PrimeWest Energy Trust Announces Third Quarter 2006 Results
NOV 7, 2006 - 19:17 ET
CALGARY, ALBERTA--(CCNMatthews - Nov. 7, 2006) - PRIMEWEST ENERGY TRUST (TSX:PWI.UN)
(TSX:PWI.DB.A) (TSX:PWI.DB.B) (TSX:PWX) (NYSE:PWI) (PRIMEWEST OR THE TRUST) TODAY
ANNOUNCES INTERIM OPERATING AND FINANCIAL RESULTS FOR THE QUARTER ENDED SEPTEMBER
30, 2006. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT ARE IN CANADIAN
DOLLARS.
Third Quarter 2006 Highlights:
- Distributions in the third quarter were $0.90 per Trust Unit representing a payout
ratio of approximately 77% of operating cash flow compared to second quarter 2006
distributions of $1.02 per Trust Unit, which represented a payout ratio of approximately
93% of cash flow from operations.
- On July 6, 2006, PrimeWest, through a U.S. subsidiary, acquired producing oil
and gas assets located in Montana, North Dakota, Wyoming and Saskatchewan for consideration
of $336.7 million. The acquisition establishes a new operating area for PrimeWest
within the Williston Basin with considerable waterflood and development drilling
potential. The U.S. assets contributed 2,756 barrels of oil equivalent (BOE) per
day to the third quarter production volumes.
- On August 25, 2006, PrimeWest acquired natural gas assets in the Caroline area
for a net adjusted purchase price of $31.9 million. The acquisition of these assets,
already operated by PrimeWest, represents the conclusion of a farm in arrangement
between PrimeWest and the vendor. Production volumes from the assets are approximately
550 BOE per day.
- Cash flow from operations for the third quarter was $96.6 million ($1.17 per Trust
Unit) compared to $88.6 million ($1.08 per Trust Unit) in the previous quarter and
$106.4 million ($1.36 per Trust Unit) in the third quarter of 2005.
- Third quarter 2006 production averaged 40,381 BOE per day, compared to the second
quarter 2006 rate of 37,406 BOE per day. The increase in volumes is mainly due to
the acquisition of the U.S. assets in July. The U.S. volumes offset the loss of
production due to the maintenance shut-in at the Crossfield plant in September.
PrimeWest expects full year 2006 production volumes to average between 39,000 -
40,000 BOE per day.
- Development capital expenditures in the third quarter were $76.3 million with
drilling, completion and tie-in expenditures of $62.5 million resulting in 81 gross
wells (56.3 net) being drilled with a success rate of 95%.
- Net debt to annualized third quarter 2006 cash flow from operations was approximately
2.0 times at September 30, 2006 compared to net debt to annualized second quarter
2006 cash flow from operations of 1.2 times at June 30, 2006. This increase is primarily
due to additional debt utilized to finance the U.S. asset acquisition.
SUBSEQUENT EVENT
- On October 31, 2006, the federal government announced its intention to change
the way that royalty trusts and income funds are taxed, which would take effect
January 1, 2011. If the proposals are enacted, a tax will be applied at the trust
level on distributions at rates of tax comparable to the combined federal and provincial
corporate tax, estimated at 31.5%, and to treat distributions as dividends to the
Unitholders. Until such rules are released in legislative form and passed into law,
it is uncertain what the impact of such rules will be to the Trust and its Unitholders.
MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF NOVEMBER 7, 2006
The following is management's discussion and analysis (MD&A) of PrimeWest's operating
and financial results for the quarter and nine months ended September 30, 2006,
compared with the preceding quarter, the corresponding periods in the prior year
and the year ended December 31, 2005, as well as information and opinions concerning
the Trust's future outlook based on currently available information.
Forward-Looking Information
This MD&A contains forward-looking or outlook information with respect to PrimeWest.
Certain statements contained in this MD&A, and any documents incorporated by reference
into this MD&A, constitute forward-looking statements. The use of any of the words
"anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project",
"should", "believe", "outlook" and similar expressions are intended to identify
forward-looking statements. In addition, statements relating to "reserves" or "resources"
are deemed to be forward-looking statements, as they involve implied assessment,
based on certain estimates and assumptions, that the resources and reserves described
can be profitably produced in the future. These statements involve known and unknown
risks, uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in our forward-looking statements.
We believe the expectations reflected in those forward-looking statements are reasonable.
However, we cannot assure you that these expectations will prove to be correct.
You should not unduly rely on forward-looking statements included in, or incorporated
by reference into this MD&A. These statements speak only as of the date of this
MD&A.
In particular, this MD&A contains forward-looking statements pertaining to the following:
- the quantity and recoverability of our reserves;
- the timing and amount of future production;
- prices for oil, natural gas and natural gas liquids produced;
- operating and other costs;
- business strategies and plans of management;
- supply and demand for oil and natural gas;
- expectations regarding our ability to raise capital and to add to our reserves
through acquisitions and exploration and development;
- our treatment under governmental regulatory regimes;
- the focus of capital expenditures on development activity rather than exploration;
- the sale, farming in, farming out or development of certain exploration properties
using third-party resources;
- the objective to achieve a predictable level of monthly cash distributions;
- the intention of maintaining a payout ratio of distributions to cash flow from
operations within any range;
- the use of development activity and acquisitions to replace and add to reserves;
- the impact of changes in oil and natural gas prices on cash flow after hedging;
- drilling plans;
- the existence, operations and strategy of the commodity price risk management
program;
- the approximate and maximum amount of forward sales and hedging to be employed;
- our acquisition strategy, the criteria to be considered in connection therewith
and the benefits to be derived therefrom;
- the impact of the Canadian federal and provincial governmental regulation on us
relative to other oil and natural gas issuers of similar size;
- the goal to sustain or grow production and reserves through prudent management
and acquisitions;
- the emergence of accretive growth opportunities; and
- our ability to benefit from the combination of growth opportunities and the ability
to grow through the capital markets.
With respect to forward-looking statements contained in this MD&A, we have made
assumptions regarding, among other things:
- future oil and natural gas prices and differentials between light, medium and
heavy oil prices;
- the cost of expanding our property holdings;
- our ability to obtain equipment in a timely manner to carry out development activities;
- our ability to market our oil and natural gas successfully to current and new
customers;
- the impact of increasing competition;
- our ability to obtain financing on acceptable terms; and
- our ability to add production and reserves through our development and exploitation
activities.
Our actual results could differ materially from those anticipated in these forward-looking
statements as a result of the risk factors set forth below and elsewhere in this
MD&A:
- volatility in market prices for oil and natural gas;
- the impact of weather conditions on seasonal demand;
- risks inherent in our oil and natural gas operations;
- uncertainties associated with estimating reserves;
- competition for, among other things: capital, acquisitions of reserves, undeveloped
lands and skilled personnel;
- incorrect assessments of the value of acquisitions;
- geological, technical, drilling and processing problems;
- general economic conditions in Canada, the United States and globally;
- industry conditions, including fluctuations in the price of oil and natural gas;
- royalties payable in respect of our oil and natural gas production;
- government regulation of the oil and natural gas industry, including environmental
regulation;
- fluctuation in foreign exchange or interest rates;
- unanticipated operating events that can reduce production or cause production
to be shut-in or delayed;
- failure to obtain industry partner and other third-party consents and approvals,
when required;
- stock market volatility and market valuations;
- OPEC's ability to control production and balance global supply and demand of crude
oil at desired price levels;
- political uncertainty, including the risks of hostilities, in the petroleum producing
regions of the world;
- the need to obtain required approvals from regulatory authorities; and
- the other factors discussed under "Business Risk Factors" contained in this MD&A.
These factors should not be construed as exhaustive. The forward-looking statements
contained in this MD&A and herein are expressly qualified by these cautionary statements.
We undertake no obligation to publicly update or revise any forward-looking statements.
PrimeWest does not endorse any analyst or consultant sourced material contained
herein.
Production figures stated in this MD&A are Company Interest before the deduction
of royalties.
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer, Don Garner, and the Chief Financial Officer, Dennis
Feuchuk, evaluated the effectiveness of PrimeWest's disclosure controls and procedures
as of September 30, 2006, and concluded that PrimeWest's disclosure controls and
procedures were effective to ensure that information PrimeWest is required to disclose:
- in its annual filings, interim filings or other reports (each as defined in National
Instrument 52-109 of the Canadian Securities Administrators) filed or submitted
by it under provincial securities legislation is recorded, processed, summarized
and reported within the time periods specified in the provincial securities legislation
and to ensure that information required to be disclosed by PrimeWest in its annual
filings, interim filings or other reports filed or submitted under provincial securities
legislation is accumulated and communicated to PrimeWest's management, including
its Chief Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure; and
- in its annual filings, interim filings or other reports with the United States
Securities and Exchange Commission (SEC) in the United States (U.S.) under the Securities
Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported,
within the time periods specified in the Commission's rules and forms, and to ensure
that information required to be disclosed by PrimeWest in the reports that it files
under the Exchange Act is accumulated and communicated to PrimeWest's management,
including its principal executive officer and principal financial officer, as appropriate
to allow timely decisions regarding required disclosure.
The evaluation took into consideration PrimeWest's Communications and Disclosure
Policy and the functioning of its Executive Officers, Board of Directors and Board
Committees. In addition, the evaluation covered PrimeWest's processes, systems and
capabilities relating to regulatory filings, public disclosures and the identification
and communication of material information.
Changes to Internal Controls Over Financial Reporting
There were no changes to PrimeWest's internal control over financial reporting since
June 30, 2006 that have materially affected, or are reasonably likely to materially
affect PrimeWest's internal control over financial reporting.
Non-GAAP Measures
This MD&A contains the following measurements that are not defined by Canadian Generally
Accepted Accounting Principles (GAAP):
- Cash flow from operations on a total and per Trust Unit basis;
- Distributions per Trust Unit; and
- Net debt and net debt per Trust Unit.
These measurements do not have any standardized meaning prescribed by GAAP and are,
therefore, unlikely to be comparable to similar measures presented by other entities.
Cash flow from operations is calculated from the Trust's cash flow statement as
cash flow from operating activities before changes in working capital. Cash flow
from operations per Trust Unit on a basic basis is calculated by dividing cash flow
from operations by the weighted average number of Trust Units outstanding plus Trust
Units issuable upon the exchange of the outstanding Exchangeable Shares of PrimeWest
Energy Inc. (Exchangeable Shares). Cash flow from operations per Trust Unit on a
diluted basis is calculated using cash flow 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 PrimeWest's
Long Term Incentive Plan (LTIP). Cash flow from operations is a key performance
indicator of PrimeWest's ability to generate cash and finance operations and pay
monthly distributions.
Distributions per Trust Unit disclose the cash distributions accrued in 2006 based
on the number of Trust Units outstanding on the Record Date.
Net debt 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. Net debt per Trust Unit is calculated as net debt divided
by the number of Trust Units outstanding and includes Trust Units issueable upon
the exchange of outstanding Exchangeable Shares and Trust Units issueable pursuant
to the LTIP at September 30, 2006.
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 United States. PrimeWest is one of North America's
largest natural gas-weighted energy trusts.
Maximizing total return to Unitholders, in the form of cash distributions and appreciation
in unit price, is PrimeWest's overriding objective. Our strategies for asset management
and growth, financial management and corporate governance are outlined in this MD&A,
along with a discussion of our performance in the third quarter of 2006 and our
goals for 2006 and beyond.
We believe that PrimeWest can maximize total return to Unitholders by continuing
to develop our core properties, making opportunistic acquisitions that emphasize
value creation, exercising disciplined financial management which broadens access
to capital while minimizing risk to Unitholders, and complying with strong corporate
governance principles to protect the interests of all stakeholders.
Asset Management and Growth
PrimeWest has a strategy to focus expansion efforts on existing core areas and pursue
depletion optimization strategies to maximize asset value. We make every effort
to obtain operatorship of our asset base and maintain high working interests in
core areas. We currently maintain operatorship of 80% of our assets, which allows
us to use existing infrastructure and synergies within our core areas. We believe
this high level of control can translate into cost efficiencies and timing of capital
outlays and projects. The current size of the Trust gives us the ability and critical
mass to make acquisitions of significant size, while being able to add value by
transacting smaller acquisitions.
Financial Management
PrimeWest strives to maintain a prudent debt position, to allow us to fund smaller
acquisitions and to fund ongoing development activities without tapping the capital
markets. Our long-term debt is comprised of bank credit facilities through a bank
syndicate, US-dollar-denominated Senior Secured Notes (U.S. Secured Notes), Pounds
Sterling denominated Senior Secured Notes (U.K. Secured Notes) and Debentures. Our
diversified debt instruments help to reduce our reliance on the bank syndicate.
PrimeWest's commodity hedging strategy is designed to reduce the volatility of cash
flow by providing some near term downside price protection. Hedging a portion of
our production protects acquisition economics and our capital structure and provides
partial protection against short-term declines in commodity prices. Since 2003,
PrimeWest has followed a strategy of maintaining a distribution payout ratio within
70%-90% of cash flow from operations, calculated on an annual basis, recognizing
that during periods of volatile commodity prices the payout ratio may move out of
this range. The Board of Directors of PrimeWest considers a variety of factors in
establishing the monthly distribution level including, but not limited to: commodity
price outlook, cash flow forecast, capital development plans, debt levels, tax considerations
and competitive industry distribution practices.
The third quarter 2006 payout ratio was approximately 77% of cash flow from operations.
Retained cash flow was utilized to fund a part of the Trust's capital spending program.
PrimeWest's net debt to annualized third quarter cash flow ratio was 2.0 times at
September 30, 2006.
PrimeWest's dual listing on the Toronto Stock Exchange (TSX) and New York Stock
Exchange (NYSE) provides increased liquidity and a broadened investor base. The
NYSE listing enables U.S. Unitholders to conveniently trade in our Trust Units,
and allows us to access the U.S. capital markets. Our status as a corporation for
U.S. tax purposes simplifies tax reporting for our U.S. Unitholders.
For eligible Canadian and U.S. Unitholders, PrimeWest offers participation in the
conventional Distribution Reinvestment Plan (DRIP), which represents a convenient
way to maximize an investment in PrimeWest. Canadian residents may also participate
in the Optional Trust Unit Purchase Plan (OTUPP) and the Premium Distribution Plan
(PREP). For alternate investment requirements, PrimeWest also has Exchangeable Shares
and Debentures issued and outstanding.
Corporate Governance
PrimeWest remains committed to high standards of corporate governance and upholds
the rules of the governing regulatory bodies under which it operates. Full disclosure
of our compliance with existing corporate governance rules and regulations is available
on our website at
www.primewestenergy.com.
PrimeWest actively monitors the corporate governance and disclosure environment
to ensure compliance with current and future requirements.
Our high standards of corporate governance are not limited to the boardroom. At
the field level, PrimeWest proactively manages environmental, health and safety
issues. We place a great deal of importance on community involvement and maintaining
good relationships with landowners.
Financial Highlights
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
$ Millions, except per BOE(1) Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
and per Trust Unit amounts 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Gross revenue (net of
transportation expense) 181.9 160.4 193.3 531.6 516.4
per BOE 48.98 47.14 52.38 50.42 46.84
Cash flow from operations 96.6 88.6 106.4 288.4 281.6
per BOE 26.00 26.04 28.83 27.36 25.54
per Trust Unit - basic (2) 1.17 1.08 1.36 3.53 3.78
per Trust Unit - diluted (3) 1.15 1.06 1.31 3.45 3.55
Royalty expense 34.5 31.9 44.4 111.0 117.3
per BOE 9.29 9.36 12.04 10.53 10.64
Operating expense 34.8 31.2 31.6 98.7 84.1
per BOE 9.36 9.16 8.56 9.36 7.63
General and administrative
expense (G&A) 6.5 8.5 7.2 21.8 20.1
per BOE 1.76 2.49 1.95 2.06 1.83
Interest expense (4) 11.9 5.2 6.0 21.6 22.8
per BOE 3.20 1.52 1.61 2.05 2.07
Distributions to Unitholders 74.0 82.8 70.1 243.5 200.5
per Trust Unit (5) 0.90 1.02 0.90 3.00 2.70
Net debt (6) 772.4 415.5 381.8 772.4 381.8
per Trust Unit (7) 9.16 4.98 4.75 9.16 4.75
---------------------------------------------------------------------------
(1) All calculations required to convert natural gas to a crude oil
equivalent (BOE) have been made using a ratio of 6,000 cubic feet of
natural gas to one barrel of crude oil. BOE's may be misleading,
particularly if used in isolation. The BOE conversion ratio is based
on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.
(2) The basic per Trust Unit calculation includes the weighted average
Trust Units and Trust Units issueable upon exchange of the Exchangeable
Shares.
(3) The diluted per Trust Unit calculation includes the weighted
average Trust Units outstanding, Trust Units issueable upon exchange
of the outstanding Exchangeable Shares, the deemed conversion of the
Debentures and Trust Units issueable pursuant to the LTIP. Interest
expense incurred on the Debentures is added back to net income and
to cash flow for the diluted per Trust Unit calculation.
(4) Interest expense includes the interest on the Debentures.
(5) Based on Trust Units outstanding at the record dates for distributions
during the period.
(6) Net debt is long-term debt including Debentures adjusted for working
capital, excluding current financial derivative and future income tax
assets and liabilities.
(7) The net debt per Trust Unit calculation includes outstanding Trust
Units, Trust Units issueable upon exchange of the outstanding
Exchangeable Shares and Trust Units issueable pursuant to the LTIP at
the end of the period.
Operating Highlights
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
Daily Production Volumes 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Natural gas (mmcf/day) 164.1 164.1 176.8 164.7 178.6
Crude oil (bbls/day) 9,106 6,305 7,037 7,434 6,898
Natural gas liquids (bbls/day) 3,931 3,748 3,616 3,736 3,713
---------------------------------------------------------------------------
Total (BOE per day) 40,381 37,406 40,121 38,625 40,379
---------------------------------------------------------------------------
Average Realized Sales Prices
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Natural gas ($/Mcf) (1)(2) 6.69 6.65 8.41 7.49 7.57
Without hedging 6.20 6.29 8.66 7.19 7.66
Crude oil ($/bbl)(1) 69.64 68.72 56.19 64.77 48.11
Without hedging 69.18 68.78 67.48 65.38 58.05
Natural gas liquids ($/bbl) 62.50 62.56 59.83 61.54 54.76
---------------------------------------------------------------------------
Total Oil Equivalent ($/BOE)(1) 48.96 47.02 52.30 50.35 46.76
Without hedging 46.86 45.46 55.38 49.20 48.85
---------------------------------------------------------------------------
Realized hedging gain/(loss)
included in prices above
($/BOE) 2.10 1.56 (3.08) 1.15 (2.09)
---------------------------------------------------------------------------
(1) Includes hedging gains and losses.
(2) Excludes sulphur.
Cash Flow Reconciliation
---------------------------------------------------------------------------
($ Millions)
---------------------------------------------------------------------------
Second quarter 2006 cash flow from operations $ 88.6
Volumes 20.4
Commodity prices (1.1)
Net hedging change from prior quarter 2.5
Operating expenses (3.6)
Royalties (2.6)
G&A 1.9
Interest (6.7)
Other 2.8
---------------------------------------------------------------------------
Third quarter 2006 cash flow from operations $ 96.6
---------------------------------------------------------------------------
The above table includes non-GAAP measurements. (Refer to discussion on
Non-GAAP Measures on Page 4)
A key performance driver for the Trust is cash flow from operations, which directly
affects PrimeWest's ability to pay monthly distributions. Cash flow is generated
through the production and sale of crude oil, natural gas and natural gas liquids,
and is dependent on production levels, commodity prices, operating expenses, interest
expense, general and administrative expense (G&A), hedging gains or losses, royalties
and currency exchange rates. Some of these factors such as commodity prices, the
currency exchange rate and royalties are uncontrollable from PrimeWest's perspective.
Other factors that are to a certain extent controllable by PrimeWest are production
levels and operating expenses, as well as interest and G&A expenses.
Selected Canadian and U.S. Financial Results
---------------------------------------------------------------------------
($ Millions, except production volumes and per unit prices)
Three Months Ended Sep 30, 2006
---------------------------------------------------------------------------
Canada U.S. Total
Daily Production Volumes
Natural gas (mmcf/day) 162.5 1.6 164.1
Crude oil (bbls/day) 6,659 2,447 9,106
Natural gas liquids (bbls/day) 3,931 - 3,931
Total daily sales (BOE/day) 37,625 2,756 40,381
Pricing (1)
Natural gas (per mcf) 6.20 6.07 6.20
Crude oil (per bbl) 69.51 68.28 69.18
Natural gas liquids (per bbl) 62.50 - 62.50
Revenues (1)
Natural gas 92.6 0.9 93.5
Crude oil 42.5 15.5 58.0
Natural gas liquids 22.6 - 22.6
Royalties (31.1) (3.4) (34.5)
Expenses
Operating 30.8 4.0 34.8
G&A 6.0 0.5 6.5
Depletion, depreciation and amortization 54.8 4.3 59.1
Income and capital taxes - 0.5 0.5
Capital expenditures
Development 75.8 0.5 76.3
Acquisition of oil and gas properties 35.1 333.7 368.8
Disposition of oil and gas properties 0.2 - 0.2
---------------------------------------------------------------------------
(1) Net of transportation expense. Excludes realized hedging gains and
losses.
---------------------------------------------------------------------------
($ Millions, except production volumes and per unit prices)
Nine Months Ended Sep 30, 2006
---------------------------------------------------------------------------
Canada U.S. Total
Daily Production Volumes
Natural gas (mmcf/day) 164.2 0.5 164.7
Crude oil (bbls/day) 6,599 835 7,434
Natural gas liquids (bbls/day) 3,736 - 3,736
Total daily sales (BOE/day) 37,696 929 38,625
Pricing (1)
Natural gas (per mcf) 7.19 6.07 7.19
Crude oil (per bbl) 65.01 68.28 65.38
Natural gas liquids (per bbl) 61.54 - 61.54
Revenues (1)
Natural gas 322.4 0.9 323.3
Crude oil 117.2 15.5 132.7
Natural gas liquids 62.8 - 62.8
Royalties (107.6) (3.4) (111.0)
Expenses
Operating 94.7 4.0 98.7
G&A 19.6 0.5 20.1
Depletion, depreciation and amortization 162.2 4.3 166.5
Income and capital taxes (0.6) 0.5 (0.1)
Capital expenditures
Development 203.2 0.5 203.7
Acquisition of oil and gas properties 35.4 333.7 369.1
Disposition of oil and gas properties 3.4 - 3.4
---------------------------------------------------------------------------
(1) Net of transportation expense. Excludes realized hedging gains and
losses
Quarterly Performance - Selective Measures
The table below highlights PrimeWest's performance for the third quarter
ended September 30, 2006 and the preceding seven quarters through 2004.
2006 2005 2004
---------------------------------------------------------------------------
($ millions, except per
Trust Unit Amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
---------------------------------------------------------------------------
Net Revenues 160.1 134.9 170.0 236.4 101.5 155.3 111.2 158.2
Net Income 64.0 65.7 68.9 101.5 27.3 54.7 24.0 42.2
Cash Flow from Operations 96.6 88.6 103.2 132.5 106.4 95.5 79.7 83.3
Cash Flow Per Unit
- basic 1.17 1.08 1.28 1.66 1.36 1.29 1.12 1.17
Cash Flow Per Unit
- diluted 1.15 1.06 1.24 1.60 1.31 1.21 1.04 1.07
Net Income Per Unit
- basic 0.78 0.81 0.85 1.27 0.35 0.74 0.34 0.59
Net Income Per Unit
- diluted 0.76 0.79 0.83 1.23 0.35 0.72 0.34 0.58
---------------------------------------------------------------------------
Net revenues are impacted primarily by commodity prices, production volumes, royalties
and unrealized gains or losses on derivatives.
Net income and net income per Trust Unit are secondary measures for a royalty trust
because they include both cash and non-cash items. The non-cash items, which include
depletion, depreciation and amortization (DD&A), non-cash G&A, future income taxes,
unrealized foreign exchange gains or losses and unrealized gains or losses on derivatives
will not affect PrimeWest's ability to pay a monthly distribution.
Capital Expenditures
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Land and lease acquisitions 2.0 3.5 2.7 8.9 15.7
Geological and geophysical 0.5 0.5 0.3 2.5 6.7
Drilling and completions 53.8 22.3 22.0 129.6 80.9
Investment in facilities
Equipping and tie-in 8.7 14.4 6.4 38.7 20.3
Gas gathering and
compression 7.8 1.1 2.3 10.1 11.5
Production facilities 2.2 3.1 2.2 10.0 7.3
Capitalized G&A 1.3 1.2 0.7 3.9 2.1
---------------------------------------------------------------------------
Development capital 76.3 46.1 36.6 203.7 144.5
---------------------------------------------------------------------------
Acquisition of oil and gas 368.8 0.2 2.6 369.1 2.1
assets
Dispositions (0.2) (0.1) (1.5) (3.4) (3.7)
Leasehold improvements,
furniture and equipment 0.4 1.3 0.8 3.0 3.4
---------------------------------------------------------------------------
Net capital expenditures 445.3 47.5 38.5 572.4 146.3
---------------------------------------------------------------------------
During the third quarter of 2006, PrimeWest's development capital expenditures totalled
$76.3 million, compared to $46.1 million invested in the second quarter of 2006
and $36.6 million in the third quarter of 2005. Of the $76.3 million total, $62.5
million or 82% was invested in drilling, completions and tie-ins, which contribute
to new reserve additions and help offset natural production decline.
Acquisition of oil and gas assets include $31.9 million for the Caroline assets
and $336.3 million for the assets located in Montana, North Dakota, Wyoming and
Saskatchewan.
Through acquisitions as well as development drilling, workovers and re-completion
activities, PrimeWest strives to offset natural production declines and add reserves
in order to sustain cash flows. Capital resources are allocated to projects on the
basis of anticipated rate of return. At PrimeWest, every capital project is measured
against stringent economic evaluation criteria prior to approval. These criteria
include expected return, risks and further development opportunities.
Development Capital Update
During the third quarter of 2006, PrimeWest invested $76.3 million on development
opportunities, drilling 81 gross wells (56.3 net) with a success rate of 95%. PrimeWest's
five key development plays are Conventional Development, Tight Gas, Southeast Alberta
Shallow Gas, U.S. Assets and Coalbed Methane (CBM). PrimeWest's development capital
expenditures for 2006 are expected to be $275 million, allocated $85 to $95 million
to Conventional Development, $60 to $70 million to Tight Gas development, $25 to
$30 million to Southeast Alberta Shallow Gas development, $10 to $15 million to
the U.S. Assets and $5 to $10 million to CBM. Approximately $30 million will be
spent on maintenance capital and seismic in 2006.
Conventional Development
PrimeWest continues to invest in development opportunities at our conventional plays,
which include properties at Lone Pine Creek/Crossfield, Wilson Creek, Boundary,
Laprise, Grand Forks and Valhalla. Development expenditures during the third quarter
totalled $34.2 million, including $21.4 million for drilling and completions, $0.4
million for land and seismic, and $11.1 million for equipping, tie-in and facilities.
A total of 23 gross wells were drilled during the quarter.
The following provides a description of the Wilson Creek and Lone Pine Creek/Crossfield
areas, which are major properties in our conventional development play.
Wilson Creek
In the Wilson Creek area, PrimeWest drilled 9 operated wells in the third quarter
of 2006, and participated in 2 non-operated wells targeted at various formations
including Edmonton, Belly River, Glauconitic, Mannville, and Rock Creek. Development
capital expenditures at Wilson Creek were $13.6 million, including $11.0 million
for drilling and completions, $0.01 million for land and $1.9 million for equipping,
tie-in and facilities.
Lone Pine Creek/Crossfield Area
Development capital expenditures at Crossfield of $16.0 million were comprised of
$8.8 million for drilling and completions, $0.1 million for land and seismic and
$7.1 million for equipping, tie-in and facilities.
Tight Gas Plays
PrimeWest's Tight Gas plays are located in west central Alberta, and target the
deeper Viking, Mannville and Cardium sandstones. Tight Gas wells are characterized
by high initial production rates that settle into a low decline stabilized rate
and production of high heat content, liquids-rich gas.
PrimeWest continued its development program in its Tight Gas plays in the third
quarter 2006. Capital expenditures for the three months ended September 30, 2006
included $18.2 million for drilling and completions, $1.8 million for land and seismic
and $3.5 million for equipping, tie-in and facilities. Fourteen gross wells were
drilled during the quarter. Previous expenditures on land and seismic have increased
PrimeWest's inventory of drilling opportunities. The following provides an overview
of activity in the Tight Gas region.
Caroline Area
Development expenditures at Caroline during the third quarter 2006 were $16.4 million
including $12.0 million for drilling and completion, $1.8 million for equipping,
tie-in and facilities and $0.6 million for land and seismic. During the quarter,
7 gross wells were drilled at Caroline.
Columbia Area
Development expenditures at Columbia of $6.1 million included $4.3 million for drilling
and completions, $1.1 million for equipping, tie-in and facilities and $0.9 million
for land and seismic. During the quarter, 2 gross wells have been drilled at Columbia.
Southeast Alberta Shallow Gas
PrimeWest's Southeast Alberta Shallow Gas Play consists of shallow gas pools in
the Medicine Hat and Milk River formations plus deeper, more prolific pools in Glauconitic
zones. Lying at typical depths of 600 to 1,000 metres, the shallow zones are amenable
to a low-risk, low-cost "manufacturing" development approach. The main properties
that comprise the Shallow Gas Play are Medicine Hat, Princess/Dinosaur, Bindloss
and Brant Farrow. This area has evolved through a combination of development activities
and acquisitions. During the third quarter of 2006, development expenditures were
$14.2 million, with $6.2 million invested in drilling and completions, $3.7 million
in equipping, tie-ins and facilities, and $0.2 million in land and seismic. Thirty-seven
gross wells were drilled in the third quarter.
The following provides a description of the Brant Farrow area, which is a major
property in the Southeast Alberta Shallow Gas play that has evolved to include development
of the seismically identified Glauconitic channels.
Brant Farrow Area
Development expenditures at Brant Farrow during the third quarter were $5.0 million,
with $3.5 million invested in drilling and completions, $1.0 million in equipping,
tie-ins and facilities and $0.1 million in land and seismic. The drilling program
is on schedule, with 5 gross operated wells drilled in the third quarter.
U.S. Assets
On July 6, 2006, PrimeWest acquired producing oil and gas assets located in Montana,
North Dakota and Wyoming. The acquisition established a new operating area within
the Williston Basin, providing considerable waterflood and development drilling
potential.
The major fields acquired are Flat Lake, Dwyer and Goose Lake in Montana; Rival,
Grenora, Alexander, Wiley, Glenburn and Sherwood in North Dakota; and Rocky Point
in Wyoming.
PrimeWest is planning to invest between $10 - $15 million on well reactivations,
injection conversions and the drilling of up to three wells during the remainder
of 2006. During the third quarter 2006, PrimeWest incurred $0.5 million on capital
development expenditures on the U.S. Assets.
Coalbed Methane
CBM is an emerging resource play in Western Canada. PrimeWest has approximately
124,000 net acres of land on the developing Horseshoe Canyon CBM trend. PrimeWest
is involved in preliminary assessments of the area. Acreage is concentrated within
three large operated properties with gas plants and extensive field infrastructure.
Commencement on commercial development of the CBM will be evaluated in 2007 and
will be contingent on the natural gas price.
Daily Production Volumes
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
Daily Production Volumes 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Natural gas (mmcf/day) 164.1 164.1 176.8 164.7 178.6
Crude oil (bbls/day) 9,106 6,305 7,037 7,434 6,898
Natural gas liquids (bbls/day) 3,931 3,748 3,616 3,736 3,713
---------------------------------------------------------------------------
Total (BOE per day) 40,381 37,406 40,121 38,625 40,379
---------------------------------------------------------------------------
PrimeWest's production volumes averaged 40,381 BOE per day in the third quarter
of 2006, compared to 37,406 BOE per day in the second quarter 2006. The 8% increase
in volumes is mainly due to the acquisition of the U.S. assets early in the third
quarter. The U.S. asset's production averaged 2,756 BOE per day for the three months
ended September 30, 2006. Production disruptions and planned workover activities
reduced third quarter volumes at the U.S. Dwyer and Rival fields. Continued success
with the Canadian drilling program resulted in relatively flat production levels
quarter over quarter. Incremental volumes offset volume reductions due to maintenance
shut-in at the Crossfield gas plant and natural decline.
For the three months ended September 30, 2006, production volumes have remained
relatively flat when compared to the same period in 2005.
For the nine months ended September 30, 2006, production volumes have decreased
approximately 4% compared to the prior year due to third party unscheduled outages
at Princess, regulatory change impacting the Nisku waterflood project at Crossfield,
a one time negative adjustment to gross overriding royalty volumes and natural decline.
Volumes from the U.S. assets partially offset the decrease with annualized production
averaging 929 BOE per day for the nine months ended September 30, 2006.
Production Outlook
PrimeWest expects full year 2006 production volumes to average between 39,000 -
40,000 BOE per day in 2006.
Commodity Prices
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
Benchmark Prices 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Natural gas
NYMEX (US$/mcf) 6.53 6.82 8.25 7.47 7.12
AECO (Cdn$/mcf) 6.03 6.27 8.17 7.19 7.41
Crude oil WTI (US$/bbl) 70.48 70.70 63.19 68.22 55.40
---------------------------------------------------------------------------
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)
---------------------------------------------------------------------------
Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
2005 2006 2006 2006 2006 2007 2007 2007
---------------------------------------------------------------------------
Natural gas
AECO
(Cdn$/mcf) 11.69 9.27 6.27 6.03 5.74 7.48 6.93 7.22
Crude oil WTI
(US$/bbl) 60.02 63.48 70.70 70.48 64.36 66.61 67.90 68.66
---------------------------------------------------------------------------
(1) As at September 30, 2006
Average Realized Sales Prices
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Natural gas ($/Mcf) (1)(2) 6.69 6.65 8.41 7.49 7.57
Without hedging 6.20 6.29 8.66 7.19 7.66
Crude oil ($/bbl)(1) 69.64 68.72 56.19 64.77 48.11
Without hedging 69.18 68.78 67.48 65.38 58.05
Natural gas liquids ($/bbl) 62.50 62.56 59.83 61.54 54.76
---------------------------------------------------------------------------
Total Oil Equivalent ($/BOE)(1) 48.96 47.02 52.30 50.35 46.76
Without hedging 48.86 45.46 55.38 49.20 48.85
---------------------------------------------------------------------------
Realized hedging gain/(loss)
included in prices above
($/BOE) 2.10 1.56 (3.08) 1.15 (2.09)
---------------------------------------------------------------------------
(1) Includes hedging losses.
(2) Excludes sulphur.
Realized natural gas prices were relatively flat in the third quarter of 2006 compared
to the previous quarter, excluding the effect of hedging. Weather continues to play
an important role in determining overall gas supply and demand balances, and therefore
pricing. Gas storage levels at the end of the 2006 summer injection season approached
record levels as a result of a record warm 2005-2006 winter, and the absence of
material hurricane activity in the Gulf of Mexico during the summer of 2006. In
addition, North American gas production continues to benefit from high drilling
activity. Realized natural gas prices were 28% lower during the third quarter of
2006 compared to the third quarter of 2005.
Third quarter realized crude oil prices were slightly higher than the previous quarter,
excluding the effect of hedging. WTI prices at the onset of the third quarter increased
as a result of perceived gasoline shortages, which many predicted would occur during
the height of the summer driving season. Because the shortages did not materialize,
WTI prices quickly retreated, falling in excess of US $10.00 per barrel by the end
of summer. Prices also continued to be impacted by historically wide differentials
to WTI on all grades of crude. High U.S. crude storage levels combined with less
seasonal demand for crude products also put downward pressure on WTI prices during
the latter part of the third quarter.
Realized oil prices excluding the effect of hedging were 3% higher during the third
quarter of 2006 compared to the third quarter of 2005.
Sales Revenue
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Revenue Sep 30, % of Jun 30, % of Sep 30, % of Sep 30, Sep 30,
($ millions)(1)(2) 2006 Total 2006 Total 2005 Total 2006 2005
---------------------------------------------------------------------------
Natural gas 101.0 56 99.3 62 136.8 71 336.7 369.3
Crude oil 58.3 32 39.4 25 36.4 19 131.4 90.6
Natural gas
liquids 22.6 12 21.4 13 19.9 10 62.8 55.5
---------------------------------------------------------------------------
Total 181.9 100 160.1 100 193.1 100 530.9 515.4
---------------------------------------------------------------------------
Hedging
gain/(losses)
included above 7.8 5.3 (11.4) 12.2 12.2 (23.1)
---------------------------------------------------------------------------
(1) Excludes sulphur.
(2) Net of transportation expenses.
Third quarter 2006 revenues were 14% higher than the previous quarter mainly due
to the increases in production volumes resulting from the U.S. asset acquisition
and increases in hedging gains.
Third quarter 2006 revenues were 6% lower than the same period in 2005, due to lower
natural gas prices offset by increases in realized hedging gains. On a year-to-date
basis, September 2006 revenues exceeded September 2005 revenues by 3% due to higher
realized crude oil prices offset by lower production volumes.
Approximately 68% of PrimeWest's production on an energy equivalent basis is natural
gas; therefore, the Trust has greater sensitivity to changes in natural gas prices
than crude oil prices.
Financial Derivatives
As part of our financial management strategy, PrimeWest uses a consistent commodity
hedging approach. The purpose of the hedging program is to reduce volatility in
cash flows, protect acquisition economics and to stabilize cash flow against the
unpredictable commodity price environment. The hedging policy reflects a willingness
to risk forfeiting a portion of the pricing upside in return for partial protection
against a significant downturn in prices.
The following table sets forth the approximate percentage of future anticipated
production volumes hedged at September 30, 2006, net anticipated royalties, reflecting
full production declines with no offsetting additions.
---------------------------------------------------------------------------
Production Volumes Hedged
(%) Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008
---------------------------------------------------------------------------
Crude Oil 69 67 56 39 40 7
Natural Gas 67 52 30 26 22 11
---------------------------------------------------------------------------
PrimeWest generally sells its oil and natural gas under short-term market-based
contracts. Derivative financial instruments, options and swaps may be used to hedge
the impact of oil and gas price fluctuations.
A listing of hedging contracts in place at September 30, 2006 follows:
Crude Oil
---------------------------------------------------------------------------
Period Volume (bbls/d) Type WTI Price (US$/bbl)
---------------------------------------------------------------------------
Oct - Dec 06 500 Costless Collar 50.00/75.03
Oct - Dec 06 1000 Costless Collar 50.00/81.50
Oct - Dec 06 500 Costless Collar 50.00/75.00
Oct - Dec 06 500 Costless Collar 50.00/81.00
Oct - Dec 06 500 Costless Collar 55.00/91.50
Oct - Dec 06 500 Costless Collar 55.00/90.90
Oct - Dec 06 500 Costless Collar 65.00/88.25
Oct - Dec 06 1800 Costless Collar 70.00/83.20
Jan - Mar 07 500 Costless Collar 50.00/76.00
Jan - Mar 07 500 Costless Collar 50.00/80.80
Jan - Mar 07 500 Costless Collar 55.00/91.65
Jan - Mar 07 500 Costless Collar 55.00/90.00
Jan - Mar 07 500 Costless Collar 60.00/97.20
Jan - Mar 07 500 Costless Collar 65.00/95.15
Jan - Mar 07 1400 Costless Collar 70.00/83.65
Jan - Mar 07 500 Costless Collar 65.00/90.25
Jan - Mar 07 500 Costless Collar 55.00/74.50
Apr - Jun 07 500 Costless Collar 50.00/80.00
Apr - Jun 07 500 Costless Collar 55.00/91.30
Apr - Jun 07 500 Costless Collar 55.00/90.08
Apr - Jun 07 500 Costless Collar 60.00/95.40
Apr - Jun 07 500 Costless Collar 65.00/93.90
Apr - Jun 07 1300 Costless Collar 70.00/84.25
Apr - Jun 07 500 Costless Collar 55.00/75.00
Jul - Sep 07 500 Costless Collar 60.00/92.75
Jul - Sep 07 500 Swap 75.20
Jul - Sep 07 500 Costless Collar 65.00/92.60
Jul - Sep 07 900 Costless Collar 70.00/83.25
Jul - Sep 07 500 Costless Collar 55.00/77.80
Oct - Dec 07 500 Costless Collar 60.00/90.25
Oct - Dec 07 500 Swap 74.58
Oct - Dec 07 500 Costless Collar 65.00/91.35
Oct - Dec 07 800 Costless Collar 70.00/82.10
Oct - Dec 07 500 Costless Collar 55.00/78.25
Jan - Mar 08 500 Costless Collar 55.00/78.00
---------------------------------------------------------------------------
Natural Gas
---------------------------------------------------------------------------
Period Volume (mmcf/d) Type AECO Price (Cdn$/mcf)
---------------------------------------------------------------------------
Oct - Dec 06 5.0 3 Way 5.28/6.33/13.03
Oct - Dec 06 5.0 Costless Collar 6.86/11.92
Oct - Dec 06 10.0 Costless Collar 6.86/12.66
Oct - Dec 06 5.0 3 Way 5.28/6.33/14.19
Oct - Dec 06 5.0 Costless Collar 7.39/15.83
Oct - Dec 06 5.0 Costless Collar 8.44/11.87
Oct - Dec 06 5.0 Costless Collar 8.44/15.83
Oct - Dec 06 5.0 Costless Collar 8.44/17.94
Oct - Dec 06 5.0 Costless Collar 8.44/18.99
Oct - Dec 06 10.0 Costless Collar 8.44/19.25
Oct - Dec 06 5.0 Swap 8.22
Oct - Dec 06 5.0 Costless Collar 6.33/9.97
Oct - Dec 06 5.0 Costless Collar 6.33/12.24
Jan - Mar 07 5.0 Costless Collar 7.91/12.87
Jan - Mar 07 5.0 Costless Collar 8.44/13.80
Jan - Mar 07 5.0 Costless Collar 8.44/15.88
Jan - Mar 07 5.0 Costless Collar 8.44/18.46
Jan - Mar 07 5.0 Costless Collar 8.44/21.10
Jan - Mar 07 5.0 Costless Collar 8.44/21.21
Jan - Mar 07 5.0 Costless Collar 8.44/12.68
Jan - Mar 07 5.0 Costless Collar 7.39/14.77
Jan - Mar 07 5.0 Costless Collar 5.28/10.87
Jan - Mar 07 5.0 Costless Collar 7.39/17.04
Jan - Mar 07 5.0 Costless Collar 8.44/15.03
Apr - Jun 07 5.0 3 Way 6.33/7.39/11.24
Apr - Jun 07 5.0 Costless Collar 6.33/10.64
Apr - Jun 07 5.0 Costless Collar 6.33/10.23
Apr - Jun 07 5.0 Costless Collar 5.28/9.34
Apr - Jun 07 5.0 Costless Collar 6.33/11.39
Apr - Jun 07 5.0 Costless Collar 6.33/11.66
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
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
Jan - Mar 08 5.0 Costless Collar 6.33/12.71
Jan - Mar 08 5.0 Costless Collar 8.44/15.67
---------------------------------------------------------------------------
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 $13.03, purchased a put at $6.33, and resold
the put at $5.28. Should the market price drop below $6.33, PrimeWest will receive
$6.33 until the price is less than $5.28, at which time PrimeWest will then receive
market price plus $1.05. However, should market prices rise above $13.03, PrimeWest
will receive a maximum of $13.03. Should the market price remain between $6.33 and
$13.03, PrimeWest will receive the market price.
Electrical Power
---------------------------------------------------------------------------
Period Power Amount (MW) Type Price ($/MW-hr)
---------------------------------------------------------------------------
Oct - Dec 06 5.0 Swap 70.50
Oct - Dec 06 5.0 Swap 66.00
---------------------------------------------------------------------------
Foreign Exchange
---------------------------------------------------------------------------
Amount Pounds
Period Sterling (000's) Type Price
---------------------------------------------------------------------------
Oct - Jun 16 Principal 63,000 Swap $2.0748 Cdn per
Interest 36,288 Pounds Sterling 1.00
---------------------------------------------------------------------------
PrimeWest's derivatives are Marked-to-Market at the end of each reporting period
with the resulting gain or loss reflected in earnings for that period.
The third quarter 2006 income statement includes an unrealized gain of $9.7 million
on derivatives resulting from the change in the Mark-to-Market valuation of the
derivative financial instruments during the period. The gain was comprised of a
$7.9 million gain on crude oil hedges, a $5.5 million gain on natural gas hedges,
$0.1 million gain on electrical power and a $3.8 million loss on the foreign exchange
hedge.
For the nine months ended September 30, 2006, the change in Mark-to-Market valuation
of the derivatives resulted in a gain of $34.8 million comprised of a $7.4 million
gain on crude oil hedges, a $33.4 million gain on natural gas hedges, a $0.1 million
gain on electrical power and a $6.1 million loss on the foreign exchange hedge.
The unrealized gain is a point-in-time measurement of PrimeWest's hedging position
at the end of the third quarter. The magnitude of the gain or loss will continue
to fluctuate with changes in commodity prices.
For the three month period ended September 30, 2006 the cash impact of hedge contract
settlements was a $7.8 million gain comprised of a $0.4 million gain on crude oil
and a $7.4 million gain on natural gas.
For the nine month period ended September 30, 2006, the cash impact of hedge contract
settlements was a $12.2 million gain comprised of a $13.4 million gain on natural
gas and a $1.2 million loss on crude oil.
Royalties
PrimeWest pays royalties to the owners of mineral rights with whom PrimeWest holds
leases. PrimeWest has mineral leases with the Crown (Provincial and Federal Governments),
freeholders (individuals or other companies) and other operators.
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
($ millions, Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
except per BOE) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Royalty expense 34.5 31.9 44.4 111.0 117.3
Per BOE 9.29 9.36 12.04 10.53 10.64
Royalties as a % of
sales revenues
With hedge gain or loss 18.9% 19.9% 23.0% 20.9% 22.8%
Excluding hedge gain or loss 19.8% 20.6% 21.7% 21.4% 21.8%
---------------------------------------------------------------------------
Third quarter 2006 royalty expense as a percentage of sales, excluding the impact
of hedges, decreased when compared to the previous quarter and the same period in
the prior year due to a Crown adjustment relating to prior periods of approximately
$0.5 million.
The Crown royalty system is based on a sliding scale structure that increases the
royalty rates as commodity prices rise. Because of the sliding scale, future changes
to commodity prices will result in changes in royalty rates and expenses.
Operating Expenses
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
($ millions, Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
except per BOE) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Operating expense 34.8 31.2 31.6 98.7 84.1
Per BOE 9.36 9.16 8.56 9.36 7.63
---------------------------------------------------------------------------
Third quarter 2006 operating expense totalled $34.8 million, an increase of 12%
from $31.2 million in the second quarter. On a per BOE basis operating expenses
increased by 2% over the previous quarter. The increase in operating expense is
mainly attributable to the acquisition of the U.S. assets. Operating expense for
the U.S. assets was approximately $4.0 million in the third quarter. Excluding the
impact of the U.S. assets, operating expense remained relatively flat quarter over
quarter. Included in the third quarter 2006 operating expense is approximately $1.8
million related to the turnaround at the Crossfield gas plant.
Year over year operating expense and operating expense per BOE increased in the
third quarter of 2006 compared to the third quarter 2005 due to the U.S. asset acquisition.
Operating expense and operating expense per BOE for the nine months ended September
30, 2006 increased over the same period in 2005 due to first quarter 2006 operating
issues, the impact of the U.S. assets and inflationary pressures on the price of
goods and services.
Operating Expense Outlook
PrimeWest anticipates that its full year operating expense will be approximately
$9.25 per BOE.
Operating Margin
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
($ per BOE) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Sales price and
other revenue(1) 49.27 47.60 52.38 50.82 46.84
Royalties (9.29) (9.36) (12.04) (10.53) (10.64)
Operating expense (9.36) (9.16) (8.56) (9.36) (7.63)
---------------------------------------------------------------------------
Operating margin 30.62 29.08 31.78 30.93 28.57
---------------------------------------------------------------------------
(1) Includes hedging and sulphur.
The operating margin per BOE increased in the third quarter of 2006 compared to
the previous quarter mainly due to an increase in realized commodity prices offset
by higher operating expenses. 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.
Third quarter 2006 operating margin was lower than the same period in 2005 due to
lower realized commodity prices and increases in operating costs offset by lower
royalties.
General & Administrative Expense
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
($ millions, Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
except per BOE) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Cash G&A expense 5.1 7.0 5.7 17.4 16.0
Per BOE 1.39 2.04 1.54 1.65 1.46
Non-cash G&A expense 1.4 1.5 1.5 4.4 4.1
Per BOE 0.37 0.45 0.41 0.41 0.37
---------------------------------------------------------------------------
Cash G&A expense in the third quarter of 2006 decreased 27% on a gross and 32% on
a per BOE basis from the previous quarter due mainly to lower stock exchange listing
fees and higher overhead recoveries related to an increase in capital spending.
Included in the third quarter 2006 G&A expense is $0.5 million related to the U.S.
operations.
Third quarter 2006 cash G&A expenses were 11% lower when compared to the third quarter
of 2005. Increases in labour costs and legal fees were offset by lower information
technology expenses and increases in overhead recoveries. Cash G&A per BOE for the
three months ended September 30, 2006 was 31% lower than the same period in the
prior year due to lower cash G&A expense and increases to production volumes.
G&A expense for the nine months ended September 30, 2006 exceeded the G&A expense
for the same period in 2005 due to higher labour costs, legal and audit fees, offset
by increases to overhead recoveries. Cash G&A expense per BOE for the nine months
ended September 30, 2006 increased 13% compared to the prior year due to increase
to G&A expense and reductions in production volumes.
Included in non-cash G&A expense was $1.2 million and $3.2 million for the three
and nine months ended September 30, 2006, 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 non-cash G&A expense is $0.2
million and $1.1 million for the three and nine months ended September 30, 2006,
respectively, related to the Special Employee Retention Plan (SERP). See note 15
to the Consolidated Financial Statements in the 2005 Annual Report.
Interest Expense
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
($ millions, except Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
per Trust Unit Amounts) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Interest expense 11.9 5.2 6.0 21.6 22.8
Period end net debt
level(1) 772.4 415.5 381.8 772.4 381.8
Debt per Trust Unit 9.16 4.98 4.75 9.16 4.75
---------------------------------------------------------------------------
Average cost of debt 5.9% 5.1% 4.9% 5.6% 4.7%
---------------------------------------------------------------------------
(1) Excludes derivative and future income tax assets and liabilities
included in current assets and liabilities.
Interest expense, representing interest on bank debt, the U.S. Secured Notes, the
U.K. Secured Notes and the Debentures increased in the third quarter of 2006 compared
to the second quarter of 2006 and the third quarter of 2005, due to the increase
in the average net debt balance resulting from the acquisition of the U.S. assets.
Interest expense was also impacted by increases in the average cost of debt.
Interest expense was lower for the nine months ended September 30, 2006 compared
to the same period in 2005 due to lower average debt balances offset by a higher
average cost of debt. The average debt balance for the nine months ended September
30, 2006 was lower than the same period in the prior year mainly due to the conversion
of the debentures throughout 2006.
The average cost of debt was higher for the three and nine months ended September
30, 2006 compared to the same periods in 2005, primarily due to the impact of the
U.K. Secured Notes and the portion of the bank credit facilities denominated in
the London Inter-Bank Offer Rate (LIBOR), which currently bear interest at 5.93%
and 6.41% respectively.
Foreign Exchange
The foreign exchange loss of $1.9 million for the three months and the $4.9 million
gain for the nine months ended September 30, 2006 resulted from the translation
of the U.S. dollar denominated debt, the U.K. Secured Notes and related interest
payable into Canadian dollars.
Depletion, Depreciation and Amortization
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
($ millions, Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
except per BOE) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Depletion, depreciation and
amortization 59.1 53.5 56.5 166.5 169.7
Per BOE 15.90 15.73 15.30 15.79 15.40
---------------------------------------------------------------------------
The DD&A rate for the three months ended September 30, 2006 increased slightly when
compared to the previous quarter and the same period in the prior year. 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 to increase.
Site Reclamation and Restoration Reserve
Since the inception of the Trust, PrimeWest has maintained a site reclamation fund
to pay for future costs related to well abandonment and site clean up. The fund
is used to pay for such costs as they are incurred. The 2006 contribution rate for
the fund is unchanged from 2005 at $0.50 per BOE. As at September 30, 2006 the site
reclamation fund contained a balance of $5.6 million. The 2007 contribution rate
will be determined early in the New Year.
The abandonment and reclamation costs incurred in the third quarter 2006 were $5.2
million, compared to $1.3 million for the same period in 2005, and $1.8 million
for the previous quarter.
Asset Retirement Obligation
PrimeWest recognizes the fair value of asset retirement costs relating to its petroleum
and natural gas properties when a reasonable estimate of the fair value can be made
(See note 9 to the consolidated financial statements in 2005 Annual Report). These
liabilities will be settled based on the expected life of the underlying assets.
These liabilities are subsequently adjusted for the passage of time (accretion)
and revisions in either timing or changes to the underlying liability. PrimeWest
increased the asset retirement obligation in the third quarter of 2006 by approximately
$52.2 million. The increase is mainly the result of a three-year review of actual
costs incurred to reclaim wells and to a new directive by the Energy and Utilities
Board relating to the remediation of facilities.
The additional liability was capitalized to the related asset and will be amortized
to earnings over time.
Income and Capital Taxes
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
($ millions, Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
except per BOE) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Income and capital taxes 0.5 (1.2) 0.6 (0.1) 1.6
Future income tax recovery (21.2) (23.0) (22.2) (44.8) (38.8)
---------------------------------------------------------------------------
Total (20.7) (24.2) (21.6) (44.9) (37.2)
---------------------------------------------------------------------------
The future income tax recovery for the three months ended September 30, 2006 was
relatively flat compared to the prior quarter and the same period in the prior year.
The increase in the future income tax recovery for the nine months ended September
30, 2006 compared to the nine months ended September 30, 2005 is mainly due to the
reduction in federal statutory tax rates that were substantially enacted in the
second quarter of 2006.
Income and capital tax expense for the three months ended September 30, 2006 is
due to taxable income from the U.S. assets.
Net Income
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
($ millions) Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Net income 64.0 65.7 27.2 198.7 105.9
---------------------------------------------------------------------------
Cash flow from operations, as opposed to net income, is the primary measure of performance
for an energy trust. The generation of cash flow is critical for an energy trust
to continue paying its distributions to Unitholders.
Conversely, net income is an accounting measure impacted by both cash and non-cash
items. The largest non-cash items impacting PrimeWest's net income are DD&A, the
unrealized gain or loss on derivatives and future income taxes.
Net income for the three months ended September 30, 2006 of $64.0 million was 3%
lower than the previous quarter net income of $65.7 million primarily due to increases
in operating expense, DD&A and interest expense offset by increases to oil and gas
revenues, all of which are attributable to the acquisition of the U.S. assets.
Net income for the third quarter of 2006 is higher than the same period in the prior
year due to an increase in the unrealized gain on derivatives and to lower royalties
offset by a decrease in oil and gas revenues resulting from lower commodity prices.
Net income for the nine months ended September 30, 2006 of $198.7 million was 88%
higher than the same period in 2005 due mainly to an increase in the unrealized
gain on derivatives offset by a reduction in the gain on sale of marketable securities.
Liquidity & Capital Resources
Long-Term Debt
As at
---------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30,
($ millions) 2006 2006 2005
---------------------------------------------------------------------------
Long-term debt 544.9 400.6 383.8
Deficit/(working capital)(1) 227.5 14.9 (2.0)
---------------------------------------------------------------------------
Net debt 772.4 415.5 381.8
Market value of Trust Units and Exchangeable
Shares outstanding (2)(3) 2,281.4 2,751.1 2,878.6
---------------------------------------------------------------------------
Total capitalization 3,053.8 3,166.6 3,260.4
---------------------------------------------------------------------------
Net debt as a % of total capitalization 25% 13% 12%
---------------------------------------------------------------------------
(1) Excludes derivative and future income tax assets and liabilities
included in current assets or liabilities.
(2) Based on September 30, 2006 Trust Unit closing price of $27.35 and
September 15, 2006 exchange ratio of 0.61771:1.
(3) Excludes the Debentures.
Long-term debt is comprised of senior bank credit facilities, the U.S. Secured Notes,
the U.K. Secured Notes and the Debentures of $269.7 million, $104.8 million, $131.5
million and $38.9 million respectively. $34.9 million relating to the U.S. Secured
Notes and $150 million relating to the bridge facility are 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 $6.8 million (2005 - $4.8 million).
The indebtedness under the senior credit facilities, the U.S. Secured Notes and
the U.K. Secured Notes is supported by a borrowing base of $750 million and is comprised
of Canadian revolving facilities having a capacity of $220.5 million, the U.S. bank
revolving credit facilities having a capacity of Cdn $255.0 million, the U.S. Secured
Notes valued at $143.8 million based on a U.S. dollar exchange rate of U.S. $0.87
and the U.K. Secured Notes valued at Cdn $130.7 million. PrimeWest also has a $150
million bridge facility, which is due to expire in March 2007 or earlier if the
amount drawn under the facility is paid out.
As a result of the U.S. asset acquisition during the third quarter of 2006, PrimeWest
has drawn advances under the U.S. bank revolving credit facilities in U.S. dollars
in the form of LIBOR loans that bear interest at LIBOR plus a margin based on PrimeWest's
debt to EBITDA ratio. PrimeWest will continue to fund its ongoing operations in
Canada with advances from the Canadian revolving facilities utilizing Banker Acceptances
(BA) that bear interest at the BA rate plus a stamping fee determined in the same
manner as the LIBOR margin.
At September 30, 2006, PrimeWest's net debt to annualized third quarter cash flow
was approximately 2.0 times compared to 1.2 times second quarter cash flow at June
30, 2006. Net debt as a percentage of total capitalization was 25% at September
30, 2006 compared to 13% at June 30, 2006.
During the third quarter of 2006, $2.1 million of the Series I Debentures and $2.2
million of the Series II Debentures were converted to Trust Units. Accretion of
$0.1 million was realized during the period.
Unitholders' Equity
At September 30, 2006, the Trust had 82,719,272 Trust Units outstanding. In addition,
PrimeWest had 1,124,068 Exchangeable Shares outstanding that are exchangeable into
a total of 694,348 Trust Units using the September 15, 2006 exchange ratio of 0.61771:1.
The equity component of the Series I and Series II Debentures have each been reduced
by $0.1 million and $0.1 million respectively, due to conversions to Trust Units
during the quarter.
During the third quarter, PrimeWest issued 599,950 Trust Units for proceeds of $20.3
million pursuant to an "at the market offering" through the facilities of the NYSE
under a shelf prospectus issued on May 12, 2006 with a prospectus supplement filed
July 28, 2006. During the third quarter of 2006, PrimeWest issued 85,462 Trust Units
for $2.7 million under the DRIP, 213,593 Trust Units for $6.8 million pursuant to
the PREP and 52,770 Trust Units for proceeds of $1.7 million under the OTUPP.
The DRIP gives Canadian and U.S. Unitholders the opportunity to reinvest their monthly
distributions at a 5% discount to the volume-weighted average market price of the
Trust Units. As an alternative to the DRIP component of the Plan, the PREP allows
eligible Canadian Unitholders to elect to receive a premium cash distribution of
up to 102% of the cash that the Unitholder would otherwise have received on the
distribution date, subject to proration in certain events. The OTUPP gives Canadian
Unitholders an opportunity to purchase additional Trust Units directly from PrimeWest
at the same 5% discount. The DRIP and PREP components are mutually exclusive. Participation
in the OTUPP requires enrolment in either the DRIP or PREP.
These plan components benefit Unitholders by offering alternatives to maximize their
investment in PrimeWest, while providing the Trust with an inexpensive method of
raising additional capital. Proceeds from these plans are used for debt reduction
of PrimeWest's credit facility and to help fund ongoing capital development programs.
For additional information or to join the DRIP, OTUPP and PREP plans, contact the
Plan Agent, Computershare Trust Company of Canada, at 1-800-564-6253 or visit PrimeWest's
website at
www.primewestenergy.com.
Exchangeable Shares
Exchangeable shares were issued in connection with certain acquisitions and as part
of PrimeWest's management internalization transaction. Exchangeable shares continue
to be issued to certain Executive Officers pursuant to a Special Employee Retention
Plan (SERP) instituted as part of the management internalization transaction.
The Exchangeable Shares do not receive cash distributions. In lieu of receiving
distributions, the number of Trust Units that the exchangeable shareholder will
receive upon exchange increases each month based on the distribution amount divided
by the market price of the Trust Units on the 15th day of that month.
At September 30, 2006, there were 1,124,068 Exchangeable Shares outstanding. The
exchange ratio on these shares was 0.61771:1 Trust Units for each Exchangeable Share
as at September 15, 2006. For purposes of calculating basic per Trust Unit amounts,
it is assumed that the Exchangeable Shares have been exchanged into Trust Units
at the current exchange ratio.
Cash Distributions
Cash distributions to Unitholders are at the discretion of the Board of Directors
and can fluctuate depending on the cash flow generated from operations and other
factors. The cash flow available for distribution is dependent upon many factors
including commodity prices, production levels, debt levels, capital spending requirements,
and factors in the overall industry environment.
The Board of Directors targets a long-term distribution payout ratio that is a percentage
of cash flow from operations. However, the actual distribution payout ratio may
vary from such targets due to fluctuations in commodity prices and their impact
on cash flow forecasts, as well as other factors. The current distribution payout
ratio is targeted to be approximately 70-90% of annual cash flow from operations.
In the third quarter of 2006, cash distributions totalled $74.0 million, or $0.90
per Trust Unit representing a payout ratio of approximately 77%, compared to $82.8
million, or $1.02 per Trust Unit (93% payout ratio) in the previous quarter.
Distribution payments to U.S. Unitholders are subject to a 15% Canadian withholding
tax, which is deducted from the entire distribution amount prior to deposit into
Unitholder accounts.
Contractual Obligations
PrimeWest enters into many contractual obligations as part of conducting day-to-day
business. Material contractual obligations include debt obligations, lease rental
commitments that run from 2006 through 2009 and various pipeline transportation
commitments that run through 2013. The details of the timing of these contractual
obligations are included in the following table.
As at September 30, 2006 Payments due by period
---------------------------------------------------------------------------
Less than More than
($ millions) Total 1 year 1-3 years 4-5 years 5 years
---------------------------------------------------------------------------
Long-term debt obligations 691.0 184.9 339.7 34.9 131.5
Debentures 38.4 - 23.7 - 14.7
Lease rental obligations 10.4 3.6 6.8 - -
Pipeline transportation
obligations 7.2 5.8 1.2 0.2 -
---------------------------------------------------------------------------
Total contractual
obligations 747.0 194.3 371.4 35.1 146.2
---------------------------------------------------------------------------
As part of PrimeWest's internalization transaction, which closed on November 6,
2002, PrimeWest agreed to issue 377,360 Exchangeable Shares to certain executive
officers pursuant to the SERP. On November 6, 2004 and 2005, 94,340 Exchangeable
Shares were issued to those officers. A total of 94,340 additional Exchangeable
Shares will be issued on November 6, 2006 and 2007. For the three and nine months
ended September 30, 2006, $0.2 million and $1.1 million respectively has been recorded
in non-cash G&A expenses related to the SERP.
In October 2006, PrimeWest entered into an agreement containing a new office lease
rental commitment that runs from 2010 to 2024. Payments that will become due under
this agreement will commence in mid-2010 at approximately $4.7 million per year
and will escalate by approximately $0.2 million every three years until 2021, at
which point they will increase by $0.1 million 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.
Business Risks
PrimeWest's operations are affected by a number of underlying risks, both internal
and external to the Trust. These risks are similar to those affecting others in
both the conventional oil and gas royalty trust sector and the conventional oil
and gas producers sector. The Trust's financial position, results of operations,
and cash available for distribution to Unitholders are directly impacted by these
factors. These factors are discussed under two broad categories - "Commodity Price,
Foreign Exchange and Interest Rate Risk" and "Operational and Other Business Risks."
For additional information on Business Risks, including Risks Related to the Trust
Structure and the Ownership of Trust Units, see PrimeWest's most recently filed
Annual Information Form.
Commodity Price, Foreign Exchange And Interest Rate Risk
The two most important factors affecting the level of cash distributions available
to Unitholders are the level of production achieved by PrimeWest and the price received
for its products. These prices are influenced in varying degrees by factors outside
the Trust's control. Some of these factors include:
- World market forces, specifically the actions of OPEC and other large crude oil
producing countries including Russia and their implications on the supply of crude
oil;
- World and North American economic conditions which influence the demand for both
crude oil and natural gas and the level of interest rates set by the governments
of Canada and the U.S.;
- Weather conditions that influence the demand for natural gas and heating oil;
- The Canadian/U.S. dollar exchange rate that affects the price received for crude
oil, as the price of crude oil is referenced in U.S. dollars;
- Transportation availability and costs; and
- Price differentials among World and North American markets based on transportation
costs to major markets and quality of production.
To mitigate these risks, PrimeWest has an active hedging program in place based
on an established set of criteria that has been approved by the Board of Directors.
The results of the hedging program are reviewed against these criteria and the results
actively monitored by the Board.
Beyond our hedging strategy, PrimeWest also mitigates risk by having a well-diversified
marketing portfolio and by transacting with a number of counterparties and limiting
exposure to each counterparty. For the third quarter of 2006 approximately 17% of
natural gas production was sold to aggregators and 83% of production was sold into
the Alberta and British Columbia short-term or export long-term markets.
The contracts that PrimeWest has with aggregators vary in length. They represent
a blend of domestic and U.S. markets and fixed and floating prices designed to provide
price diversification to our revenue stream.
The primary objective of our commodity risk management program is to reduce the
volatility of our cash distributions, to lock in the economics on major acquisitions
and to protect our capital structure when commodity prices cycle downwards. In the
third quarter 2006, PrimeWest realized a $7.8 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 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 Performing regular and proactive
production of oil and gas - protective well, facility and pipeline
includes well operations, maintenance supported by telemetry,
processing and the physical physical inspection and diagnostic
delivery of commodities to tools.
market.
---------------------------------------------------------------------------
Commodity Price
Fluctuations in natural gas, Hedging. See page 14 of this quarterly
crude oil and natural gas report.
liquids prices.
---------------------------------------------------------------------------
Transportation
Market risk related to the Diversifying the transportation systems
availability of transportation on which we rely to get our product to
to market and potential market.
disruption in delivery systems.
---------------------------------------------------------------------------
Natural Decline
Development risk associated with Diversifying our capital spending
capital enhancement activities program over a large number of projects
undertaken - the risk that so that large amounts of capital are not
capital spending on activities risked on any one activity. We also have
such as drilling, well a highly skilled technical team of
completions, well workovers and geologists, geophysicists and engineers
other capital activities will not working to apply the latest technology
result in reserve additions or in planning and executing capital
in quantities sufficient to programs. Capital is spent only after
replace annual production strict economic criteria for production
declines. and reserve additions are assessed.
---------------------------------------------------------------------------
Acquisitions
Acquisition risk associated with Continually scanning the marketplace for
acquiring producing properties opportunities to acquire assets. Our
at low cost to renew our technical acquisition specialists
inventory of assets. evaluate potential corporate or property
acquisitions and identify areas for
value enhancement through operational
efficiencies or capital investment. All
prospects are subjected to rigorous
economic review against established
acquisition and economic hurdle rates.
In some cases we may also hedge
commodity prices to protect the
acquisition economics in the near term
period.
---------------------------------------------------------------------------
Reserves
Reserve risk in respect of the Contracting our reserves evaluation to a
quantity and quality of reputable third party consultant, GLJ
recoverable reserves. 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 Establishing and adhering to strict
safety risks associated with guidelines for EH&S including training,
oil and gas properties and proper reporting of incidents,
facilities. supervision and awareness. PrimeWest has
active community involvement in field
locations including regular meetings
with stakeholders in the area. PrimeWest
carries adequate insurance to cover
property losses, liability and business
interruption.
These risks are reviewed regularly by
the Corporate Governance and EH&S
Committee of the Board.
---------------------------------------------------------------------------
Regulation, Tax and Royalties
Changes in government regulations Keeping informed of proposed changes in
including reporting requirements, regulations and laws to properly respond
income tax laws, operating to and plan for the effects that these
practices, environmental changes may have on our operations.
protection requirements and
royalty rates.
---------------------------------------------------------------------------
Historical Liability to Unitholders
is Uncertain
Because of uncertainties in the On July 1, 2004, a new statute entitled
law prior to July 1, 2004, the Income Trusts Liability Act
relating to investments in (Alberta) was proclaimed in force,
trusts, there is a risk that creating a statutory limitation on the
a Unitholder could be held liability of Unitholders of Alberta
personally liable for income trusts such as PrimeWest. The
obligations of the Trust. 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
---------------------------------------------------------------------------
Unaudited ($ millions) Sep 30, 2006 Dec 31, 2005
---------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 15.6 $ 36.8
Accounts receivable 95.5 125.0
Derivative assets 27.1 -
Future income taxes - 3.9
Prepaid expenses 19.3 16.3
Inventory 0.4 3.5
---------------------------------------------------------------------------
157.9 185.5
Cash reserved for site restoration and
reclamation (note 2) 5.6 9.2
Derivative assets 2.4 -
Other assets and deferred charges 8.0 8.8
Property, plant and equipment 2,323.4 1,859.9
Goodwill 68.5 68.5
---------------------------------------------------------------------------
$ 2,565.8 $ 2,131.9
---------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable $ 45.3 $ 50.2
Accrued liabilities 106.8 75.9
Current portion of long-term debt 184.9 -
Future income taxes 10.1 -
Derivative liabilities - 11.3
Accrued distributions to Unitholders 21.4 25.0
---------------------------------------------------------------------------
368.5 162.4
Long-term debt (note 4) 544.9 354.2
Derivative liabilities 6.1 0.2
Future income taxes 156.7 214.8
Asset retirement obligation (note 2) 89.7 40.4
---------------------------------------------------------------------------
1,165.9 772.0
UNITHOLDERS' EQUITY
Net capital contributions (note 5) 2,378.3 2,294.3
Capital issued but not distributed 3.4 3.6
Convertible unsecured subordinated
debentures 1.2 1.8
Contributed surplus (note 6) 10.7 8.7
Cumulative translation account (0.4) -
Accumulated income 502.5 303.8
Accumulated cash distributions (1,487.8) (1,244.3)
Accumulated dividends (8.0) (8.0)
---------------------------------------------------------------------------
1,399.9 1,359.9
---------------------------------------------------------------------------
$ 2,565.8 $ 2,131.9
---------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY
Nine Months Ended
---------------------------------------------------------------------------
Unaudited ($ millions) Sep 30, 2006 Sep 30, 2005
---------------------------------------------------------------------------
Unitholders' equity, beginning of period $ 1,359.9 $ 1,180.4
Net income for the period 198.7 105.9
Net capital contributions (note 5) 84.0 219.2
Convertible Unsecured Subordinated
Debentures (0.6) (5.6)
Capital issued but not distributed (0.2) (0.2)
Cumulative translation account (0.4) -
Contributed surplus (note 6) 2.0 1.5
Cash distributions (243.5) (200.5)
---------------------------------------------------------------------------
Unitholders' equity, end of period $ 1,399.9 $ 1,300.7
---------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Sep 30, Sep 30, Sep 30,
Unaudited ($ millions) 2006 2005 2006 2005
---------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the period $ 64.0 $ 27.2 $ 198.7 $ 105.9
Add/(deduct) items not
involving cash from
operations
Depletion, depreciation and
amortization 59.1 56.5 166.5 169.7
Non-cash general and
administrative 1.4 1.5 4.4 4.1
Non-cash foreign exchange
loss/(gain) 1.9 (7.9) (4.9) (4.9)
Gain on sale of marketable
securities - - - (27.2)
Unrealized (gain)/loss on
derivatives (9.7) 50.1 (34.8) 67.6
Future income taxes recovery (21.2) (22.2) (44.8) (38.8)
Accretion on asset retirement
obligation 0.7 0.6 2.0 2.0
Other non-cash items 0.4 0.6 1.3 3.2
---------------------------------------------------------------------------
Cash flow from operations $ 96.6 $ 106.4 $ 288.4 $ 281.6
Expenditures on site
restoration and reclamation (5.2) (1.3) (8.9) (4.8)
Change in non-cash working
capital (4.8) (15.1) 21.0 (40.1)
---------------------------------------------------------------------------
86.6 90.0 300.5 236.7
---------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust
Units, net of issue costs 21.9 2.9 31.2 16.5
Increase in senior secured notes - - 130.7 -
Net cash distributions to
Unitholders (64.1) (61.6) (210.0) (174.3)
Increase in deferred charges - - (0.7) -
Increase/(decrease) in bank
credit facilities 296.2 - 266.2 (99.0)
Change in non-cash working
capital 3.2 1.0 (3.4) 1.1
---------------------------------------------------------------------------
257.2 (57.7) 214.0 (255.7)
---------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property,
plant and equipment (76.7) (38.0) (206.7) (148.4)
Acquisition of capital assets (334.5) (2.0) (369.1) (1.6)
Proceeds on disposal of
property, plant and equipment 0.2 1.5 3.4 9.1
Proceeds on sale of marketable
securities - - - 94.5
Increase/(decrease) in cash
reserved for future site
restoration and reclamation 3.4 (0.6) 3.6 (0.8)
Change in non-cash working
capital 22.2 (2.5) 33.1 7.9
---------------------------------------------------------------------------
(385.4) (41.6) (535.7) (39.3)
---------------------------------------------------------------------------
Decrease in cash for the period (41.6) (9.3) (21.2) (58.3)
Cash beginning of the period 57.2 5.4 36.8 54.4
---------------------------------------------------------------------------
Cash/(Deficit) end of the period 15.6 (3.9) 15.6 (3.9)
---------------------------------------------------------------------------
Cash interest paid 4.3 3.3 13.8 17.8
Cash taxes paid 0.1 1.6 1.2 3.0
---------------------------------------------------------------------------
---------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended
---------------------------------------------------------------------------
Sep 30, Sep 30, Sep 30, Sep 30,
Unaudited ($ millions) 2006 2005 2006 2005
---------------------------------------------------------------------------
REVENUES
Sales of crude oil, natural
gas and natural gas liquids $ 183.8 $ 195.0 $ 537.1 $ 521.7
Crown and other royalties (34.5) (44.4) (111.0) (117.3)
Unrealized gain/(loss) on
derivatives 9.7 (50.1) 34.8 (67.6)
Gain on sale of marketable
securities - - - 27.2
Other income 1.1 1.0 4.1 4.0
---------------------------------------------------------------------------
160.1 101.5 465.0 368.0
---------------------------------------------------------------------------
EXPENSES
Operating 34.8 31.6 98.7 84.1
Transportation 1.9 1.7 5.5 5.3
General and administrative 6.5 7.2 21.8 20.1
Depletion, depreciation and
amortization 59.1 56.5 166.5 169.7
Interest 11.9 6.0 21.6 22.8
Accretion on asset retirement
obligation 0.7 0.6 2.0 2.0
Foreign exchange loss/(gain) 1.9 (7.7) (4.9) (4.7)
---------------------------------------------------------------------------
116.8 95.9 311.2 299.3
---------------------------------------------------------------------------
Income before taxes for the
period 43.3 5.6 153.8 68.7
Income and capital taxes 0.5 0.6 (0.1) 1.6
Future income taxes recovery (21.2) (22.2) (44.8) (38.8)
---------------------------------------------------------------------------
(20.7) (21.6) (44.9) (37.2)
---------------------------------------------------------------------------
Net income for the period 64.0 27.2 198.7 105.9
---------------------------------------------------------------------------
Net income per Trust Unit
- basic 0.78 0.35 2.43 1.42
Net income per Trust Unit
- diluted 0.76 0.35 2.