----------------------------------------------------------------------------
Unrealized gains/(losses) on derivatives
per BOE (0.06) 4.08 (0.34) 3.68
----------------------------------------------------------------------------
The following table sets forth the approximate percentage of future
anticipated production volumes hedged at June 30, 2007, net of anticipated
royalties, reflecting full production declines with no offsetting additions.
----------------------------------------------------------------------------
Production Volumes Hedged (%) Q3 Q4 Q1 Q2 Q3 Q4
2007 2007 2008 2008 2008 2008
----------------------------------------------------------------------------
Crude Oil 65 60 39 41 29 23
Natural Gas 59 53 56 45 28 15
----------------------------------------------------------------------------
A listing of derivative contracts in place at June 30, 2007, follows:
Crude Oil
----------------------------------------------------------------------------
Period Volume (bbls/d) Type WTI Price (US$/bbl)
----------------------------------------------------------------------------
Jul - Sep 07 500 Costless Collar 60.00/92.75
Jul - Sep 07 500 Swap 75.20
Jul - Sep 07 500 Costless Collar 65.00/92.60
Jul - Sep 07 900 Costless Collar 70.00/83.25
Jul - Sep 07 500 Costless Collar 55.00/77.80
Jul - Sep 07 500 Costless Collar 60.00/75.10
Jul - Sep 07 500 Costless Collar 60.00/73.20
Jul - Sep 07 500 Costless Collar 60.00/75.03
Jul - Sep 07 500 Costless Collar 60.00/71.25
Jul - Sep 07 500 Costless Collar 60.00/75.70
Oct - Dec 07 500 Costless Collar 60.00/90.25
Oct - Dec 07 500 Swap 74.58
Oct - Dec 07 500 Costless Collar 65.00/91.35
Oct - Dec 07 800 Costless Collar 70.00/82.10
Oct - Dec 07 500 Costless Collar 55.00/78.25
Oct - Dec 07 500 Costless Collar 60.00/76.60
Oct - Dec 07 500 Costless Collar 60.00/75.20
Oct - Dec 07 500 Costless Collar 60.00/76.60
Oct - Dec 07 500 Costless Collar 60.00/75.05
Jan - Mar 08 500 Costless Collar 55.00/78.00
Jan - Mar 08 500 Costless Collar 60.00/77.10
Jan - Mar 08 500 Costless Collar 60.00/76.60
Jan - Mar 08 500 Costless Collar 60.00/70.00
Jan - Mar 08 500 Costless Collar 60.00/75.10
Jan - Mar 08 500 Costless Collar 60.00/75.25
Apr - Jun 08 500 Costless Collar 60.00/77.35
Apr - Jun 08 500 Costless Collar 60.00/70.00
Apr - Jun 08 500 Costless Collar 60.00/75.95
Apr - Jun 08 500 Costless Collar 60.00/75.10
Apr - Jun 08 500 Costless Collar 60.00/82.62
Apr - Jun 08 500 Costless Collar 65.00/80.10
Jul - Sep 08 500 Costless Collar 60.00/75.05
Jul - Sep 08 500 Costless Collar 60.00/75.25
Jul - Sep 08 500 Costless Collar 60.00/82.72
Jul - Sep 08 500 Costless Collar 65.00/80.10
Oct - Dec 08 500 Costless Collar 60.00/82.05
Oct - Dec 08 500 Costless Collar 65.00/80.55
Oct - Dec 08 500 Costless Collar 65.00/80.01
----------------------------------------------------------------------------
Natural Gas
----------------------------------------------------------------------------
Period Volume (mmcf/d) Type AECO Price (C$/mcf)
----------------------------------------------------------------------------
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
Jul - Sep 07 5.0 Costless Collar 6.86/8.65
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
Oct - Dec 07 5.0 Costless Collar 7.39/10.18
Oct - Dec 07 5.0 Costless Collar 6.33/8.55
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
Jan - Mar 08 5.0 Costless Collar 7.39/12.45
Jan - Mar 08 5.0 Costless Collar 7.39/11.61
Jan - Mar 08 5.0 Costless Collar 6.33/11.43
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
Apr - Jun 08 5.0 Costless Collar 6.86/9.65
Apr - Jun 08 5.0 Costless Collar 6.86/9.50
Apr - Jun 08 5.0 Costless Collar 6.33/9.02
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
Jul - Sep 08 5.0 Costless Collar 7.39/9.51
Jul - Sep 08 5.0 Costless Collar 6.86/9.51
Jul - Sep 08 5.0 Costless Collar 6.33/9.60
Oct - Dec 08 5.0 Costless Collar 7.39/10.81
Oct - Dec 08 5.0 Costless Collar 7.39/10.55
Oct - Dec 08 5.0 Costless Collar 6.86/10.71
----------------------------------------------------------------------------
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 $9.29, 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 $9.29, PrimeWest
will receive a maximum of $9.29. Should the market price remain between $7.39 and
$9.29, PrimeWest will receive the market price.
Foreign Exchange
----------------------------------------------------------------------------
Period Amount Pounds Sterling (000's) Type Price
----------------------------------------------------------------------------
Jul 2007-Jun 2016 Principal 63,000 Swap $ 2.0748 Cdn per
Interest 33,623 Pounds 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 Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ Millions, except per BOE 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Royalty expense 30.3 40.0 31.9 70.3 76.5
Per BOE 8.27 10.65 9.36 9.47 11.20
Royalties as a % of sales
revenues 16.4% 21.3% 20.6% 18.9% 22.2%
----------------------------------------------------------------------------
Royalty expense as a percentage of sales was lower in the second quarter of 2007
compared to the first quarter due to an over estimate of freehold mineral tax in
prior periods and to the annual Crown adjustment for gas cost allowance. Without
these adjustments, the royalty rate for the second quarter would have been approximately
20%.
Royalty expense as a percentage of sales for the three and six months ended June
2007 was lower compared to the same periods in 2006 due to the adjustment to freehold
mineral tax.
Operating Expense
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ Millions, except per BOE 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Operating expense 34.6 38.9 31.1 73.6 63.8
Per BOE 9.46 10.36 9.15 9.92 9.35
----------------------------------------------------------------------------
Second quarter 2007 operating expense totalled $34.6 million, a decrease of 11%
from $38.9 million in the first quarter 2007. The decrease in operating expense
in the second quarter compared to the first quarter is mainly due to lower well
servicing activities at Fox Creek and Grand Forks, lower repair and maintenance
costs at Valhalla, lower processing fees at Thorsby, decreases in power costs, increases
to processing income resulting from fee updates and the impact of the sale of assets
in the Seal area. The reductions were partially offset by turnaround costs at Wilson
Creek and Stowe. On a BOE basis, operating expense decreased from the prior quarter
due to the reduction in operating expense partially offset by the decrease in production
volumes.
Operating expense and operating expense per BOE for the three and six months ended
2007 have increased compared to the same periods in 2006 due to higher operating
costs associated with the US assets 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
$9.50 per BOE including the impact of the Shiningbank merger.
Operating Margin
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ per BOE 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Sales price and other revenue
(1) 51.47 50.49 46.03 50.98 51.02
Royalties (8.27) (10.65) (9.36) (9.47) (11.20)
Operating expense (9.46) (10.36) (9.15) (9.92) (9.35)
----------------------------------------------------------------------------
Operating margin before
realized derivative
gains/(losses) 33.74 29.48 27.52 31.59 30.47
Realized derivative gain/loss 0.44 1.60 1.56 1.03 0.63
----------------------------------------------------------------------------
Operating margin after realized
derivative gains/(losses) 34.18 31.08 29.08 32.62 31.10
----------------------------------------------------------------------------
(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 second quarter of 2007 compared to
the previous quarter mainly due to an increase in other revenue, lower operating
expense and lower royalties.
The second quarter 2007 operating margin was higher than the same period in 2006
due to increases in other revenue, increases in natural gas prices and lower royalties
partially offset by increases in operating expenses and lower crude oil prices.
General & Administrative Expense
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ Millions, except per BOE 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
G&A expense 9.6 9.3 8.5 18.9 15.3
Per BOE 2.64 2.47 2.49 2.55 2.24
----------------------------------------------------------------------------
G&A expense in the second quarter of 2007 increased by 3% compared to the previous
quarter mainly due to the decrease in overhead recoveries resulting from lower capital
expenditures in the second quarter.
G&A expense for the three months ended June 30, 2007 was 13% higher when compared
to the same period in 2006 due to increases in labour costs and costs associated
with the Denver office. G&A expense per BOE for the three months ended June 30,
2007, was 6% higher than the same period in the prior year due to higher G&A expense
partially offset by increases to production volumes.
G&A expense for the six months ended June 30, 2007 increased by 24% compared to
the six months ended June 30, 2006 mainly due to an increase in labour costs and
lower overhead recoveries.
Included in G&A expense was $1.7 million and $3.4 million for the three and six
months ended June 30, 2007, respectively, relating to the Unit Appreciation Rights
(UARs), granted under the LTIP. UARs in the Trust are similar to stock options in
a corporation. The program rewards employees based on total Unitholder return, which
is comprised of cumulative distributions on a reinvested basis plus growth in Unit
price. No benefit accrues to the UARs until the Unitholders have first achieved
a 5% total annual return from the time of grant. PrimeWest continues to pay for
the exercise of UARs in Trust Units. Also included in G&A expense is $0.2 million
and $0.5 million for the three and six months ended June 30, 2007, respectively,
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 Six Months Ended
----------------------------------------------------------------------------
$ Millions, except per Trust Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
Unit Amounts and Cost of Debt 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Interest expense 11.2 12.2 5.2 23.5 9.7
Period end net debt level (1) 619.2 716.3 415.5 619.2 415.5
Debt per Trust Unit 6.70 7.81 4.98 6.70 4.98
----------------------------------------------------------------------------
Average cost of debt % 6.2% 5.8% 5.1% 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 US Secured Notes, the
U.K. Secured Notes and the Debentures decreased in the second quarter of 2007 compared
to the first quarter of 2007 due to the decrease in the average net debt balance.
Interest expense was higher for the three and six months ended June 30, 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 US asset acquisition in the
third quarter of 2006.
The average cost of debt was higher for the three months ended June 30, 2007, compared
to the previous quarter and the same period in 2006, primarily due to a larger percentage
of the outstanding debt balance bearing interest at the London Inter Bank Offer
Rate (LIBOR) which is higher than the Canadian Banker's acceptance rate.
Foreign Exchange
The unrealized foreign exchange gain of $17.1 million and $19.3 million for the
three and six months ended June 30, 2007, respectively, resulted from the translation
of the US Secured Notes, the U.K. Secured Notes and related interest payable into
Canadian dollars.
Depletion, Depreciation and Amortization
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
$ Millions, except Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
per BOE 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
DD&A 64.1 66.9 53.5 131.0 107.5
Per BOE 17.50 17.82 15.73 17.66 15.74
----------------------------------------------------------------------------
The DD&A rate for the three and six months ended June 30, 2007 increased by 11%
and 12%, respectively, 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 second quarter. If required additional contributions will be
made to the fund in 2007 to accommodate the recent increase in expenditures.
As at June 30, 2007, the site reclamation fund contained a balance of $0.4 million.
The abandonment and reclamation costs incurred in the second quarter 2007 were $2.0
million, compared to $1.8 million for the same period in 2006, and $3.8 million
for the previous quarter.
Income and Capital Taxes
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ Millions 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Income and capital taxes 1.3 0.2 (1.2) 1.5 (0.6)
Future income tax recovery (46.4) (16.3) (23.0) (62.7) (23.7)
----------------------------------------------------------------------------
Total (45.1) (16.1) (24.2) (61.2) (24.3)
----------------------------------------------------------------------------
The increase in the future income tax recovery for the three and six months ended
June 30, 2007 compared to the same periods in 2006 is due to amendments to the Income
Tax Act which were enacted on June 22, 2007.
Prior to the changes in tax law, distributions paid to Unitholders, other than return
of capital, were claimed as a deduction by the Trust in arriving at taxable income
the result of which is the tax is eliminated at the Trust level and is paid by the
Unitholders. The new Trust tax legislation results in a two-tiered structure whereby
distributions are subject to a 31.5% tax at the Trust level and then Unitholders
are subject to tax on the distribution as if it were a taxable dividend paid by
a taxable Canadian corporation. These rules are effective for tax years beginning
in 2011.
The enactment of the legislation triggered the recognition of future Canadian corporate
income tax assets, with a corresponding impact on future Canadian corporate income
tax recovery, based on temporary differences expected to reverse after the date
that the taxation changes take effect. The $46.7 million recovery to future income
tax recorded in the second quarter of 2007 as a result of this new legislation is
based on estimated gross temporary differences of approximately $170.2 million that
are expected to reverse after 2010, which, using an effective rate of 31.5%, results
in a future tax asset of $46.7 million at June 30, 2007.
The Federal Government issued guidance with respect to limitations on future growth
of the Trust. PrimeWest does not anticipate that the guidelines will impair the
Trust's ability to annually replace or grow reserves in the next four years as the
guidelines allow sufficient growth targets. Key attributes of the future growth
constraints are as follows:
- Trusts may grow in size by 100% cumulatively for the period 2007 through 2010
as measured by the value of equity based on the October 31, 2006 market capitalization.
The cumulative limit starts at 40% in 2007 and increases by 20 % per year in 2008
through 2010.
- The merger of two Trusts will not be impacted by the growth limitations.
- The growth limits are not impacted by non-convertible debt-financed growth but
rather focus solely on the issuance of equity to facilitate growth.
Net Income
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30, Jun 30, Jun 30,
$ Millions 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Net income 112.4 5.5 65.7 117.9 134.7
----------------------------------------------------------------------------
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 June 30, 2007, of $112.4 million was significantly
higher than the previous quarter's net income of $5.5 million primarily due to increases
in the change in the unrealized gain on derivatives of $42.9 million, the foreign
exchange gain of $14.8 million and the future income tax recovery of $30.1 million.
Reductions to royalties of $9.7 million, operating costs of $4.3 million and debt
issue costs of $8.0 million also increased net income.
Net income for the three months ended June 30, 2007 was $46.7 million higher than
the same period in 2006, mainly due to increases in oil and gas revenues of $29.7
million resulting from the acquisition of US assets in July 2006, increases to the
unrealized gain on derivatives of $8.4 million, increases to the foreign exchange
gain of $9.9 million and an increase to the future income tax recovery of $23.4
million resulting from the changes in tax legislation. Increases to operating expense
of $3.5 million, interest of $6.0 million and DD&A of $10.6 million had a negative
impact on net income. The increases in costs are primarily due to the acquisition
of the US assets.
Net income for the six months ended June 30, 2007 of $117.9 million was $16.8 million
lower than the same period in 2006 mainly due to increases in the changed in the
unrealized loss on derivatives of $45.2 million, increases to interest of $13.8
million, increases to operating expense of $9.8 million and debenture debt issue
costs of $8.0 million. The increases in operating expense, DD&A and interest are
due to the US asset acquisition. Increases to oil and gas revenue of $27.3 million,
the foreign exchange gain of $12.7 million and the future income tax recovery of
$39.0 million had a positive impact on net income.
Liquidity & Capital Resources
Long-Term Debt
As at
----------------------------------------------------------------------------
Jun 30, Mar 31, Jun 30,
$ Millions 2007 2007 2006
----------------------------------------------------------------------------
Long-term debt 648.5 716.3 400.6
(Working capital)/Deficit (1) (29.3) - 14.9
----------------------------------------------------------------------------
Net debt 619.2 716.3 415.5
Market value of Trust Units and Exchangeable
Shares outstanding (2)(3) 2,055.8 2,070.8 2,751.1
----------------------------------------------------------------------------
Total capitalization 2,675.0 2,787.1 3,166.6
----------------------------------------------------------------------------
Net debt as a % of total capitalization 23% 26% 13%
----------------------------------------------------------------------------
(1) Excludes derivative and future income tax assets and liabilities
included in current assets or liabilities.
(2) Based on Jun 30, 2007, Trust Unit closing price of $22.39 and June 15,
2007, exchange ratio of 0.68067:1.
(3) Excludes the Debentures.
Long-term debt is comprised of senior bank credit facilities, the US Secured Notes,
the U.K. Secured Notes and the Debentures of $215.2 million, $99.9 million, $134.4
million and $232.3 million respectively. $33.3 million relating to the US 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 US 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
US bank revolving credit facilities having a borrowing limit of Cdn $255.0 million,
the US Secured Notes valued at $99.9 million based on a US dollar exchange rate
of US $0.94 and the U.K. Secured Notes valued at Cdn $130.7 million.
On January 11, 2007, PrimeWest issued $200 million of Series III 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 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 June 30, 2007, PrimeWest's net debt to annualized second quarter funds flow was
approximately 1.5 times compared to 2.1 times annualized first quarter 2007 cash
flow at March 31, 2007.
Upon the completion of the merger with Shiningbank on July 11, 2007, PrimeWest entered
into a new 3-year unsecured extendible revolving credit facility with a syndicate
of chartered banks and other financial institutions. The credit facility provides
for Cdn $1.1 billion of credit capacity for PrimeWest's operations in Canada and
US $235 million of credit capacity for PrimeWest's operations in the US. With the
consent of the lenders, the 3-year term of the credit facility may be extended on
an annual basis for an additional year. Advances under the credit facility may be
made by way of Canadian and US dollar denominated prime rate loans, Canadian dollar
denominated bankers' acceptances, US dollar denominated LIBOR advances and letters
of credit. These advances bear interest at the lenders' borrowing costs plus a stamping
fee, or the applicable prime rate plus a margin. PrimeWest is required under the
credit facility to maintain certain financial covenants.
Unitholders' Equity
At June 30, 2007, the Trust had 91,029,149 Trust Units outstanding. In addition,
PrimeWest had 1,158,068 Exchangeable Shares outstanding that are exchangeable into
a total of 788,262 Trust Units using the June 30, 2007, exchange ratio of 0.68067:1.
On January 11, 2007, PrimeWest issued 6,420,000 Trust Units for net proceeds of
$142.4 million.
The DRIP gives Canadian and US Unitholders the opportunity to reinvest their monthly
distributions at a 5% discount to the volume-weighted average market price of the
Trust Units. As an alternative to the DRIP component of the Plan, the PREP allows
eligible Canadian Unitholders to elect to receive a premium cash distribution of
up to 102% of the cash that the Unitholder would otherwise have received on the
distribution date, subject to proration in certain events. The OTUPP gives Canadian
Unitholders an opportunity to purchase additional Trust Units directly from PrimeWest
at the same 5% discount. The DRIP and PREP components are mutually exclusive. Participation
in the OTUPP requires enrolment in either the DRIP or PREP. During the six months
ended June 30, 2007, PrimeWest issued 423,400 Trust Units under the DRIP for $9.0
million, 585,380 Trust Units for $12.5 million under the PREP and 306,087 Trust
Units for $6.5 million under 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 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 SERP which was 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 June 30, 2007, there were 1,158,068 Exchangeable Shares outstanding. The exchange
ratio on these shares was 0.68067:1 Trust Units for each Exchangeable Share as at
June 30, 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 60% - 75% of funds flow from operations. In
the second quarter of 2007, cash distributions totalled $68.1 million, or $0.75
per Trust Unit, representing a payout ratio of 66% of funds flow from operations.
Distribution payments to US 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 these contractual obligations
are included in the following table.
As at June 30, 2007 Payments due by period
----------------------------------------------------------------------------
Less More
than 1-3 4-5 than
$ Millions Total 1 year years years 5 years
----------------------------------------------------------------------------
Long-term debt obligations 449.5 33.3 281.8 - 134.4
Debentures 238.4 - 23.7 14.7 200.0
Interest (1) 84.2 14.6 21.7 17.2 30.7
Lease rental obligations 82.6 3.8 5.4 9.5 63.9
Pipeline transportation
obligations 4.5 3.0 1.3 0.2 -
----------------------------------------------------------------------------
Total contractual obligations 859.2 54.7 333.9 41.6 429.0
----------------------------------------------------------------------------
(1) Includes interest on the US Secured Notes, U.K. Secured Notes and the
Debentures assuming foreign exchange rates in effect as at June 30,
2007.
As part of PrimeWest's internalization transaction, which closed on November 6,
2002, PrimeWest agreed to issue 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 75,472 Exchangeable Shares will be
issued on November 6, 2007. For the three months ended June 30, 2007, $0.2 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 early 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 below 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 available for distribution
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 US;
- Weather conditions that influence the demand for natural gas and heating oil;
- The Canadian/US dollar exchange rate that affects the price received for crude
oil, as the price of crude oil is referenced in US 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 second 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 US 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
second quarter 2007, PrimeWest realized a $1.6 million gain 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 for
distribution 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 telemetry, physical inspection and
to market. diagnostic tools.
----------------------------------------------------------------------------
Commodity Price
Fluctuations in natural gas, crude See section "Financial Derivatives"
oil and natural gas liquids prices. in this quarterly report.
----------------------------------------------------------------------------
Transportation
Market risk related to the Diversifying the transportation
availability of transportation to systems on which we rely to
market and potential disruption in get our product to market.
delivery systems.
----------------------------------------------------------------------------
Natural Decline
Development risk associated with Diversifying our capital spending
capital enhancement activities program over a large
undertaken - the risk that number of projects so that large
capital spending on activities such amounts of capital are not
as drilling, well completions, risked on any one activity. We also
well workovers and other capital have a highly skilled
activities will not result in technical team of geologists,
reserve additions or in quantities geophysicists and engineers
sufficient to replace annual working to apply the latest
production declines. technology in planning and
executing capital programs. Capital
is spent only after strict
economic criteria for production
and reserve additions are
assessed.
----------------------------------------------------------------------------
Acquisitions
Acquisition risk associated with Continually scanning the
acquiring producing properties at marketplace for opportunities to
low cost to renew our inventory acquire assets. Our technical
of assets. acquisition specialists evaluate
potential corporate or property
acquisitions and identify areas
for value enhancement through
operational efficiencies or
capital investment. All prospects
are subjected to rigorous
economic review against established
acquisition and economic hurdle
rates. In some cases we may also
hedge commodity prices to protect
the acquisition economics in the
near term period.
----------------------------------------------------------------------------
Reserves
Reserve risk in respect of the 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
including reporting requirements, changes in regulations and
income tax laws, operating practices, laws to properly respond to and
environmental protection requirements plan for the effects that these
and royalty rates. changes may have on our 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
investments in trusts, there is a Liability Act (Alberta) was
risk that a Unitholder could be proclaimed in force, creating a
held personally liable for statutory limitation on the
obligations of the Trust. liability of 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) (unaudited) Jun 30, 2007 Dec 31, 2006
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 95.6 22.0
Accounts receivable 84.8 104.5
Derivative assets (note 6) 15.1 23.5
Future income taxes 2.1 2.3
Prepaid expenses 16.8 19.9
----------------------------------------------------------------------------
214.4 172.2
Cash reserved for site restoration
and reclamation 0.4 2.2
Other assets and deferred charges (note 2) 0.2 7.4
Derivative assets (note 6) 0.6 5.3
Future income taxes 46.7 -
Property, plant and equipment 2,242.3 2,332.9
Goodwill 68.5 68.5
----------------------------------------------------------------------------
2,573.1 2,588.5
----------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities 115.4 143.3
Current portion of long-term debt (note 4) 33.3 186.4
Future income taxes 5.8 8.7
Derivative liabilities (note 6) 1.3 -
Accrued distributions to Unitholders 19.2 18.1
----------------------------------------------------------------------------
175.0 356.5
Long-term debt (note 4) 648.5 619.4
Derivative liabilities (note 6) 5.7 -
Future income taxes 144.1 153.9
Asset retirement obligation (note 3) 88.9 91.5
----------------------------------------------------------------------------
1,062.2 1,221.3
UNITHOLDERS' EQUITY
Net capital contributions (note 5) 2,561.9 2,391.2
Capital issued but not distributed 3.5 2.7
Convertible Unsecured Subordinated Debentures 8.8 1.2
Contributed surplus (note 7) 15.0 11.9
Accumulated other comprehensive (loss)/income
(note 2) (7.2) 6.2
Deficit (note 8) (1,071.1) (1,046.0)
----------------------------------------------------------------------------
1,510.9 1,367.2
----------------------------------------------------------------------------
2,573.1 2,588.5
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
($ millions) (unaudited) Jun 30, Jun 30, Jun 30, Jun 30,
2007 2006 2007 2006
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the period 112.4 65.7 117.9 134.7
Add/(deduct) items not involving
cash from operations:
Depletion, depreciation and
amortization 64.1 53.5 131.0 107.5
Non-cash general and
administrative 1.9 1.5 3.9 3.0
Non-cash foreign exchange gain (17.0) (7.4) (19.1) (6.8)
Unrealized (gain)/loss on
derivatives (11.4) (3.0) 20.1 (25.1)
Future income tax recovery (46.4) (23.0) (62.7) (23.7)
Accretion of asset retirement
obligation 1.5 0.7 3.0 1.4
Other non-cash items 0.4 0.6 0.9 0.9
Expenditures on site restoration
and reclamation (2.0) (1.8) (5.7) (3.7)
----------------------------------------------------------------------------
Funds flow from operations 103.5 86.8 189.3 188.2
Change in non-cash working capital 1.5 2.6 (1.8) 25.7
----------------------------------------------------------------------------
105.0 89.4 187.5 213.9
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust
Units (net of costs) 2.9 3.6 148.9 9.3
Proceeds from issue of Debentures - - 200.0 -
(Decrease)/Increase in Senior
Secured Notes (34.4) 130.7 (34.4) 130.7
Net cash distributions to
Unitholders (57.4) (71.4) (113.2) (145.9)
Decrease in bank credit facilities - (4.0) (242.0) (30.0)
Increase in deferred charges - (0.7) - (0.7)
Change in non-cash working capital (0.3) (4.3) 6.8 (6.6)
----------------------------------------------------------------------------
(89.2) 53.9 (33.9) (43.2)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant
and equipment (33.6) (47.6) (106.2) (130.3)
Acquisition of oil and gas assets - - (11.5) -
Expenditures on future acquisition (0.8) (34.3) (0.8) (34.3)
Proceeds on disposal of property,
plant and equipment 47.6 0.1 47.6 3.2
Decrease in cash reserved for
future site reclamation 0.2 - 1.8 0.2
Change in non-cash working capital (11.7) (7.5) (10.9) 10.9
----------------------------------------------------------------------------
1.7 (89.3) (80.0) (150.3)
----------------------------------------------------------------------------
Increase in cash and cash
equivalents for the period 17.5 54.0 73.6 20.4
Cash and cash equivalents,
beginning of period 78.1 3.2 22.0 36.8
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period 95.6 57.2 95.6 57.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash interest paid 11.0 5.3 15.8 8.0
----------------------------------------------------------------------------
Cash taxes paid 0.2 0.4 0.6 1.1
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
($millions, except per
Trust Unit amounts) Jun 30, Jun 30, Jun 30, Jun 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
REVENUES
Sales of crude oil, natural
gas and natural gas liquids 186.5 156.8 376.2 348.9
Crown and other royalties (30.3) (31.9) (70.3) (76.5)
Realized gain on derivatives 1.6 5.5 7.6 4.5
Change in unrealized (gain)/loss
on derivatives 11.4 3.0 (20.1) 25.1
Other income 3.9 1.6 5.7 3.1
----------------------------------------------------------------------------
173.1 135.0 299.1 305.1
----------------------------------------------------------------------------
EXPENSES
Operating 34.6 31.1 73.6 63.8
Transportation 1.9 1.8 3.7 3.6
General and administrative 9.6 8.5 18.9 15.3
Interest 11.2 5.2 23.5 9.7
Debt issue costs (note 2) - - 8.0 -
Depletion, depreciation and
amortization 64.1 53.5 131.0 107.5
Accretion of asset retirement
obligation (note 3) 1.5 0.7 3.0 1.4
Foreign exchange gain (17.1) (7.3) (19.3) (6.6)
----------------------------------------------------------------------------
105.8 93.5 242.4 194.7
----------------------------------------------------------------------------
Income before taxes for the period 67.3 41.5 56.7 110.4
----------------------------------------------------------------------------
Income and capital taxes 1.3 (1.2) 1.5 (0.6)
Future income tax recovery
(note 11) (46.4) (23.0) (62.7) (23.7)
----------------------------------------------------------------------------
(45.1) (24.2) (61.2) (24.3)
----------------------------------------------------------------------------
Net income for the period 112.4 65.7 117.9 134.7
Other comprehensive income
Unrealized foreign exchange loss
on translation of self-sustaining
foreign operations (8.9) - (9.9) -
Tax effect on unrealized foreign
exchange loss on translation of
self-sustaining foreign
operations (3.1) - (3.5) -
----------------------------------------------------------------------------
Other comprehensive income (12.0) - (13.4) -
----------------------------------------------------------------------------
Comprehensive income 100.4 65.7 104.5 134.7
----------------------------------------------------------------------------
Net income per Trust Unit - basic
(note 5) 1.24 0.81 1.30 1.66
Net income per Trust Unit - diluted
(note 5) 1.17 0.79 1.26 1.62
----------------------------------------------------------------------------
See notes to interim consolidated financial statements
CONSOLIDATED STATEMENTS OF DEFICIT & ACCUMULATED COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
($ millions) (unaudited) Jun 30, Jun 30, Jun 30, Jun 30,
2007 2006 2007 2006
----------------------------------------------------------------------------
Deficit, beginning of period (1,115.4) (966.4) (1,046.0) (948.5)
Adoption of new financial
instrument accounting standard
(net of income tax recovery of
$0.1 million) (note 2) - - (7.3) -
Net income 112.4 65.7 117.9 134.7
Distributions paid or declared (68.1) (82.6) (135.7) (169.5)
----------------------------------------------------------------------------
Deficit, end of period (1,071.1) (983.3) (1,071.1) (983.3)
----------------------------------------------------------------------------
Accumulated other comprehensive
income, beginning of period 4.8 - 6.2 -
Other comprehensive income,
net of tax (12.0) - (13.4) -
----------------------------------------------------------------------------
Accumulated other comprehensive
income, end of period (7.2) - (7.2) -
----------------------------------------------------------------------------
Deficit and accumulated other
comprehensive income (1,078.3) (983.3) (1,078.3) (983.3)
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 30, 2007, 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 65 and 66 of the Trust's 2006 Annual Report, with
the exception of policies disclosed in note 2, and should be read in conjunction
with these interim financial statements.
2. Changes in Accounting Policies
Financial Instruments, Hedging Activities and Comprehensive Income
Effective January 1, 2007, the Trust adopted CICA Handbook section 3855, "Financial
Instruments - Recognition and Measurement," and CICA Handbook section 3861, "Financial
Instruments - Disclosure and Presentation." The Trust has adopted these sections
prospectively and the comparative interim consolidated financial statements have
not been restated for these accounting policy changes. Adoption of section 3855
allows for the cumulative effect of the change in accounting policy to be booked
as an adjustment to accumulated deficit with no restatement of prior periods. At
January 1, 2007, $7.2 million in financing charges net of income tax recovery of
$0.1 million were written off to the deficit. At January 1, 2007, other assets and
deferred charges on the balance sheet wwere reduced to $0.2 million.
Effective January 1, 2007, the Trust adopted CICA Handbook section 1530, "Comprehensive
Income." The Trust has adopted this section retroactively and prior periods have
been restated. At January 1, 2007, the change in accounting policy resulted in an
increase to accumulated other comprehensive income of $6.2 million net of tax (2006
-nil) and a decrease and elimination of the cumulative translation account of $6.2
million (2006 -nil).
Financial Instruments
All financial instruments must initially be recognized at fair value on the balance
sheet. The Trust has classified its financial instruments into the following categories:
held for trading financial assets and financial liabilities, loans or receivables,
held to maturity investments, available for sale financial assets, and other financial
liabilities. Subsequent measurement of the financial instruments is based on their
classification. Unrealized gains and losses on held for trading financial instruments
are recognized in earnings. Gains and losses, other than impairment losses, on available
for sale financial assets are recognized in other comprehensive income and are transferred
to earnings when the asset is de-recognized. The other categories of financial instruments
are recognized at amortized cost using the effective interest rate method. Impairment
losses are recorded in earnings when incurred.
Upon adoption and with any new financial instrument, an irrevocable election is
available that allows entities to classify any financial asset or financial liability
as held for trading, even if the financial instrument does not meet the criteria
to designate it as held for trading. The Trust has not elected to classify any financial
assets or financial liabilities as held for trading unless they meet the held for
trading criteria. A held for trading financial instrument is not a loan or receivable
and includes one of the following criteria:
- is a derivative, except for those derivatives that have been designated as effective
hedging instruments;
- has been acquired or incurred principally for the purpose of selling or repurchasing
in the near future; or
- is part of a portfolio of financial instruments that are managed together and
for which there is evidence of a recent actual pattern of short-term profit taking.
For financial assets and financial liabilities that are not classified as held for
trading, the transaction costs that are directly attributable to the acquisition
or issue of a financial asset or financial liability are expensed to earnings as
incurred.
Derivative Instruments and Hedging Activities
Derivative instruments are utilized by the Trust to manage market risk against the
volatility in commodity prices, foreign exchange rates and interest rate exposures.
The Trust's policy is not to utilize derivative instruments for speculative purposes.
The Trust may choose to designate derivative instruments as hedges. To date, the
Trust has not elected to apply hedge accounting.
All derivative instruments are recorded on the balance sheet at fair value. Freestanding
derivative instruments are classified as held for trading financial instruments.
Gains and losses on these instruments are recorded in the change in unrealized gains
and losses on derivatives in the consolidated statement of income and comprehensive
income in the period they occur.
The Trust enters into commodity price contracts to hedge anticipated sales of crude
oil and natural gas production to manage its exposure to price fluctuations. Gains
and losses from these contracts are recognized in realized gains and losses on derivatives
when the contracts are settled.
The Trust enters into cross currency swap agreements to hedge its fixed interest
rate and foreign currency exposures on foreign currency denominated long-term debt.
Gains and losses from these contracts are recognized in realized gains and losses
on derivatives as the related interest payments are made.
Fair values of the derivatives are based on quoted market prices where available.
The fair values of swaps and forwards are based on forward market prices. If a forward
price is not available for a commodity based forward, a forward price is estimated
using an existing forward price adjusted for quality or location.
Embedded Derivatives
Derivatives embedded in a host contract are classified as embedded derivatives.
These derivatives are required to be recorded separately from the host contract
when their economic characteristics and risks are not clearly and closely related
to those of the host contract, the terms of the embedded derivatives are the same
as those of a freestanding derivative and the combined contract is not classified
as held for trading or designated at fair value. The Trust has selected January
1, 2004, as its transition date for accounting for any potential embedded derivatives.
Comprehensive Income
Comprehensive income consists of net income and other comprehensive income. Other
comprehensive income comprises the change in the unrealized foreign exchange gain
/ loss on translation of financial statements of self-sustaining foreign operations.
Amounts included in other comprehensive income are shown net of tax. Accumulated
other comprehensive income is a new equity category comprised of the cumulative
amounts of other comprehensive income.
Foreign Currency Translation
The Trust has US dollar operations, which are self-sustaining. The self-sustaining
operations are translated into Canadian dollars using the current rate method. Under
this method, assets and liabilities are translated using period end exchange rates
with revenues and expenses translated using average rates for the period. Effective
January 1, 2007, gains and losses arising on the translation of assets and liabilities
are included in the comprehensive income account under Unitholder's equity.
Accounting Changes
Effective January 1, 2007, the Trust adopted the revised recommendations of CICA
Handbook Section 1506, "Accounting Changes."
The new recommendations permit voluntary changes in accounting policy only if they
result in financial statements which provide reliable and more relevant information.
Accounting policy changes are applied retrospectively unless it is impractical to
determine the period or cumulative impact of the change. Corrections of prior period
errors are applied retrospectively and changes in accounting estimates are applied
prospectively by including these changes in earnings. The guidance was effective
for all changes in accounting polices, changes in accounting estimates and corrections
of prior period errors initiated in periods beginning on or after January 1, 2007.
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.
3. Asset Retirement Obligations
Management has estimated the future asset retirement obligation based on the Trust's
net ownership interest in wells and facilities. This includes 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:
----------------------------------------------------------------------------
Asset Retirement Obligation $ Millions
----------------------------------------------------------------------------
Asset Retirement Obligation, December 31, 2006 91.5
Liabilities incurred 4.6
Liabilities settled (5.7)
Assets sold (4.5)
Accretion expense 3.0
----------------------------------------------------------------------------
Asset Retirement Obligation, June 30, 2007 88.9
----------------------------------------------------------------------------
As at June 30, 2007, the undiscounted amount of estimated cash flows required to
settle the obligation is $469.5 million. The estimated cash flow has been discounted
using a credit-adjusted risk free rate of 6.8% and an inflation rate of 2.0%. 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.
4. Long-Term Debt
----------------------------------------------------------------------------
Jun 30, Dec 31, Jun 30, Dec 31, Jun 30, Dec 31,
Maturity 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Canadian Dollar US Dollar Pounds
Amounts Denominated Sterling
(millions) (millions) (millions)
Bank credit
facilities 215.2 477.3 202.0 202.0 - -
7.5% debentures 2009 24.0 24.0 - - - -
US secured notes 2010 99.9 145.7 93.8 125.0 - -
7.75% debentures 2011 15.0 15.0 - - - -
6.5% debentures 2012 193.3 - - - - -
U.K. secured notes 2016 134.4 143.8 - - 63.0 63.0
----------------------------------------------------------------------------
Total debt 681.8 805.8 295.8 327.0 63.0 63.0
-------------------------------
Current portion of
long-term debt 33.3 186.4
--------------------------------------------
Total of
long-term debt 648.5 619.4
--------------------------------------------
On January 11, 2007, PrimeWest issued $200 million of Series III Convertible Unsecured
Debentures for net proceeds of $192.0 million. The debt issue costs of $8.0 million
were expensed to earnings. 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 obligation to repay the principal by issuing Trust Units.
The Series III Convertible Debentures are presented on the balance sheet in their
debt and equity components. The debt component represents the discounted present
value of the semi-annual interest obligations and the principal payment due at maturity,
using the rate of the interest that would have been applicable to a non-convertible
debt instrument of comparable term and risk at the date of issue. The debt component
increases over the term of the debenture to the full fair value of the outstanding
debenture at maturity. The difference is reflected as accretion expense on the income
statement. The equity component is presented in Unitholders' Equity on the balance
sheet. The equity component represents the value ascribed to the conversion right
which remains a fixed amount over the term of the debenture. Upon conversion of
the debenture into Trust Units, a proportionate amount of both the debt and equity
components are transferred to Unitholders' capital.
The current portion of long-term debt includes $33.3 million relating to the US
Secured Notes payable on May 7, 2008.
5. Unitholders' Equity
The authorized capital of the Trust consists of an unlimited number of Trust
Units.
----------------------------------------------------------------------------
Trust Units Number of Units $ Millions
----------------------------------------------------------------------------
Balance, December 31, 2006 83,256,610 2,378.9
Issued pursuant to equity offering 6,420,000 142.4
Issued pursuant to Distribution Reinvestment Plan 423,400 9.0
Issued pursuant to Premium Distribution Plan 585,380 12.5
Issued pursuant to Optional Trust Unit Purchase Plan 306,087 6.5
Issued pursuant to Long-Term Incentive Plan 33,209 0.2
Conversion of Convertible Unsecured Subordinated
Debentures 1,886 0.1
Issued pursuant to exchange of Exchangeable Shares 2,573 -
Issued pursuant to Consolidation/Fractional Units 4 -
----------------------------------------------------------------------------
Balance, June 30, 2007 91,029,149 2,549.6
----------------------------------------------------------------------------
The weighted average number of Trust Units and Exchangeable Shares outstanding for
the three months ended June 30, 2007, was 90,315,850 (2006 - 81,726,126). For purposes
of calculating diluted net income per Trust Unit for the three months ended June
30, 2007, 560,949 (2006 - 1,302,773) Trust Units issueable pursuant to the LTIP
and 9,066,481 (2006 - 1,717,406) Trust Units issueable pursuant to the conversion
of the Debentures were added to the weighted average number.
The weighted average number of Trust Units and Exchangeable Shares outstanding for
the six months ended June 30, 2007, was 90,734,065 (2006 - 81,013,827). For the
purposes of calculating diluted net income per Trust Unit for the six months ended
June 30, 2007, 560,949 (2006 - 1,302,773) Trust Units issueable pursuant to the
LTIP and 9,067,325 (2006 - 1,836,114) Trust Units issueable pursuant to the conversion
of the Debentures were added to the weighted average number.
On January 11, 2007, PrimeWest issued 6,420,000 Trust Units at a price of $23.35
per Trust Unit for net proceeds of $142.4 million.
Exchangeable Shares
The Exchangeable Shares are exchangeable into Trust Units at any time up to March
29, 2015 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
June 15, 2007, was 0.68067:1 which is equivalent to 788,262 Trust Units.
----------------------------------------------------------------------------
Exchangeable Shares Number of Shares $ Millions
----------------------------------------------------------------------------
Balance, December 31, 2006 1,161,864 12.3
Exchanged for Trust Units (3,796) -
----------------------------------------------------------------------------
Balance, June 30, 2007 1,158,068 12.3
----------------------------------------------------------------------------
6. Financial Instruments and Risk Management
The Trust's financial instruments presented on the balance sheet consist of cash,
accounts receivable, accounts payable and accrued liabilities, accrued distributions
to Unitholders, derivative assets, derivative liabilities and long-term debt. Other
than the long-term debt, the fair market value of these financial instruments approximate
their carrying value due to the short-term to maturity and the risk management contacts
are presented at fair value on the balance sheet. The fair value of long-term debt
is disclosed in the following table.
----------------------------------------------------------------------------
Jun 30, Jun 30, Jun 30, Dec 31, Dec 31,
2007 2007 2007 2006 2006
----------------------------------------------------------------------------
Face Carrying(1) Fair Face Carrying(1)
value value value value value
Bank credit facilities - - - 242.0 242.0
7.5% debentures 23.7 24.0 24.3 24.0 24.0
7.75% debentures 14.7 15.0 15.4 15.0 15.0
6.5% debentures 200.0 193.3 199.0 - -
----------------------------------------------------------------------------
Total Cdn $ denominated debt 238.4 232.3 238.7 281.0 281.0
----------------------------------------------------------------------------
Bank credit facilities 202.0 202.0 202.0 202.0 202.0
US $ denominated secured notes 93.8 93.8 89.5 125.0 125.0
----------------------------------------------------------------------------
Total US $ denominated debt 295.8 295.8 291.5 327.0 327.0
----------------------------------------------------------------------------
Pounds Sterling denominated
debt - U.K. secured notes 63.0 63.0 59.0 63.0 63.0
----------------------------------------------------------------------------
(1) Excludes equity component.
Commodity Price Risk Management
PrimeWest generally sells its oil and natural gas under short-term market-based
contacts. Derivative financial instruments, collars and swaps may be used to hedge
the impact of oil and natural gas fluctuations.
Foreign Exchange Rate Risk
The Trust is exposed to fluctuations in the Canadian /US dollar exchange rate on
the sale of commodities that are denominated in US dollars or directly influenced
by US dollar benchmark prices. In addition, the Trust's 4.19% US Secured Notes are
denominated in US dollars. The semi-annual interest payments and principal payments
associated with the US Senior Notes can be impacted by movement in the Canadian/US
dollar exchange rate. PrimeWest, through the use of a financial swap, has converted
the U.K. Secured Notes from pounds sterling to Canadian dollar debt. This currency
swap has fixed the aggregate principal value and annual interest payments on this
Pounds Sterling 63.0 million debt at $130.7 million and $3.9 million respectively.
Impact on Financial Statements
The commodity price risk financial instruments and currency swaps have been recorded
at fair value on the balance sheet with the offset included in the unrealized gain
or loss on derivatives on the income statement.
At June 30, 2007, $15.1 million was recorded as a current derivative asset related
to natural gas. $0.6 million was recorded as a long-term derivative asset related
to natural gas and $1.3 million was recorded as a current derivative liability related
to crude oil. $5.7 million was recorded as a long-term derivative liability comprised
of a $0.3 million unrealized loss on crude oil and a $5.4 million unrealized loss
attributable to foreign exchange.
For the three months ended June 30, 2007, the change in the unrealized gain on the
statement of income was $11.4 million comprised of a $21.0 million change in the
gain related to natural gas, a $1.7 million change in the loss related to crude
oil and a $7.9 million change in the loss related to foreign exchange. For the six
months ended June 30, 2007, the total change in unrealized loss on the income statement
was $20.1 million comprised of a $7.7 million change in the loss related to crude
oil, a $2.4 million change in the loss related to natural gas and a $10.0 million
change in the loss attributable to foreign exchange.
The financial impact on the settlement of contracts during the second quarter of
2007 recorded in realized derivative gain on the income statement was a $1.6 million
gain comprised of a $0.9 million gain related to natural gas and a $0.7 million
gain related to crude oil. The financial impact of the settlement of contracts for
the six months ended June 30, 2007, was a $7.6 million realized derivative gain
comprised of a $3.4 million gain related to crude oil and a $4.2 million gain related
to natural gas.
7. Contributed Surplus
Contributed surplus includes the accumulated unit-based compensation charge in respect
of PrimeWest's unexercised Unit Appreciation Rights (UARs) 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, 2006 11.9
General and administrative expense - unit appreciation rights 3.4
Unit Appreciation Rights exercised (0.3)
----------------------------------------------------------------------------
Balance, June 30, 2007 15.0
----------------------------------------------------------------------------
8. Deficit
----------------------------------------------------------------------------
($ millions) Jun 30, 2007 Dec 31,2006
----------------------------------------------------------------------------
Accumulated income 622.7 512.1
Accumulated distributions paid or declared (1,685.8) (1,550.1)
Accumulated dividends (8.0) (8.0)
----------------------------------------------------------------------------
(1,071.1) (1,046.0)
----------------------------------------------------------------------------
9. Segmented Information
The Trust's business activities are conducted through two business segments: Canadian
oil and natural gas production and US oil and natural gas production. Oil and natural
gas production in Canada and the US includes development and production of crude
oil and natural gas reserves. The following tables includes financial results from
the US operations for the three and six months ended June 30, 2007. Prior to July
2006, the Trust operated in only one segment.
----------------------------------------------------------------------------
Three Months Ended Jun 30, 2007
----------------------------------------------------------------------------
Inter
Segment
$ Millions Canada US Elimination Total
----------------------------------------------------------------------------
Revenues
Sale of oil, natural gas and natural
gas liquids 172.4 14.1 - 186.5
Realized gain in financial derivatives 0.9 0.7 - 1.6
Royalties (27.5) (2.8) - (30.3)
Other income 3.8 0.1 - 3.9
----------------------------------------------------------------------------
149.6 12.1 - 161.7
Expenses
Operating 30.9 3.7 - 34.6
Transportation 1.9 - - 1.9
General and administrative 9.1 0.5 - 9.6
----------------------------------------------------------------------------
41.9 4.2 - 46.1
----------------------------------------------------------------------------
Earnings before interest, taxes and
DD&A and other non-cash items 107.7 7.9 - 115.6
Non-cash revenue
----------------------------------------------------------------------------
Unrealized gain/(loss) on derivatives 11.4 - - 11.4
----------------------------------------------------------------------------
Other expenses
DD&A 59.4 4.7 - 64.1
Interest 7.7 3.5 - 11.2
Foreign exchange loss/(gain) (17.1) - - (17.1)
Accretion on asset retirement
obligation 1.4 0.1 - 1.5
Income and capital taxes 1.1 0.2 - 1.3
Future income tax recovery (46.2) (0.2) - (46.4)
----------------------------------------------------------------------------
6.3 8.3 - 14.6
----------------------------------------------------------------------------
Net income for the period 112.8 (0.4) - 112.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months Ended Jun 30, 2007
----------------------------------------------------------------------------
Inter
Segment
$ Millions Canada US Elimination Total
----------------------------------------------------------------------------
Revenues
Sale of oil, natural gas and natural
gas liquids 349.0 27.2 - 376.2
Realized gain in financial derivatives 5.2 2.4 - 7.6
Royalties (64.8) (5.5) - (70.3)
Other income 5.5 0.2 - 5.7
----------------------------------------------------------------------------
294.9 24.3 - 319.2
Expenses
Operating 66.4 7.2 - 73.6
Transportation 3.7 - - 3.7
General and administrative 17.7 1.2 - 18.9
----------------------------------------------------------------------------
87.8 8.4 - 96.2
----------------------------------------------------------------------------
Earnings before interest, taxes and
DD&A and other non-cash items 207.1 15.9 - 232.0
Non-cash revenue
----------------------------------------------------------------------------
Unrealized loss on derivatives (20.1) - - (20.1)
----------------------------------------------------------------------------
Other expenses
DD&A 121.4 9.6 - 131.0
Interest 16.2 7.3 - 23.5
Debt issue costs 8.0 - - 8.0
Foreign exchange loss/(gain) (19.3) - - (19.3)
Accretion on asset retirement
obligation 2.8 0.2 - 3.0
Income and capital taxes 1.1 0.4 - 1.5
Future income tax recovery (62.0) (0.7) - (62.7)
----------------------------------------------------------------------------
68.2 16.8 - 85.0
----------------------------------------------------------------------------
Net income for the period 118.8 (0.9) - 117.9
----------------------------------------------------------------------------
Selected Balance Sheet Items at June 30, 2007
Capital assets
Property, plant and equipment, net 1,906.1 336.2 - 2,242.3
Goodwill 68.5 - - 68.5
Capital expenditures
Acquisition of oil and gas properties 10.6 1.7 - 12.3
Development and head office 82.4 23.8 - 106.2
Working capital
Accounts receivable 80.3 3.8 0.7 84.8
Account payable and accrued liabilities 97.4 18.7 (0.7) 115.4
Current portion of long-term debt 33.3 - - 33.3
Long-term debt 433.3 215.2 - 648.5
----------------------------------------------------------------------------
10. Long-Term Incentive Plan
PrimeWest recorded $1.7 million (2006 - $1.0 million) and $3.4 million (2006 - $2.0
million) in general and administrative expense related to the Long-Term Incentive
Plan for the three and six months ended June 30, 2007, respectively, using the fair
value method of accounting.
PrimeWest used a binomial lattice 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: Jun 30, 2007 Jun 30, 2006
----------------------------------------------------------------------------
Risk-free interest rate 3.98% 3.85%
Expected volatility in Trust Unit price 26.0% 22.5%
Expected time until exercise 1.5 - 3.5 years 3.5 years
Expected forfeiture rate 13.3% 10.6%
Expected annual dividend yield zero zero
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Summary of Changes in Number of Weighted Average
Unit Appreciation Rights UARS Strike Price
----------------------------------------------------------------------------
Balance outstanding at December 31, 2006 4,460,040 31.96
Granted 1,762,931 23.49
Forfeited (88,641) 30.44
Exercised (76,642) 27.56
----------------------------------------------------------------------------
Balance outstanding at June 30, 2007 6,057,688 29.57
----------------------------------------------------------------------------
11. Future Income Tax
On June 22, 2007, legislation was enacted that effectively imposes income tax for
income trusts, including royalty trusts, for taxation years beginning in 2011. The
enactment of this legislation triggered the recognition of future Canadian corporate
income tax assets on all entities within the PrimeWest structure, with a corresponding
impact on future Canadian corporate income tax recovery, based on temporary differences
expected to reverse after the date that the taxation changes take effect. The $46.7
million recovery to future income tax recorded in the second quarter of 2007 as
a result of this new legislation is based on estimated gross temporary differences
of approximately $170.2 million that are expected to reverse after 2010, which,
using an effective tax rate of 31.5%, results in a future tax asset of $46.7 million
at June 30, 2007.
12. Subsequent Event Note
On July 11, 2007, PrimeWest Energy Trust merged with Shiningbank Energy Income Fund.
Shiningbank Trust Units were exchanged for 0.62 of a PrimeWest Trust Unit resulting
in the issuance of 53,647,473 PrimeWest Trust Units. The transaction will be accounted
for as a business combination using the purchase price method. Total consideration
was $1.2 billion.
Upon the completion of the merger with Shiningbank on July 11, 2007, PrimeWest entered
into a new 3-year unsecured extendible revolving credit facility with a syndicate
of chartered banks and other financial institutions. The credit facility provides
for Cdn $1.1 billion of credit capacity for PrimeWest's operations in Canada and
US $235 million of credit capacity for PrimeWest's operations in the United States.
With the consent of the lenders, the 3-year term of the credit facility may be extended
on an annual basis for an additional year. Advances under the credit facility may
be made by way of Canadian and US dollar denominated prime rate loans, Canadian
dollar denominated bankers' acceptances, US dollar denominated LIBOR advances and
letters of credit. These advances bear interest at the lenders' borrowing costs
plus a stamping fee, or the applicable prime rate plus a margin. PrimeWest is required
under the credit facility to maintain certain financial covenants.
TRADING PERFORMANCE
----------------------------------------------------------------------------
For the quarter ended Jun 30/07 Mar 31/07 Dec 31/06 Sep 30/06 Jun 30/06
----------------------------------------------------------------------------
TSX Trust Unit Prices
(C$ per Trust Unit)
High 23.94 23.37 29.21 35.42 35.30
Low 22.12 19.98 20.87 27.33 30.62
Close 22.39 22.72 21.50 27.35 33.50
----------------------------------------------------------------------------
Average daily traded volume 334,005 255,263 391,293 225,732 258,294
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the quarter ended Jun 30/07 Mar 31/07 Dec 31/06 Sep 30/06 Jun 30/06
----------------------------------------------------------------------------
NYSE Trust Unit Prices
(US$ per Trust Unit)
High 22.47 20.26 25.94 31.29 30.91
Low 19.34 17.01 18.03 24.45 27.76
Close 21.03 19.69 18.47 24.64 29.98
----------------------------------------------------------------------------
Average daily traded volume 478,381 450,593 796,677 441,508 438,995
----------------------------------------------------------------------------
Number of Trust Units
outstanding including
Exchangeable Shares
(thousands of Trust Units) 91,817 91,144 83,257 82,719 81,439
----------------------------------------------------------------------------
Distribution paid per
Trust Unit 0.75 0.75 0.75 0.90 1.02
----------------------------------------------------------------------------
CORPORATE INFORMATION
(effective July 11, 2007) Corporate Offices
Board of Directors Suite 5100, 150 Sixth Avenue S.W.
Calgary, Alberta Canada T2P 3Y6
Harold P. Milavsky, Chair (1,2) Tel: (403) 234-6600
Barry E. Emes (1,2) Fax: (403) 699-7477
David M. Fitzpatrick (4) Toll-Free: 1-877-968-7878
Robert B. Hodgins (1) Website: www.primewestenergy.com
Harold N. Kvisle (3,4) Email:
investor@primewestenergy.com
Kent J. MacIntyre (3,4)
W. Glen Russell, (3,4) Trust Units and Exchangeable Shares
Warren D. Steckley (4)
Peter Valentine (1,2) The Toronto Stock Exchange (PWI.UN; PWX)
The New York Stock Exchange (PWI)
(1) Audit and Finance Committee
(2) Corporate Governance Convertible Debentures
Committee
(3) Compensation Committee The Toronto Stock Exchange
(4) Operations & Reserves
Committee Series I Debentures (PWI.DB.A)
Series II Debentures (PWI.DB.B)
Officers Series III Debentures (PWI.DB.C)
Donald A. Garner Registrar and Transfer Agent
President and Chief Executive
Officer Computershare Trust Company of Canada
Toll-free in Canada: 1-800-564-6253
Ronald J. Ambrozy
Vice President, Business Auditor
Development
PricewaterhouseCoopers LLP
Douglas S. Fraser Calgary, Alberta
Vice President, Finance and Chief
Financial Officer Engineering Consultants
Timothy S. Granger GLJ Petroleum Consultants Ltd.
Chief Operating Officer Calgary, Alberta
Gordon D. Haun Legal Counsel
Vice President, Legal and General
Counsel Stikeman Elliott LLP
Calgary, Alberta
Gregory D. Moore
Vice President, Operations
J. Lance Petersen
Vice President, Land
R. Bruce Thornhill
Vice President, Geosciences
Murrary J. Desrosiers
Corporate Secretary and Associate
General Counsel
FOR FURTHER INFORMATION PLEASE CONTACT:
PrimeWest Energy Trust
George Kesteven
Manager, Investor Relations
(403) 699-7367 or Toll Free: 1-877-968-7878
or
PrimeWest Energy Trust
Debbie Carver
Investor Relations Advisor
(403) 699-7464 or Toll Free: 1-877-968-7878
Email: investor@primewestenergy.com
Website: www.primewestenergy.com