PRIMEWEST ENERGY TRUST (PRIMEWEST OR THE TRUST) (TSX: PWI.UN) (TSX: PWI.DB.A) (TSX: PWI.DB.B) (TSX: PWI.DB.C) (TSX: PWX) (NYSE: PWI) TODAY ANNOUNCES INTERIM OPERATING AND FINANCIAL RESULTS FOR THE QUARTER ENDED SEPTEMBER 30, 2007. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT ARE IN CANADIAN DOLLARS.
Third Quarter 2007 Highlights:
- On July 11, 2007 PrimeWest Energy Trust merged with Shiningbank Energy Income Fund. Pursuant to the merger each Shiningbank Trust Unit was exchanged for 0.62 of a PrimeWest Trust Unit.
- On September 24, 2007, PrimeWest announced that it had entered into an Arrangement Agreement with 1350849 Alberta Ltd. and TAQA North Ltd., both of which are wholly-owned subsidiaries of Abu Dhabi National Energy Company PJSC (TAQA), to purchase all of the issued and outstanding trust units (Trust Units) of PrimeWest and all of the issued and outstanding exchangeable shares (Exchangeable Shares) of PrimeWest Energy Inc. for a cash consideration of Cdn $26.75 per Trust Unit pursuant to a plan of arrangement under the Business Corporations Act (Alberta). The cash consideration payable for the Exchangeable Shares will be calculated on the basis of the exchange ratio in effect at the time the transaction is completed.
The aggregate value of the transaction, including the debt carried by PrimeWest and its subsidiaries, is approximately Cdn $5.0 billion.
- Provided that PrimeWest securityholders approve the transaction at the Special Meeting scheduled for November 21, 2007, and that all of the other conditions to the completion of the transaction are satisfied, the earliest completion date for the transaction is anticipated to be November 23, 2007. The completion date may be later depending on regulatory approvals but in all cases shall be on or before January 31, 2008 or the Arrangement terminates, unless extended in accordance with the terms of the Arrangement Agreement.
- Distributions in the third quarter were $0.75 per Trust Unit representing a payout ratio of approximately 84% of funds flow from operations.
- Funds flow from operations for the third quarter was $123.1 million ($0.89 per Trust Unit) compared to $103.5 million ($1.15 per Trust Unit) in the previous quarter and $91.4 million ($1.11 per Trust Unit) in the third quarter of 2006.
- Third quarter 2007 production averaged 58,941 BOE per day, compared to the second quarter 2007 rate of 40,226 BOE per day. The third quarter production rate includes production from Shiningbank's properties beginning July 11, 2007 which is the main reason for the higher production rate compared to the previous quarter. PrimeWest expects full year 2007 production volumes to average approximately 50,000 BOE per day which includes the impact of divestitures and the Shiningbank merger. The 2007 production exit rate is expected to be approximately 59,000 BOE per day.
- Operating expense was $52.3 million ($9.64 per BOE) in the third quarter of 2007 compared to $34.6 million ($9.46 per BOE) in the second quarter of 2007. The increase in operating expense is mainly due to increased production volumes from the Shiningbank merger and to increases in power costs and workovers. PrimeWest expects full year operating expense per BOE to be approximately $9.50 per BOE including the impact of the Shiningbank merger.
- Development capital expenditures in the third quarter were $62.8 million with drilling, completion and tie-in expenditures of $51.3 million. Forty-two gross wells (26.6 net) were drilled in the third quarter. Full year development capital expenditures are expected to be approximately $250 million.
- In the third quarter of 2007, PrimeWest completed the previously reported divestment program which was initiated in the second quarter of 2007. In total, this divestment program generated net proceeds of $106.4 million as at September 30, 2007 through the sale of approximately 1,700 BOE per day of non-core production. PrimeWest intends to divest approximately 1,800 BOE per day in the fourth quarter of 2007.
- Net debt to annualized third quarter 2007 funds flow from operations was approximately 2.1 times at September 30, 2007, compared to net debt to annualized second quarter 2007 funds flow from operations of 1.5 times at June 30, 2007.
Subsequent Event
- On October 25, 2007 the Government of Alberta announced major proposed changes to the oil and gas royalty structure which are scheduled to take effect on January 1, 2009. A preliminary analysis indicates that PrimeWest's mature, gas weighted asset base will attract only marginally higher royalty rates when compared to the existing structure.
- The Finance Minister delivered the Government's Economic Statement on October 30, 2007 which proposed corporate tax rate reductions over the next five years. The proposed corporate tax rate reductions will apply to the distributions on income trusts as of 2011.
MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF NOVEMBER 6, 2007
The following is management's discussion and analysis (MD&A) of the operating and financial results of PrimeWest Energy Trust (PrimeWest or the Trust) operating and financial results for the three and nine months ended September 30, 2007, compared with the preceding quarter and the corresponding periods in the prior year as well as information and opinions concerning the Trust's future outlook based on currently available information.
Forward-Looking Information
This quarterly report may contain forward-looking or outlook information with respect to PrimeWest.
Certain statements contained in this quarterly report constitute forward-looking statements. The use of any of the words "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "believe", "outlook" and similar expressions are intended to identify forward-looking statements. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in our forward-looking statements.
We believe the expectations reflected in those forward-looking statements are reasonable. However, we cannot assure you that these expectations will prove to be correct. You should not unduly rely on forward-looking statements included in this quarterly report. These statements speak only as of the date of this quarterly report.
In particular, this quarterly report may contain forward-looking statements pertaining to the following:
- The completion of the previously announced transaction with certain subsidiaries of TAQA;
- The quantity and recoverability of our reserves;
- The timing and amount of future production;
- Prices for oil, natural gas and natural gas liquids produced;
- Operating and other costs;
- Business strategies and plans of management;
- Supply and demand for oil and natural gas;
- Expectations regarding our ability to raise capital and to add to our reserves through acquisitions and exploration and development;
- The ability to adequately fund development activities and distributions for any period from funds flow from operations;
- Our treatment under governmental regulatory regimes;
- The focus of capital expenditures on development activity rather than exploration;
- The sale, farming in, farming out or development of certain exploration properties using third-party resources;
- The objective to achieve a predictable level of monthly cash distributions;
- The use of development activity and acquisitions to replace and add to reserves;
- The impact of changes in oil and natural gas prices on cash flow after hedging;
- Drilling plans;
- The existence, operations and strategy of the commodity price risk management program;
- The approximate and maximum amount of forward sales and hedging to be employed;
- Our acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;
- The impact of the Canadian federal and provincial governmental regulations on us relative to other oil and natural gas issuers of similar size;
- The goal to sustain or grow production and reserves through prudent management and acquisitions;
- The emergence of accretive growth opportunities; and
- Our ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets.
With respect to forward-looking statements contained in this quarterly report we have made assumptions regarding, among other things:
- Future oil, natural gas and natural gas liquids prices and differentials between light, medium and heavy oil prices;
- The cost of expanding our property holdings;
- Our ability to obtain equipment in a timely manner to carry out development activities;
- Our ability to market our oil and natural gas successfully to current and new customers;
- The impact of increasing competition;
- Our ability to obtain financing on acceptable terms; and
- Our ability to add production and reserves through our development and exploitation activities.
Our actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below in this quarterly report:
- Volatility in market prices for oil, natural gas and natural gas liquids;
- The impact of weather conditions on seasonal demand;
- Risks inherent in our oil and natural gas operations;
- Uncertainties associated with estimating reserves;
- Competition for, among other things: capital, acquisitions of reserves, undeveloped lands and skilled personnel;
- Incorrect assessments of the value of acquisitions;
- Geological, technical, drilling and processing problems;
- General economic conditions in Canada, the US and globally;
- Tax treatment of the Trust and its subsidiaries;
- Industry conditions, including fluctuations in the price of oil and natural gas;
- Royalties payable in respect of our oil and natural gas production;
- Government regulation of the oil and natural gas industry, including environmental regulation;
- Fluctuation in foreign exchange or interest rates;
- Unanticipated operating events that could reduce production or cause production to be shut-in or delayed;
- Failure to obtain industry partner and other third-party consents and approvals, when required;
- Stock market volatility and market valuations;
- OPEC's ability to control production, and balance global supply and demand of crude oil at desired price levels;
- Increasing globalization of natural gas supply and demand;
- Political uncertainty, including the risks of hostilities, in the petroleum-producing regions of the world;
- The need to obtain required approvals from regulatory authorities; and
- The other factors discussed under Business Risks contained in this quarterly report.
These factors should not be construed as exhaustive. The forward-looking statements contained in this quarterly report are expressly qualified by this cautionary statement. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or revise any forward-looking statements.
All figures reported in Canadian dollars unless otherwise stated.
Production figures stated are before the deduction of royalties.
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer, Donald A. Garner, and the Chief Financial Officer, Douglas S. Fraser, evaluated the effectiveness of PrimeWest's disclosure controls and procedures as of September 30, 2007, and concluded that PrimeWest's disclosure controls and procedures were effective to ensure that information PrimeWest is required to disclose:
- In its annual filings and interim filings (each as defined in National Instrument 52-109 of the Canadian Securities Administrators) filed or submitted by it under provincial securities legislation is recorded, processed, summarized and reported within the time periods specified in the provincial securities legislation and to ensure that information required to be disclosed by PrimeWest in its annual filings and interim filings filed or submitted under provincial securities legislation is accumulated and communicated to PrimeWest's management, including its chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure; and
- In its annual filings, interim filings or other reports with the US Securities and Exchange Commission (SEC) in the US under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and to ensure that information required to be disclosed by PrimeWest in the reports that it files under the Exchange Act is accumulated and communicated to PrimeWest's management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
The evaluation took into consideration PrimeWest's Communications and Disclosure Policy and the functioning of its executive officers, board of directors and board committees. In addition, the evaluation covered PrimeWest's processes, systems and capabilities relating to regulatory filings, public disclosures and the identification and communication of material information.
Changes to Internal Controls Over Financial Reporting
There were no changes to PrimeWest's internal controls over financial reporting since June 30, 2007, which have materially affected, or are reasonably likely to materially affect, PrimeWest's internal control over financial reporting.
Non-GAAP Measures
This MD&A contains the following measurements that are not defined by Canadian Generally Accepted Accounting Principles (GAAP):
- Funds flow from operations on a total and per Trust Unit basis;
- Distributions per Trust Unit; and
- Net debt per Trust Unit.
These measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other issuers.
Funds flow from operations is measured as cash flow from operating activities before changes in non-cash working capital. Funds flow from operations does not represent operating cash flows or operating profits for the period and should not be viewed as an alternative to cash flow from operating activities calculated in accordance with GAAP. Funds flow from operations is a key performance indicator of PrimeWest's ability to generate cash to finance operations and to pay monthly distributions.
Funds flow from operations per Trust Unit on a basic basis is calculated by dividing funds flow from operations by the weighted average number of Trust Units outstanding plus Trust Units issueable upon the exchange of the outstanding Exchangeable Shares of PrimeWest Energy Inc. (Exchangeable Shares). Funds flow from operations per Trust Unit on a diluted basis is calculated using funds flow from operations and adding back the interest expense on the Convertible Unsecured Subordinated Debentures (Debentures), divided by the diluted weighted average number of Trust Units outstanding in the period. The diluted weighted average number of Trust Units outstanding consists of the weighted average Trust Units plus Trust Units issueable upon the exchange of outstanding Exchangeable Shares and includes the Trust Units issueable pursuant to the conversion of the Debentures, and Trust Units issueable pursuant to the Long-Term Incentive Plan (LTIP).
Distributions per Trust Unit disclose the cash distributions accrued in the period based on the number of Trust Units outstanding on the applicable record dates.
Net debt 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 Trust Units issueable upon the exchange of outstanding Exchangeable Shares and Trust Units issueable pursuant to the LTIP at September 30, 2007.
Business Strategy
PrimeWest is an Alberta based conventional oil and natural gas energy trust actively managed to generate monthly cash distributions for the holders of Trust Units (Unitholders). The Trust's operations are focused in the Western Canada Sedimentary Basin and Montana, North Dakota and Wyoming in the United States. PrimeWest is one of North America's largest natural gas-weighted energy trusts.
Maximizing total return to Unitholders, in the form of cash distributions and appreciation in unit price, is PrimeWest's overriding objective. Our strategies for asset management and growth, financial management and corporate governance are outlined in this MD&A, along with a discussion of our performance for the three and nine months ended September 30, 2007, and our goals for the remainder of 2007.
We believe that PrimeWest can maximize total return to Unitholders by continuing to develop our core properties, making opportunistic acquisitions that emphasize value creation, exercising disciplined financial management which broadens access to capital while minimizing risk to Unitholders, and complying with strong corporate governance principles to protect the interests of all stakeholders.
Asset Management and Growth
PrimeWest has a strategy to focus expansion efforts on existing core areas and pursue depletion optimization strategies within those core areas to maximize asset value. We make every effort to obtain operatorship of our asset base and maintain high working interests in core areas. We currently maintain operatorship of approximately 80% of our assets, which allows us to use existing infrastructure and synergies within our core areas. We believe this high level of control can translate into cost efficiencies and optimize timing of capital outlays and projects.
Financial Management
PrimeWest strives to maintain a prudent debt position, to allow us to fund smaller acquisitions and to fund ongoing development activities without accessing the capital markets. Our long-term debt is comprised of credit facilities through a bank syndicate, US-dollar-denominated Senior Secured Notes (US Secured Notes), Pounds Sterling denominated Senior Secured Notes (U.K. Secured Notes) and Debentures. Our diversified debt instruments help to reduce our reliance on the bank syndicate. PrimeWest's commodity hedging strategy is designed to reduce the volatility of cash flow by providing some near term downside price protection. Hedging a portion of our production protects acquisition economics and our capital structure and provides partial protection against short-term declines in commodity prices. In accordance with the terms of the Arrangement Agreement with 1350849 Alberta Ltd. And TAQA North Ltd., PrimeWest has not entered into any new hedging contracts subsequent to September 24, 2007.
PrimeWest's dual listing on the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) provides increased liquidity and a broadened investor base. The NYSE listing enables US Unitholders to conveniently trade in our Trust Units, and allows us to access the US capital markets. Our status as a corporation for US tax purposes simplifies tax reporting for our US Unitholders.
On September 24, 2007 PrimeWest announced the suspension of the conventional Distribution Reinvestment Plan (DRIP), the Optional Trust Unit Purchase Plan (OTUPP) and the Premium Distribution Plan (PREP) with respect to any distribution paid on the Trust Units after October 15, 2007.
Corporate Governance
PrimeWest is committed to high standards of corporate governance and upholds the rules of the governing regulatory bodies under which it operates. Full disclosure of our compliance with existing corporate governance rules and regulations is contained in the Trust's Management Proxy Circular dated March 15, 2007, which is available on our website. 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 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Gross revenue 240.4 186.5 176.0 616.6 524.9 per BOE 44.33 50.94 47.38 48.02 49.78 Funds flow from operations 123.1 103.5 91.4 312.6 279.5 per BOE 22.70 28.27 24.59 24.35 26.51 per Trust Unit - basic (2) 0.89 1.15 1.11 2.92 3.42 per Trust Unit - diluted (3) 0.86 1.08 1.09 2.78 3.42 Royalty expense 46.5 30.3 34.5 116.7 111.0 per BOE 8.57 8.27 9.29 9.09 10.53 Operating expense 52.3 34.6 35.4 125.9 99.3 per BOE 9.64 9.46 9.54 9.80 9.41 General and administrative expense (G&A) 12.3 9.6 6.5 31.3 21.8 per BOE 2.27 2.64 1.76 2.43 2.06 Interest expense (4) 16.6 11.2 11.9 40.1 21.6 per BOE 3.06 3.07 3.20 3.12 2.06 Distributions to Unitholders 108.8 68.1 74.0 244.7 243.5 per Trust Unit (5) 0.75 0.75 0.90 2.25 3.00 Net debt (6) 1,024.0 619.2 772.4 1,024.0 772.4 per Trust Unit (7) 6.98 6.70 9.16 6.98 9.16 ---------------------------------------------------------------------------- (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 funds flow for the diluted per Trust Unit calculation. (4) Interest expense includes the interest on the Debentures. (5) Based on Trust Units outstanding at the record dates for distributions during the period. (6) Net debt is long-term debt including the Debentures adjusted for working capital, excluding current derivative and future income tax assets and liabilities. (7) The net debt per Trust Unit calculation includes outstanding Trust Units, Trust Units issueable upon exchange of the outstanding Exchangeable Shares and Trust Units issueable pursuant to the LTIP at the end of the period. Operating Highlights Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, Daily Production Volumes 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Natural gas (mmcf/day) 250.8 165.2 164.1 195.4 164.7 Crude oil (bbls/day) 10,561 8,666 9,106 9,438 7,434 Natural gas liquids (bbls/day) 6,584 4,027 3,931 5,026 3,736 ---------------------------------------------------------------------------- Total (BOE per day) 58,941 40,226 40,381 47,034 38,625 ---------------------------------------------------------------------------- Average Realized Sales Prices Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Natural gas ($/Mcf) (1) 5.65 7.57 6.20 6.81 7.19 Crude oil ($/bbl) 69.97 62.58 69.18 63.99 65.38 Natural gas liquids ($/bbl) 65.33 59.06 62.50 60.29 61.54 ---------------------------------------------------------------------------- Total Oil Equivalent ($/BOE) 43.88 50.50 46.86 47.56 49.20 ---------------------------------------------------------------------------- Realized derivative gains ($/BOE) 2.74 0.44 2.10 1.75 1.15 ---------------------------------------------------------------------------- Net realized price ($/BOE) 46.62 50.94 48.96 49.31 50.35 ---------------------------------------------------------------------------- (1) Excludes sulphur. Funds Flow From Operations Reconciliation ---------------------------------------------------------------------------- $ millions ---------------------------------------------------------------------------- Second quarter 2007 funds flow from operations 103.5 Volumes 86.4 Commodity prices (33.4) Net hedging change from prior quarter 13.3 Operating expenses (17.7) Royalties (16.2) Site restoration and reclamation (3.0) Interest (5.4) Other (4.4) ---------------------------------------------------------------------------- Third quarter 2007 funds flow from operations 123.1 ----------------------------------------------------------------------------
The above table includes a non-GAAP measure (refer to section regarding Non-GAAP Measures).
A key performance driver for the Trust is funds flow from operations, which directly affects PrimeWest's ability to pay monthly distributions. Funds flow from operations is generated through the production and sale of crude oil, natural gas and natural gas liquids, and is dependent on production levels, commodity prices, operating expense, site restoration and reclamation expenditures, interest expense, G&A expense, derivative gains or losses, royalties and currency exchange rates. Some of these factors such as commodity prices, the currency exchange rate and royalties are uncontrollable from PrimeWest's perspective. Other factors that are to a certain extent controllable by PrimeWest are production levels and operating, interest and G&A expenses.
Reconciliation of Non-GAAP Measure
The following table reconciles the non-GAAP measure, funds flow from operations, to the nearest GAAP measure cash flow from operating activities.
Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, $ millions 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Funds flow from operations 123.1 103.5 91.4 312.6 279.5 Change in non-cash working capital (5.6) 1.5 (4.8) (7.5) 21.0 ---------------------------------------------------------------------------- Cash flow from operating activities 117.5 105.0 86.6 305.1 300.5 ----------------------------------------------------------------------------
Quarterly Performance - Selective Measures
The following table highlights PrimeWest's performance for the third quarter ended September 30, 2007, and the preceding seven quarters through 2005.
2007 2006 2005 ---------------------------------------------------------------------------- $ millions, except per Trust Unit Amounts Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 ---------------------------------------------------------------------------- Net Revenues 204.7 173.1 126.0 158.4 160.7 135.0 170.0 237.1 Net Income 46.9 112.4 5.5 9.6 64.0 65.7 68.9 101.5 Funds Flow from Operations 123.1 103.5 85.8 84.6 91.4 86.8 101.3 128.6 Net income per Trust Unit - basic 0.34 1.24 0.06 0.11 0.78 0.81 0.85 1.27 Net income per Trust Unit - diluted 0.34 1.17 0.06 0.11 0.76 0.79 0.83 1.23 Funds flow per Trust Unit - basic 0.89 1.15 0.95 1.01 1.11 1.06 1.25 1.61 Funds flow per Trust Unit - diluted 0.86 1.08 0.90 1.00 1.09 1.03 1.22 1.56 ----------------------------------------------------------------------------
Net revenues are impacted primarily by commodity prices, production volumes, royalties and realized and unrealized gains or losses on derivatives.
Net income includes the following non-cash items: depletion, depreciation and amortization (DD&A), unit-based compensation, future income taxes, unrealized foreign exchange gains or losses and changes in unrealized gains or losses on derivatives. Non-cash items will not affect PrimeWest's current ability to pay a monthly distribution.
Capital Expenditures Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, $ millions 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Land and lease acquisitions 2.1 1.6 2.0 4.8 8.9 Geological and geophysical 1.3 1.0 0.5 4.8 2.5 Drilling and completions 44.5 16.2 53.8 109.7 129.6 Investment in facilities Equipping and tie-in 6.8 7.8 8.7 23.0 38.7 Gas gathering and compression 3.6 3.1 7.8 13.5 10.1 Production facilities 3.6 2.3 2.2 8.2 10.0 Capitalized G&A 0.9 1.0 1.3 3.3 3.9 ---------------------------------------------------------------------------- Development capital 62.8 33.0 76.3 167.3 203.7 ---------------------------------------------------------------------------- Acquisition of oil and gas assets 1,689.1 0.8 368.8 1,701.4 369.1 Dispositions (58.8) (47.6) (0.2) (106.4) (3.4) Leasehold improvements, furniture and equipment 0.6 0.6 0.4 2.3 3.0 ---------------------------------------------------------------------------- Net capital expenditures 1,693.7 (13.2) 445.3 1,764.6 572.4 ----------------------------------------------------------------------------
PrimeWest is continually striving to add to reserves and offset the natural decline in its oil and natural gas reserves in an effort to create value for the unitholders. Investment in activities such as development drilling, workovers and recompletions can add incremental production volumes and reserves.
On July 11, 2007, PrimeWest merged with Shiningbank Energy Income Fund, resulting in the acquisition of oil and gas assets of $1,689.8 million.
PrimeWest continues to focus on its four key development plays: conventional development, tight gas, US oil assets and coalbed methane (CBM). During the third quarter $51.3 million was invested in drilling and completions and tie-ins. PrimeWest drilled 42 gross wells (26.6 net) in the third quarter. During the quarter PrimeWest sold non-core assets for net proceeds of $58.8 million.
Capital Outlook
Development activity for the remainder of the year will be focused on tight gas assets at Caroline, Columbia and Ferrier as well as on conventional assets at Wilson Creek, Valhalla, Whitecourt and BC Gas. PrimeWest will continue with the first phase of drilling at the Crossfield CBM project during the fourth quarter of 2007.
Total 2007 development capital expenditures are estimated to be $250 million and will be allocated approximately as follows:
---------------------------------------------------------------------------- $ millions ---------------------------------------------------------------------------- Conventional development 100 Tight gas 50 US assets 25 Coalbed methane (CBM) 40 Land, seismic, central facilities and plants, maintenance and capitalized G&A 35 ---------------------------------------------------------------------------- Total Development Capital 250 ---------------------------------------------------------------------------- Daily Production Volumes Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, Daily Production Volumes 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Natural gas (mmcf/day) 250.8 165.2 164.1 195.4 164.7 Crude oil (bbls/day) 10,561 8,666 9,106 9,438 7,434 Natural gas liquids (bbls/day) 6,584 4,027 3,931 5,026 3,736 ---------------------------------------------------------------------------- Total (BOE per day) 58,941 40,266 40,381 47,034 38,625 ----------------------------------------------------------------------------
The significant increase in production volumes for the three and nine months ended September 30, 2007 compared to the same periods in 2006 and the previous quarter is primarily due to the merger with Shiningbank in the third quarter of 2007. Shiningbank volumes have been consolidated with PrimeWest effective July 11, 2007.
During the third quarter PrimeWest completed the divestment program of approximately 1,700 BOE per day from non-core assets which was commenced in May 2007. Additional divestments of approximately 1,800 BOE per day are expected to be completed in the fourth quarter of 2007.
Production Outlook
PrimeWest expects full year 2007 production volumes to average approximately 50,000 BOE per day which includes the impact of divestitures and the Shiningbank merger. The 2007 exit production rate is expected to be approximately 59,000 BOE per day.
Commodity Prices Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, Benchmark Prices 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Natural gas NYMEX (US$/Mcf) 6.13 7.56 6.53 6.88 7.47 AECO (C$/Mcf) 5.61 7.37 6.03 6.81 7.19 Crude oil WTI (US$/bbl) 75.38 65.03 70.48 66.23 68.22 ---------------------------------------------------------------------------- Benchmark Commodity Prices The following table sets forth benchmark historical and estimated future commodity prices. Past Four Quarters Next Four Quarters (Actual) (Forward Markets)(1) ---------------------------------------------------------------------------- Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2006 2007 2007 2007 2007 2008 2008 2008 ---------------------------------------------------------------------------- Natural gas AECO (C$/Mcf) 6.36 7.46 7.37 5.61 5.93 6.81 6.66 6.78 Crude oil WTI (US$/bbl) 60.21 58.27 65.03 75.38 80.23 78.15 76.84 75.76 ---------------------------------------------------------------------------- (1) As at September 30, 2007. Average Realized Sales Prices Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2007 2007 2006 2007 2006 Natural gas ($/Mcf) (1)(2) 6.32 7.64 6.69 7.17 7.49 Without derivatives 5.65 7.57 6.20 6.81 7.19 Crude oil ($/bbl) (1) 69.34 63.46 69.64 65.08 64.77 Without derivatives 69.97 62.58 69.18 63.99 65.38 Natural gas liquids ($/bbl) 65.33 59.06 62.50 60.29 61.54 ---------------------------------------------------------------------------- Total Oil Equivalent ($/BOE) (1)(2) 46.61 50.94 48.96 49.31 50.35 Without derivatives 43.88 50.50 48.86 47.56 49.20 ---------------------------------------------------------------------------- Realized derivative gains included in prices above ($/BOE) 2.73 0.44 2.10 1.75 1.15 ---------------------------------------------------------------------------- (1) Includes derivatives gains/losses. (2) Excludes sulphur.
Natural gas prices in the third quarter continued to be negatively influenced by weather. Due to a warm spring, less gas fired electrical generation was required, resulting in early season projections of an increasing supply surplus. Increases in liquefied natural gas imports in the U.S., combined with strong builds in US domestic production, contributed to further downward pressure on gas prices. This was partially offset by a decrease in year over year Canadian gas exports, and US price-driven domestic shut-ins. By August, the downward pressure on gas prices was relieved temporarily due to widespread above normal US temperatures. However, the market softened again in September in the absence of any summer hurricane activity shutting in gas production. It is expected that the gas storage surplus will continue to limit any natural gas price increases until colder temperature arrives in North America.
Crude oil prices continued to respond upward to geopolitical events due to forecasts of world demand growth exceeding the rate of supply growth. By the end of August, the WTI market was in backwardation with near term prices higher than future prices for the first time in two years. In late October, WTI prices traded over US $90/bbl.
Sales Revenue Nine ($ millions) Three Months Ended Months Ended ---------------------------------------------------------------------------- Revenue (1)(2)(3) Sep 30, % of Jun 30, % of Sep 30, % of Sep 30, Sep 30, 2007 Total 2007 Total 2006 Total 2007 2006 Natural gas 130.4 55 113.9 62 93.5 54 363.1 323.3 Crude oil 68.0 29 49.4 27 58.0 33 164.9 132.7 Natural gas liquids 39.5 16 21.6 11 22.6 13 82.7 62.7 ---------------------------------------------------------------------------- Total 237.9 100 184.9 100 174.1 100 610.7 518.7 ---------------------------------------------------------------------------- (1) Excludes sulphur. (2) Net of transportation expenses. (3) Excludes impact of derivatives.
Revenues for the three and nine months ended September 30, 2007 are higher than they were in the same periods in 2006 and the previous quarter mainly due to additional volumes resulting from the Shiningbank merger, partially offset by decreases in natural gas prices.
As at end of September 2007, approximately 70% of PrimeWest's production on an energy equivalent basis was natural gas; therefore, the Trust has greater sensitivity to changes in natural gas prices than crude oil prices.
Financial Derivatives
As part of our risk management strategy PrimeWest uses financial instruments to manage commodity prices. These instruments are commonly referred to as "hedges." The purpose of the hedging program is to reduce volatility in cash flows and to protect acquisition economics against the unpredictable commodity price environment. PrimeWest did not elect to adopt hedge treatment for accounting purposes.
PrimeWest has a financial swap which converts the interest and principal payments associated with the U.K. Senior Notes into Canadian dollars from pounds sterling. The pounds sterling debt and interest payable are converted to Canadian dollars at the foreign currency exchange rate in effect the end of each reporting period.
In accordance with the terms of the Arrangement Agreement with 1350849 Alberta Ltd. And TAQA North Ltd., PrimeWest has not entered into any new hedging contracts subsequent to September 24, 2007.
PrimeWest's derivatives are marked-to-market at the end of each reporting period with the resulting change in the gain or loss from the prior period reflected in earnings for that period. The unrealized gain or loss is a point-in-time measurement of PrimeWest's hedging position at the end of the period. The magnitude of the gain or loss will fluctuate with changes to commodity prices.
The following table provides a summary of net realized and unrealized gains and losses on financial derivatives for the three and nine months ended September 30, 2007 and 2006.
---------------------------------------------------------------------------- Three Months Ended September 30, 2007 ---------------------------------------------------------------------------- Foreign ($ millions except per BOE) Oil Gas Power Exchange Total Realized (losses)/gains on derivatives (0.6) 15.4 0.1 - 14.9 Unrealized (losses)/gains on derivatives (6.0) 5.9 0.1 (5.3) (5.3) ---------------------------------------------------------------------------- Total (losses)/gains on derivatives (6.6) 21.3 0.2 (5.3) 9.6 ---------------------------------------------------------------------------- Realized (losses)/ gains on derivatives per BOE (0.11) 2.84 0.01 - 2.74 Unrealized (losses)/gains on derivatives per BOE (1.11) 1.09 0.01 (0.97) (0.98) ---------------------------------------------------------------------------- Nine Months Ended September 30, 2007 ---------------------------------------------------------------------------- Foreign ($ millions except per BOE) Oil Gas Power Exchange Total Realized gains/(losses) on derivatives 2.8 19.6 0.1 (0.1) 22.4 Unrealized (losses)/gains on derivatives (13.6) 3.5 0.1 (15.3) (25.3) ---------------------------------------------------------------------------- Total (losses)/gains on derivatives (10.8) 23.1 0.2 (15.4) (2.9) ---------------------------------------------------------------------------- Realized gains/(losses) on derivatives per BOE 0.22 1.53 - - 1.75 Unrealized (losses)/gains on derivatives per BOE (1.06) 0.28 - (1.19) (1.97) ---------------------------------------------------------------------------- Three Months Ended September 30, 2006 ---------------------------------------------------------------------------- Foreign ($ millions except per BOE) Oil Gas Power Exchange Total Realized gains on derivatives 0.4 7.4 0.6 - 8.4 Unrealized gains/(losses) on derivatives 7.9 5.5 0.1 (3.8) 9.7 ---------------------------------------------------------------------------- Total gains/(losses) on derivatives 8.3 12.9 0.7 (3.8) 18.1 ---------------------------------------------------------------------------- Realized gains on derivatives per BOE 0.10 2.00 0.17 - 2.27 Unrealized gains/(losses) on derivatives per BOE 2.12 1.48 0.03 (1.02) 2.61 ---------------------------------------------------------------------------- Nine Months Ended September 30, 2006 ---------------------------------------------------------------------------- Foreign ($ millions except per BOE) Oil Gas Power Exchange Total Realized (losses)/gains on derivatives (1.2) 13.4 - 0.6 12.8 Unrealized gains/(losses) on derivatives 7.4 33.4 0.1 (6.1) 34.8 ---------------------------------------------------------------------------- Total gains/(losses) on derivatives 6.2 46.8 0.1 (5.5) 47.6 ---------------------------------------------------------------------------- Realized (losses)/gains on derivatives per BOE (0.12) 1.27 - 0.06 1.21 Unrealized gains/(losses) on derivatives per BOE 0.71 3.17 0.01 (0.58) 3.31 ----------------------------------------------------------------------------
The following table sets forth the approximate percentage of future anticipated production volumes hedged at September 30, 2007, net of anticipated royalties, reflecting full production declines with no offsetting additions.
---------------------------------------------------------------------------- Production Volumes Hedged (%) Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 ---------------------------------------------------------------------------- Crude Oil 65 51 49 41 32 17 Natural Gas 56 44 38 29 22 15 ---------------------------------------------------------------------------- The following derivative contracts were in place at September 30, 2007: Crude Oil ---------------------------------------------------------------------------- Period Volume (bbls/d) Type WTI Price (US$/bbl) ---------------------------------------------------------------------------- Oct - Dec 07 500 Costless Collar 60.00/75.00 Oct - Dec 07 500 Costless Collar 60.00/90.25 Oct - Dec 07 500 Swap 74.58 Oct - Dec 07 500 Costless Collar 65.00/91.35 Oct - Dec 07 800 Costless Collar 70.00/82.10 Oct - Dec 07 500 Costless Collar 55.00/78.25 Oct - Dec 07 500 Costless Collar 60.00/76.60 Oct - Dec 07 500 Costless Collar 60.00/75.20 Oct - Dec 07 500 Costless Collar 60.00/76.60 Oct - Dec 07 500 Costless Collar 60.00/75.05 Oct - Dec 07 500 Costless Collar 65.00/80.85 Oct - Dec 07 1000 Costless Collar 65.00/81.00 Oct - Dec 07 500 Costless Collar 65.00/85.62 Jan - Mar 08 500 Costless Collar 55.00/78.00 Jan - Mar 08 500 Costless Collar 60.00/77.10 Jan - Mar 08 500 Costless Collar 60.00/76.60 Jan - Mar 08 500 Costless Collar 60.00/70.00 Jan - Mar 08 500 Costless Collar 60.00/75.10 Jan - Mar 08 500 Costless Collar 60.00/75.25 Jan - Mar 08 500 Costless Collar 65.00/80.25 Jan - Mar 08 1000 Costless Collar 65.00/80.70 Jan - Mar 08 500 Costless Collar 60.00/80.40 Jan - Mar 08 500 Costless Collar 65.00/80.08 Apr - Jun 08 500 Costless Collar 60.00/77.35 Apr - Jun 08 500 Costless Collar 60.00/70.00 Apr - Jun 08 500 Costless Collar 60.00/75.95 Apr - Jun 08 500 Costless Collar 60.00/75.10 Apr - Jun 08 500 Costless Collar 60.00/82.62 Apr - Jun 08 500 Costless Collar 65.00/80.10 Apr - Jun 08 500 Costless Collar 65.00/80.00 Apr - Jun 08 1000 Costless Collar 65.00/80.75 Apr - Jun 08 500 Costless Collar 60.00/78.88 Jul - Sep 08 500 Costless Collar 60.00/75.05 Jul - Sep 08 500 Costless Collar 60.00/75.25 Jul - Sep 08 500 Costless Collar 60.00/82.72 Jul - Sep 08 500 Costless Collar 65.00/80.10 Jul - Sep 08 500 Costless Collar 65.00/80.01 Jul - Sep 08 1000 Costless Collar 65.00/80.75 Jul - Sep 08 500 Costless Collar 60.00/78.02 Oct - Dec 08 500 Costless Collar 60.00/82.05 Oct - Dec 08 500 Costless Collar 65.00/80.55 Oct - Dec 08 500 Costless Collar 65.00/80.01 Oct - Dec 08 1000 Costless Collar 65.00/80.90 Oct - Dec 08 500 Costless Collar 60.00/77.45 Jan - Mar 09 1000 Costless Collar 65.00/80.45 Jan - Mar 09 500 Costless Collar 60.00/76.85 ---------------------------------------------------------------------------- Natural Gas ---------------------------------------------------------------------------- Period Volume (mmcf/d) Type AECO Price (C$/mcf) ---------------------------------------------------------------------------- Oct - Dec 07 9.5 Costless Collar 6.86/9.50 Oct 07 9.5 Costless Collar 7.07/9.02 Oct - Dec 07 4.7 Costless Collar 7.39/9.18 Oct 07 4.7 Costless Collar 7.02/9.02 Oct 07 4.7 Costless Collar 7.39/9.50 Oct - Dec 07 9.5 Swap 8.20 Oct - Dec 07 5.0 Costless Collar 7.39/12.28 Oct - Dec 07 5.0 Costless Collar 5.28/12.66 Oct - Dec 07 5.0 Costless Collar 7.39/12.77 Oct - Dec 07 5.0 Costless Collar 7.39/13.40 Oct - Dec 07 10.0 Costless Collar 7.39/9.84 Oct - Dec 07 10.0 Costless Collar 7.39/10.29 Oct - Dec 07 5.0 Costless Collar 7.39/9.71 Oct - Dec 07 5.0 Costless Collar 7.39/10.76 Oct - Dec 07 5.0 Costless Collar 7.39/10.60 Oct - Dec 07 5.0 Costless Collar 7.39/10.18 Oct - Dec 07 5.0 Costless Collar 6.33/8.55 Oct - Dec 07 10.0 Costless Collar 5.28/9.02 Oct - Dec 07 5.0 Costless Collar 6.33/8.44 Oct - Dec 07 10.0 Costless Collar 4.75/7.66 Jan - Mar 08 5.0 Costless Collar 6.33/12.71 Jan - Mar 08 5.0 Costless Collar 8.44/15.67 Jan - Mar 08 10.0 Costless Collar 7.39/12.40 Jan - Mar 08 10.0 Costless Collar 7.39/11.61 Jan - Mar 08 5.0 Costless Collar 7.39/11.56 Jan - Mar 08 5.0 Costless Collar 7.39/11.61 Jan - Mar 08 5.0 Costless Collar 7.39/12.55 Jan - Mar 08 5.0 Costless Collar 7.39/12.87 Jan - Mar 08 5.0 Costless Collar 7.39/12.45 Jan - Mar 08 5.0 Costless Collar 7.39/11.61 Jan - Mar 08 5.0 Costless Collar 6.33/11.43 Jan - Mar 08 10.0 Costless Collar 6.33/9.66 Jan - Mar 08 5.0 Costless Collar 6.33/10.55 Jan - Mar 08 10.0 Costless Collar 6.33/7.88 Apr - Jun 08 10.0 Costless Collar 7.39/8.97 Apr - Jun 08 5.0 Costless Collar 6.33/9.76 Apr - Jun 08 5.0 Costless Collar 7.39/8.91 Apr - Jun 08 5.0 3-Way 6.33/7.39/10.13 Apr - Jun 08 5.0 Costless Collar 7.39/8.97 Apr - Jun 08 5.0 Costless Collar 7.39/9.50 Apr - Jun 08 5.0 Costless Collar 6.86/9.65 Apr - Jun 08 5.0 Costless Collar 6.86/9.50 Apr - Jun 08 5.0 Costless Collar 6.33/9.02 Apr - Jun 08 10.0 Costless Collar 6.33/8.24 Apr - Jun 08 5.0 Costless Collar 6.33/8.49 Apr - Jun 08 10.0 Costless Collar 6.33/7.28 Jul - Sep 08 5.0 Costless Collar 7.39/9.39 Jul - Sep 08 5.0 Costless Collar 7.39/9.50 Jul - Sep 08 5.0 3-Way 6.33/7.39/10.97 Jul - Sep 08 5.0 Costless Collar 7.39/9.51 Jul - Sep 08 5.0 Costless Collar 6.86/9.51 Jul - Sep 08 5.0 Costless Collar 6.33/9.60 Jul - Sep 08 10.0 Costless Collar 6.33/8.62 Jul - Sep 08 5.0 Costless Collar 6.33/9.54 Jul - Sep 08 10.0 Costless Collar 6.33/7.70 Oct - Dec 08 5.0 Costless Collar 7.39/10.81 Oct - Dec 08 5.0 Costless Collar 7.39/10.55 Oct - Dec 08 5.0 Costless Collar 6.86/10.71 Oct - Dec 08 10.0 Costless Collar 6.33/10.44 Oct - Dec 08 5.0 Costless Collar 6.33/10.55 Oct - Dec 08 10.0 Costless Collar 6.33/9.68 Jan - Mar 09 10.0 Costless Collar 6.33/12.35 Jan - Mar 09 5.0 Costless Collar 7.39/10.55 Jan - Mar 09 10.00 Costless Collar 6.33/11.91 ----------------------------------------------------------------------------
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 $10.13, purchased a put at $7.39, and resold the put at $6.33. Should the market price drop below $7.39, PrimeWest will receive $7.39 until the price is less than $6.33, at which time PrimeWest will then receive market price plus $1.06. However, should market prices rise above $10.13, PrimeWest will receive a maximum of $10.13. Should the market price remain between $7.39 and $10.13, PrimeWest will receive the market price.
Power ---------------------------------------------------------------------------- Period Volume Price (C$/MWh) ---------------------------------------------------------------------------- Oct 07 - Oct 08 1 MW 71.40 ---------------------------------------------------------------------------- Foreign Exchange ---------------------------------------------------------------------------- Amount Pounds Period Sterling (000's) Type Price ---------------------------------------------------------------------------- Oct 07 - Jun 16 Principal 63,000 Swap $2.0748 Cdn per Pounds Interest 30,846 Sterling 1.00 ----------------------------------------------------------------------------
Royalties
PrimeWest pays Crown, freehold and overriding royalties to the owners of mineral rights with whom PrimeWest holds leases. These royalties vary for each property and product. The Crown royalty system is based on a sliding scale structure that increases the royalty rates as commodity prices rise. Due to the sliding scale Crown royalty system, future changes to commodity prices will result in changes to royalty rates and expenses. In certain situations, the Crown grants royalty "holidays" which eliminate royalties on specific wells.
Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- $ millions, except Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, per BOE 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Royalty expense 46.5 30.3 34.5 116.7 111.0 Per BOE 8.57 8.27 9.29 9.09 10.53 Royalties as a % of sales revenues 19.5% 16.4% 19.8% 19.1% 21.4% ----------------------------------------------------------------------------
Royalty expense as a percentage of sales was higher in the third quarter of 2007 compared to the second quarter of 2007 due to the second quarter adjustment for an over estimate of freehold mineral tax relating to prior periods and the annual Crown adjustment for gas cost allowance. Without these adjustments, the royalty rate for the second quarter would have been 19.5%.
Royalty expense as a percentage of sales for the nine months ended September 2007 was lower compared to the same period in 2006 due to the adjustment to freehold mineral tax in the second quarter of 2007.
On October 25th, 2007 the Government of Alberta announced major proposed changes to the oil and gas royalty structure which are scheduled to take effect on January 1, 2009. A preliminary analysis indicates that PrimeWest's mature, gas weighted asset base will attract only marginally higher royalty rates when compared to the existing structure.
Operating Expense Three months Ended Nine months Ended ---------------------------------------------------------------------------- $ millions, except Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, per BOE 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Operating expense 52.3 34.6 35.4 125.9 99.3 Per BOE 9.64 9.46 9.54 9.80 9.41 ----------------------------------------------------------------------------
Third quarter 2007 operating expense totalled $52.3 million, an increase of 51% from $34.6 million in the second quarter of 2007 due mainly to the merger with Shiningbank effective July 11, 2007. Increases to power costs and to workovers also contributed to the higher operating expense and operating expense per BOE.
Operating expense and operating expense per BOE for the three and nine months ended 2007 increased compared to the same periods in 2006 due to the Shiningbank merger and to the impact of inflationary pressures on the prices of goods and services.
Operating Expense Outlook
PrimeWest anticipates that its full year operating expense will be approximately $9.50 per BOE including the impact of the Shiningbank merger.
Operating Margin Three months Ended Nine months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, $ per BOE 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Sales price and other revenue (1) 44.12 51.47 47.17 48.07 49.67 Royalties (8.57) (8.27) (9.29) (9.09) (10.53) Operating expense (9.64) (9.46) (9.36) (9.80) (9.36) ---------------------------------------------------------------------------- Operating margin before realized derivate gains 25.91 33.74 28.52 29.18 29.78 Realized derivative gains 2.73 0.44 2.10 1.75 1.15 ---------------------------------------------------------------------------- Operating margin after realized derivative gains 28.64 34.18 30.62 30.93 30.93 ---------------------------------------------------------------------------- (1) Includes sulphur.
Operating margin is an important measure of our business because it gives an indication of the amount of cash flow PrimeWest realizes per BOE that is produced, before head office expenses and financing charges.
The operating margin per BOE decreased in the third quarter of 2007 compared to the previous quarter mainly due to decreases in natural gas prices, increases to royalty expense and increases to operating expense. Increases in crude oil prices and realized derivative gains had a positive impact on the operating margin.
The third quarter 2007 operating margin was lower than the same period in 2006 due to decreases in natural gas prices and increases to operating expense partially offset by decreases to royalties and increases to realized derivative gains.
General & Administrative Expense Three months Ended Nine months Ended ---------------------------------------------------------------------------- $ millions, except Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, per BOE 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- G&A expense 12.3 9.6 6.5 31.3 21.8 Per BOE 2.27 2.64 1.76 2.43 2.06 ----------------------------------------------------------------------------
G&A expense in the third quarter of 2007 increased by 28% compared to the previous quarter mainly due to increases in labour costs, legal fees, building rent, and unit based compensation expense, partially offset by increases to overhead recoveries. These increases in G&A are due in large part to the merger with Shiningbank effective July 11, 2007. On a BOE basis, third quarter 2007 G&A decreased compared to the previous quarter due to the additional volumes added through the merger.
G&A expense and G&A expense per BOE for the three and nine months ended September 30, 2007 have increased from the same period in the prior years mainly due to increases in labour costs and building rent associated with the Shiningbank merger.
Included in G&A expense was $2.2 million and $5.6 million for the three and nine months ended September 30, 2007, respectively, relating to the Unit Appreciation Rights (UARs), granted under the LTIP. UARs in the Trust are similar to stock options in a corporation. The program rewards employees based on total Unitholder return, which is comprised of cumulative distributions on a reinvested basis plus growth in the market price of the Trust Units. No benefit accrues to the UARs until the Unitholders have first achieved a 5% total annual return from the time of grant. PrimeWest continues to pay for the exercise of UARs in Trust Units. Also included in G&A expense is $0.5 million and $1.1 million for the three and nine months ended September 30, 2007, respectively, related to the Special Employee Retention Plan (SERP) instituted on November 6, 2002 as part of the internalization transaction.
Interest Expense Three months Ended Nine months Ended ---------------------------------------------------------------------------- $ millions, except per Trust Unit Amounts and Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, Cost of Debt 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Interest expense 16.6 11.2 11.9 40.1 21.6 Period end net debt level (1) 1,024.0 619.2 772.4 1,024.0 772.4 Debt per Trust Unit 6.98 6.70 9.16 6.98 9.16 ---------------------------------------------------------------------------- Average cost of debt % 6.1% 6.2% 5.9% 6.0% 5.6% ---------------------------------------------------------------------------- (1) Excludes derivative and future income tax assets and liabilities included in current assets and liabilities.
Interest expense, representing interest on bank debt, the US Secured Notes, the U.K. Secured Notes and the Debentures increased in the third quarter of 2007 compared to the second quarter of 2007 and the third quarter of 2006 mainly due to the increase in the average net debt balance resulting from the Shiningbank merger.
Interest expense was higher for the nine months ended September 30, 2007 compared to the same period in 2006 due to higher average debt balances resulting from additional borrowing against the credit facility to finance the U.S. asset acquisition in the third quarter of 2006, the debt acquired in the Shiningbank merger, and to a higher average cost of debt.
The average cost of debt for the three and nine months ended September 30, 2007 was higher than the same periods in 2006, primarily due to the issuance of the Series III debentures on January 11, 2007, which bear a higher interest rate at 6.5%.
Foreign Exchange
The foreign exchange gain of $12.8 million and $31.9 million for the three and nine months ended September 30, 2007, respectively, resulted from the translation of the US Secured Notes, the U.K. Secured Notes and related interest payable into Canadian dollars.
Depletion, Depreciation and Amortization (DD&A) Three months Ended Nine months Ended ---------------------------------------------------------------------------- $ millions, except Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, per BOE 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- DD&A 120.9 64.1 59.1 251.9 166.5 Per BOE 22.29 17.50 15.90 19.62 15.79 ----------------------------------------------------------------------------
The DD&A rate for the three and nine months ended September 30, 2007 increased by 40% and 24%, respectively, when compared to the same periods in the prior year due to the impact of the Shiningbank merger in the third quarter of 2007.
Site Reclamation and Restoration Reserve
Since the inception of the Trust, PrimeWest has maintained a site reclamation fund to pay for future costs related to well abandonment and site clean up. The fund is used to pay for such costs as they are incurred. The 2007 contribution rate remains unchanged from 2006 at $0.50 per BOE produced. During the third quarter, a total of $4.4 million was contributed to the fund, including a $1.8 million additional contribution to accommodate an increase in expenditures during the period.
The abandonment and reclamation costs incurred in the third quarter of 2007 were $5.0 million, compared to $5.2 million for the same period in 2006, and $2.0 million for the previous quarter.
Income and Capital Taxes Three months Ended Nine months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, $ millions 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Income and capital taxes 1.5 1.3 0.5 3.0 (0.1) Future income tax recovery (37.1) (46.4) (21.2) (99.9) (44.8) ---------------------------------------------------------------------------- Total (35.6) (45.1) (20.7) (96.9) (44.9) ----------------------------------------------------------------------------
The increase in the future income tax recovery for the nine months ended September 30, 2007 compared to the same period in 2006 is due to amendments to the Income Tax Act which were enacted on June 22, 2007.
Prior to the changes in tax law, distributions paid to Unitholders, other than return of capital, were claimed as a deduction by the Trust in arriving at taxable income the result of which is the tax is eliminated at the Trust level and is paid by the Unitholders. The new Trust tax legislation results in a two-tiered structure whereby distributions are subject to a 31.5% tax at the Trust level and then Unitholders are subject to tax on the distribution as if it were a taxable dividend paid by a taxable Canadian corporation. These rules are effective for tax years beginning in 2011.
The enactment of the legislation triggered the recognition of future Canadian corporate income tax assets, with a corresponding impact on future Canadian corporate income tax recovery, based on temporary differences expected to reverse after the date that the taxation changes take effect. The $46.7 million recovery to future income tax recorded in the second quarter of 2007 as a result of this new legislation is based on estimated gross temporary differences of approximately $170.2 million that are expected to reverse after 2010, which, using an effective rate of 31.5%, resulted in a future tax asset of $46.7 million at June 30, 2007.
In connection with the enactment of the trust tax legislation, the Federal Government issued guidance with respect to limitations on future growth of the Trust. PrimeWest does not anticipate that the guidelines will impair its ability to annually replace or grow reserves in the next three years as the guidelines allow sufficient growth targets. Key attributes of the future growth constraints are as follows:
- Trusts may grow in size by 100% cumulatively for the period 2007 through 2010 as measured by the value of equity based on October 31, 2006 market capitalization. The cumulative limit started at 40% in 2007 and increases by 20% per year in 2008 through 2010.
- The merger of two income trusts will not be impacted by the growth limitations.
- The growth limits are not impacted by non-convertible debt-financed growth but rather focus solely on the issuance of equity to facilitate growth.
The Finance Minister delivered the Government's Economic Statement on October 30, 2007 which proposed corporate tax rate reductions over the next five years. The proposed corporate tax rate reductions will apply to the distributions on income trusts as of 2011.
Net Income Three months Ended Nine months Ended ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, $ millions 2007 2007 2006 2007 2006 ---------------------------------------------------------------------------- Net income 46.9 112.4 64.0 165.0 198.7 ----------------------------------------------------------------------------
Net income is an accounting measure impacted by both cash and non-cash items. The largest non-cash items impacting PrimeWest's net income are DD&A, the unrealized gain or loss on derivatives and future income taxes.
Net income for the three months ended September 30, 2007 of $46.9 million was lower than the previous quarter's net income of $112.4 million due to increases in DD&A of $56.8 million, increases to operating expense of $17.7 million, increases to the change in unrealized loss on derivatives of $16.7 million, increases to royalties of $16.2 million and a decrease to the income tax recovery of $9.3 million. Increases to oil and gas revenues of $53.9 million and increases to the realized gain on derivatives of $13.3 million partially offset the decreases to net income.
Net income for the three months ended September 30, 2007 was $17.1 million lower than the same period in 2006, mainly due to increases in DD&A of $61.8 million, increases to operating expense of $16.9 million, increases to the change in unrealized loss on derivatives of $15.0 million, and increases to royalties of $12.0 million. Increases to oil and gas revenues of $64.4 million, increases to the realized gain on derivatives of $6.5 million, increases to the unrealized foreign exchange gain of $14.7 million and a $15.9 million increase to the income tax recovery partially offset the decreases to net income.
Net income for the nine months ended September 30, 2007 of $165.0 million was $33.7 million lower than the same period in 2006 mainly due to increases in DD&A of $85.4 million, increases to the unrealized loss on derivatives of $60.1 million, increases to operating expense of $26.6 million, and an increase to interest expense of $15.5 million. Increases to oil and gas revenues of $91.7 million, the unrealized foreign exchange gain of $27.3 million and the increase in the future income tax recovery of $55.1 million partially offset the decreases to net income. The large increase in the future income tax recovery is due to the changes in the tax law related to trusts in the second quarter of 2007.
The increases in oil and gas revenues, royalties, operating expense and DD&A for the three and nine months ended September 30, 2007 are mainly attributable to the Shiningbank merger which occurred on July 11, 2007.
Liquidity & Capital Resources Long-Term Debt As at ---------------------------------------------------------------------------- Sep 30, Jun 30, Sep 30, $ millions 2007 2007 2006 ---------------------------------------------------------------------------- Long-term debt 1,053.1 648.5 544.9 (Working capital)/Deficit (1) (29.1) (29.3) 227.5 ---------------------------------------------------------------------------- Net debt 1,024.0 619.2 772.4 Market value of Trust Units and Exchangeable Shares outstanding (2)(3) 3,852.7 2,055.8 2,281.4 ---------------------------------------------------------------------------- Total capitalization 4,876.7 2,675.0 3,053.8 ---------------------------------------------------------------------------- Net debt as a % of total capitalization 21% 23% 25% ---------------------------------------------------------------------------- (1) Excludes derivative and future income tax assets and liabilities included in current assets or liabilities. (2) Based on September 30, 2007 Trust Unit closing price of $26.26 and September 15, 2007 exchange ratio of 0.70406:1. (3) Excludes the Debentures.
Long-term debt is comprised of senior bank credit facilities, the US Secured Notes, the U.K. Secured Notes and the Debentures of $630.4 million, $93.3 million, $128.0 million and $232.5 million, respectively. $31.1 million relating to the US Secured Notes was included in working capital as a current portion of long-term debt. In addition to amounts outstanding under the bank credit facility, PrimeWest has outstanding letters of credit in the amount of $4.3 million (2006 - $6.8 million).
Upon the completion of the merger with Shiningbank on July 11, 2007, PrimeWest entered into a new 3-year unsecured extendible revolving credit facility with a syndicate of chartered banks and other financial institutions. The credit facility provides for Cdn $1.1 billion of credit capacity for PrimeWest's operations in Canada and US $235 million of credit capacity for PrimeWest's operations in the US. With the consent of the lenders, the 3-year term of the credit facility may be extended on an annual basis for an additional year. Advances under the credit facility may be made by way of Canadian and US dollar denominated prime rate loans, Canadian dollar denominated bankers' acceptances, US dollar denominated LIBOR advances and letters of credit. These advances bear interest at the lenders' borrowing costs plus a stamping fee, or the applicable prime rate plus a margin. PrimeWest is required under the credit facility to maintain certain financial covenants.
On January 11, 2007, PrimeWest issued $200 million of Series III Debentures for net proceeds of $192.0 million. The Debentures bear interest at 6.5% payable semi-annually at January 31 and July 31 commencing July 31, 2007. The Debentures are convertible at any time at the option of the debenture holder into Trust Units at a conversion price of $26.25 per Trust Unit prior to maturity on January 31, 2012. The Debentures may be redeemed in whole or in part at the option of the Trust at a price of $1,050 per Debenture after February 1, 2010, and on or before January 31, 2011, and at a price of $1,025 per Debenture after February 1, 2011, and on or before January 31, 2012. On redemption or maturity the Trust may opt to satisfy its obligations to repay the principal by issuing Trust Units.
At September 30, 2007, PrimeWest's net debt to annualized third quarter funds flow from operations was approximately 2.1 times compared to 1.5 times annualized second quarter 2007 funds flow at June 30, 2007.
Unitholders' Equity
At September 30, 2007, the Trust had 145,901,890 Trust Units outstanding. In addition, PrimeWest had 1,150,406 Exchangeable Shares outstanding that are exchangeable into a total of 809,955 Trust Units using the September 30, 2007, exchange ratio of 0.70406:1.
On January 11, 2007, PrimeWest issued 6,420,000 Trust Units for net proceeds of $142.4 million.
On July 11, 2007 PrimeWest merged with Shiningbank Energy Income Fund. Pursuant to the merger each trust unit of Shiningbank was exchanged for 0.62 of a PrimeWest Trust Unit resulting in the issuance of 53,647,473 Trust Units.
The DRIP gives Canadian and US Unitholders the opportunity to reinvest their monthly distributions at a 5% discount to the volume-weighted average market price of the Trust Units. As an alternative to the DRIP component of the Plan, the PREP allows eligible Canadian Unitholders to elect to receive a premium cash distribution of up to 102% of the cash that the Unitholder would otherwise have received on the distribution date, subject to proration in certain events. The OTUPP gives Canadian Unitholders an opportunity to purchase additional Trust Units directly from PrimeWest at the same 5% discount. The DRIP and PREP components are mutually exclusive. Participation in the OTUPP requires enrolment in either the DRIP or PREP. During the nine months ended September 30, 2007, PrimeWest issued 1,032,727 Trust Units under the DRIP for $21.6 million, 873,932 Trust Units for $18.5 million under the PREP and 426,950 Trust Units for $9.0 million under the OTUPP.
These plan components benefit Unitholders by offering alternatives to maximize their investment in PrimeWest, while providing the Trust with a relatively inexpensive method of raising additional capital. Proceeds from these plans are used for debt reduction and to help fund ongoing capital development programs.
On September 24, 2007, PrimeWest announced that it has suspended the operation of its DRIP, OTUPP and PREP with respect to any distribution paid on the Trust Units after October 15, 2007.
Exchangeable Shares
Exchangeable shares were issued in connection with certain acquisitions and as part of PrimeWest's management internalization transaction. Exchangeable shares continue to be issued to certain Executive Officers pursuant to a SERP which was instituted as part of the management internalization transaction.
The Exchangeable Shares do not receive cash distributions. In lieu of receiving distributions, the number of Trust Units that the exchangeable shareholder will receive upon exchange increases each month based on the distribution amount divided by the market price of the Trust Units on the 15th day of that month.
At September 30, 2007, there were 1,150,406 Exchangeable Shares outstanding. The exchange ratio on these shares was 0.70406:1 Trust Units for each Exchangeable Share as at September 30, 2007. For purposes of calculating basic per Trust Unit amounts, it is assumed that the Exchangeable Shares have been exchanged into Trust Units at the current exchange ratio.
Cash Distributions
Cash distributions to Unitholders are at the discretion of the Board of Directors and can fluctuate depending on the cash flow generated from operations and other factors. The cash flow available for distribution is dependent upon many factors including commodity prices, production levels, debt levels, capital spending requirements, and factors in the overall industry environment.
The Board of Directors targets a long-term distribution payout ratio that is a percentage of cash flow from operations. However, the actual distribution payout ratio may vary from such targets due to fluctuations in commodity prices and their impact on cash flow forecasts, as well as other factors. The annual distribution payout ratio is targeted to be approximately 60% - 75% of funds flow from operations. In the third quarter of 2007, cash distributions totalled $108.9 million, or $0.75 per Trust Unit, representing a payout ratio of 84% of funds flow from operations. The 2007 year to date payout ratio was approximately 77%.
Distribution payments to US Unitholders are subject to a 15% Canadian withholding tax, which is deducted from the entire distribution amount prior to deposit into Unitholder accounts.
The Arrangement Agreement with TAQA permits PrimeWest to maintain its current monthly distribution at an amount not greater than C$0.25 per Unit payable in each of the months of October and November 2007. Therefore, if the effective date of the Arrangement occurs in November, the final distribution to Unitholders will be paid on November 15, 2007. However, if the Unitholder meeting is held on or before November 30, 2007 and the effective date of the Arrangement is delayed beyond the third business day of the following month, the Arrangement Agreement permits PrimeWest to continue to pay monthly distributions. If PrimeWest is permitted to pay distributions after November, the distribution amount will be set at the discretion of the Board of Directors of PrimeWest but will not exceed $0.25 per Trust Unit per month.
Future Accounting Changes
The CICA has issued the following accounting standards which will be effective January 1, 2008: Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 1535 "Capital Disclosures."
These new accounting standards will require the Trust to provide additional disclosures relating to its financial instruments, including hedging instruments, and the Trust's capital. Section 3863 does not change the presentation guidance provided in Section 3861 "Financial Instruments - Disclosure and Presentation" which it replaces. It is not anticipated that the adoption of these new accounting standards will impact the amounts reported in the Trust's financial statements as they primarily relate to disclosure.
PrimeWest is not aware of any other upcoming accounting pronouncements that would impact the financial statements.
Business Risks
PrimeWest's operations are affected by a number of underlying risks, both internal and external to the Trust. These risks are similar to those affecting others in both the conventional oil and gas royalty trust sector and the conventional oil and gas producers sector. The Trust's financial position, results of operations, and cash available for distribution to Unitholders are directly impacted by these factors. These factors are discussed below under two broad categories - "Commodity Price, Foreign Exchange and Interest Rate Risk" and "Operational and Other Business Risks." For additional information on Business Risks, including Risks Related to the Trust Structure and the Ownership of Trust Units, see PrimeWest's most recently filed Annual Information Form.
Commodity Price, Foreign Exchange, and Interest Rate Risk
The two most important factors affecting the level of cash available for distribution to Unitholders are the level of production achieved by PrimeWest and the price received for its products. These prices are influenced in varying degrees by factors outside the Trust's control. Some of these factors include:
- World market forces, specifically the actions of OPEC and other large crude oil producing countries including Russia and their implications on the supply of crude oil;
- World and North American economic conditions which influence the demand for both crude oil and natural gas and the level of interest rates set by the governments of Canada and the US;
- Weather conditions that influence the demand for natural gas and heating oil;
- The Canadian/US dollar exchange rate that affects the price received for crude oil, as the price of crude oil is referenced in US dollars;
- Transportation availability and costs; and
- Price differentials among World and North American markets based on transportation costs to major markets and quality of production.
To mitigate these risks, PrimeWest has an active hedging program in place based on an established set of criteria that has been approved by the Board of Directors. The results of the hedging program are reviewed against these criteria and the results are 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 2007 approximately 17% of natural gas production was sold to aggregators and 83% of production was sold into the Alberta and British Columbia short-term or export long-term markets.
The contracts that PrimeWest has with aggregators vary in length. They represent a blend of domestic and US markets and fixed and floating prices designed to provide price diversification to our revenue stream.
The primary objective of our commodity risk management program is to reduce the volatility of our cash distributions, to lock in the economics on major acquisitions and to protect our capital structure when commodity prices cycle downwards. In the third quarter of 2007, PrimeWest realized a $14.8 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 for distribution to Unitholders. These risks, and the manner in which PrimeWest seeks to mitigate these risks include, but are not limited to:
---------------------------------------------------------------------------- Risk We Mitigate By ---------------------------------------------------------------------------- Production Risk associated with the production Performing regular and proactive of oil and gas - includes well protective well, facility and operations, processing and the pipeline maintenance supported by physical delivery of commodities to telemetry, physical inspection and market. diagnostic tools. ---------------------------------------------------------------------------- Commodity Price Fluctuations in natural gas, crude See the "Financial Derivatives" oil and natural gas liquids prices. section in this quarterly report. ---------------------------------------------------------------------------- Transportation Market risk related to the Diversifying the transportation availability of transportation to systems on which we rely to get our market and potential disruption in product to market. delivery systems. ---------------------------------------------------------------------------- Natural Decline Development risk associated with Diversifying our capital spending capital enhancement activities program over a large number of undertaken - the risk that capital projects so that large amounts of spending on activities such as capital are not risked on any one drilling, well completions, well activity. We also have a highly workovers and other capital skilled technical team of activities will not result in geologists, geophysicists and reserve additions or in quantities engineers working to apply the sufficient to replace annual latest technology in planning and production declines. executing capital programs. Capital is spent only after strict economic criteria for production and reserve additions are assessed. ---------------------------------------------------------------------------- Acquisitions Acquisition risk associated with Continually scanning the acquiring producing properties at marketplace for opportunities to low cost to renew our inventory of acquire assets. Our technical assets. acquisition specialists evaluate potential corporate or property acquisitions and identify areas for value enhancement through operational efficiencies or capital investment. All prospects are subjected to rigorous economic review against established acquisition and economic hurdle rates. In some cases we may also hedge commodity prices to protect the acquisition economics in the near term period. ---------------------------------------------------------------------------- Reserves Reserve risk in respect of the Contracting our reserves evaluation quantity and quality of recoverable to a reputable third party reserves. consultant, GLJ Petroleum Consultants Ltd (GLJ). The Operations and Reserves Committee of the Board of Directors and PrimeWest review the work and independence of GLJ. Our strategy is to invest in mature, longer life properties having a higher proved producing component where the reserve risk is generally lower and cash flows are more stable and predictable. ---------------------------------------------------------------------------- Environmental, Health and Safety Establishing and adhering to strict (EH&S) guidelines for EH&S, including Environmental, health and safety training, proper reporting of risks associated with oil and gas incidents, supervision and properties and facilities. awareness. PrimeWest has active community involvement in field locations, including regular meetings with stakeholders in the area. PrimeWest carries adequate insurance to cover property losses, liability and business interruption. These risks are reviewed regularly by the Operations and Reserves Committee of the Board of Directors. ---------------------------------------------------------------------------- Regulation, Tax and Royalties Keeping informed of proposed Changes in government regulations, changes in regulations and laws to including reporting requirements, properly respond to and plan for income tax laws, operating the effects that these changes may practices, environmental protection have on our operations. requirements and royalty rates. ---------------------------------------------------------------------------- Historical Liability to Unitholders On July 1, 2004, the Income Trusts is Uncertain Liability Act (Alberta) was Because of uncertainties in the law proclaimed in force, creating a prior to July 1, 2004, relating to statutory limitation on the investments in trusts, there is a liability of Unitholders of Alberta risk that a Unitholder could be income trusts such as PrimeWest. held personally liable for The legislation provides that a obligations of the Trust. Unitholder is not, as beneficiary, liable for any act, default, obligation or liability of the Trust that arises after July 1, 2004. Similar legislation was proclaimed in force in Ontario in December of 2004. ---------------------------------------------------------------------------- CONSOLIDATED BALANCE SHEETS ---------------------------------------------------------------------------- Sep 30, Dec 31, ($ millions) (unaudited) 2007 2006 ---------------------------------------------------------------------------- ASSETS Current Assets Cash and cash equivalents $ 117.5 $ 22.0 Accounts receivable 121.4 104.5 Derivative assets (note 7) 26.9 23.5 Future income taxes 1.9 2.3 Prepaid expenses 25.9 19.9 ---------------------------------------------------------------------------- 293.6 172.2 Cash reserved for site restoration and reclamation - 2.2 Other assets and deferred charges (note 2) 1.1 7.4 Derivative assets (note 7) 1.7 5.3 Future income taxes 61.9 - Property, plant and equipment 3,835.2 2,332.9 Goodwill 318.5 68.5 ---------------------------------------------------------------------------- $ 4,512.0 $ 2,588.5 ---------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current Liabilities Accounts payable and accrued liabilities $ 176.7 $ 143.3 Current portion of long-term debt (note 5) 31.1 186.4 Future income taxes 8.1 8.7 Derivative liabilities (note 7) 7.0 - Accrued distributions to Unitholders 27.9 18.1 ---------------------------------------------------------------------------- 250.8 356.5 Long-term debt (note 5) 1,053.1 619.4 Derivative liabilities (note 7) 11.3 - Future income taxes 362.4 153.9 Asset retirement obligation (note 4) 127.8 91.5 ---------------------------------------------------------------------------- 1,805.4 1,221.3 UNITHOLDERS' EQUITY Net capital contributions (note 6) 3,820.4 2,391.2 Capital issued but not distributed 8.5 2.7 Convertible Unsecured Subordinated Debentures 8.7 1.2 Contributed surplus (note 8) 16.5 11.9 Accumulated other comprehensive (loss)/income (note 2) (14.5) 6.2 Deficit (note 9) (1,133.0) (1,046.0) ---------------------------------------------------------------------------- 2,706.6 1,367.2 ---------------------------------------------------------------------------- $ 4,512.0 $ 2,588.5 ---------------------------------------------------------------------------- See notes to interim consolidated financial statements. CONSOLIDATED STATEMENTS OF CASH FLOW Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Sep 30, Sep 30, Sep 30, ($ millions) (unaudited) 2007 2006 2007 2006 ---------------------------------------------------------------------------- OPERATING ACTIVITIES Net income for the period $ 46.9 $ 64.0 $ 165.0 $ 198.7 Add/(deduct) items not involving cash from operations: Depletion, depreciation and amortization 120.9 59.1 251.9 166.5 Non-cash general and administrative 2.7 1.4 6.7 4.4 Non-cash foreign exchange gain (12.8) 1.9 (31.9) (4.9) Unrealized loss/(gain) on derivatives 5.3 (9.7) 25.3 (34.8) Future income tax recovery (37.1) (21.2) (99.9) (44.8) Accretion of asset retirement obligation 1.5 0.7 4.6 2.0 Other non-cash items 0.7 0.4 1.6 1.3 Expenditures on site restoration and reclamation (5.0) (5.2) (10.7) (8.9) ---------------------------------------------------------------------------- Funds flow from operations $ 123.1 $ 91.4 $ 312.6 $ 279.5 Change in non-cash working capital (5.6) (4.8) (7.5) 21.0 ---------------------------------------------------------------------------- $ 117.5 $ 86.6 $ 305.1 $ 300.5 ---------------------------------------------------------------------------- FINANCING ACTIVITIES Proceeds from issue of Trust Units (net of costs) 2.5 21.9 151.3 31.2 Proceeds from issue of Debentures - - 200.0 - Increase/(decrease) in Senior Secured Notes 5.3 - (29.1) 130.7 Net cash distributions to Unitholders (85.6) (64.1) (198.8) (210.0) (Decrease)/increase in bank credit facilities (25.4) 296.2 (267.5) 266.2 Increase in deferred charges - - - (0.7) Change in non-cash working capital 7.4 3.2 14.3 (3.4) ---------------------------------------------------------------------------- $ (95.8) $ 257.2 $ (129.8) $ 214.0 ---------------------------------------------------------------------------- INVESTING ACTIVITIES Expenditures on property, plant and equipment (63.4) (76.7) (169.6) (206.7) Acquisition of property, plant and equipment (14.9) (334.5) (27.2) (369.1) Proceeds on disposal of property, plant and equipment 58.8 0.2 106.4 3.4 Decrease in cash reserved for future site reclamation 0.4 3.4 2.2 3.6 Change in non-cash working capital 19.3 22.2 8.4 33.1 ---------------------------------------------------------------------------- $ 0.2 $ (385.4) $ (79.8) $ (535.7) ---------------------------------------------------------------------------- Increase/(decrease) in cash and cash equivalents for the period 21.9 (41.6) 95.5 (21.2) Cash and cash equivalents, beginning of period 95.6 57.2 22.0 36.8 ---------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 117.5 $ 15.6 $ 117.5 $ 15.6 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Cash interest paid $ 17.5 $ 4.3 $ 33.3 $ 13.8 ---------------------------------------------------------------------------- Cash taxes paid $ 0.1 $ 0.1 $ 0.7 $ 1.2 ---------------------------------------------------------------------------- See notes to interim consolidated financial statements. CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- ($millions, except per Trust Unit amounts) Sep 30, Sep 30, Sep 30, Sep 30, (unaudited) 2007 2006 2007 2006 ---------------------------------------------------------------------------- REVENUES Sales of crude oil, natural gas and natural gas liquids $ 240.4 $ 176.0 $ 616.6 $ 524.9 Crown and other royalties (46.5) (34.5) (116.7) (111.0) Realized gain on derivatives 14.9 8.4 22.4 12.8 Change in unrealized (loss)/gain on derivatives (5.3) 9.7 (25.3) 34.8 Other income 1.2 1.1 7.0 4.1 ---------------------------------------------------------------------------- $ 204.7 $ 160.7 $ 504.0 $ 465.6 ---------------------------------------------------------------------------- EXPENSES Operating 52.3 35.4 125.9 99.3 Transportation 2.6 1.9 6.3 5.5 General and administrative 12.3 6.5 31.3 21.8 Interest 16.6 11.9 40.1 21.6 Debt issue costs (note 2) - - 8.0 - Depletion, depreciation and amortization 120.9 59.1 251.9 166.5 Accretion of asset retirement obligation (note 4) 1.5 0.7 4.6 2.0 Foreign exchange (gain)/loss (12.8) 1.9 (32.2) (4.9) ---------------------------------------------------------------------------- $ 193.4 $ 117.4 $ 435.9 $ 311.8 ---------------------------------------------------------------------------- Income before taxes for the period $ 11.3 $ 43.3 $ 68.1 $ 153.8 ---------------------------------------------------------------------------- Income and capital taxes 1.5 0.5 3.0 (0.1) Future income tax recovery (note 11) (37.1) (21.2) (99.9) (44.8) ---------------------------------------------------------------------------- (35.6) (20.7) (96.9) (44.9) ---------------------------------------------------------------------------- Net income for the period $ 46.9 $ 64.0 $ 165.0 $ 198.7 Other comprehensive income Unrealized foreign exchange loss on translation of self-sustaining foreign operations (7.2) - (17.1) - Tax effect on unrealized foreign exchange loss on translation of self-sustaining foreign operations (0.1) - (3.6) - ---------------------------------------------------------------------------- Other comprehensive income (7.3) - (20.7) - ---------------------------------------------------------------------------- Comprehensive income $ 39.6 $ 64.0 $ 144.3 $ 198.7 ---------------------------------------------------------------------------- Net income per Trust Unit - basic (note 6) $ 0.34 $ 0.78 $ 1.54 $ 2.43 Net income per Trust Unit - diluted (note 6) $ 0.34 $ 0.76 $ 1.52 $ 2.39 ---------------------------------------------------------------------------- See notes to interim consolidated financial statements CONSOLIDATED STATEMENTS OF DEFICIT & ACCUMULATED COMPREHENSIVE INCOME Three Months Ended Nine Months Ended ---------------------------------------------------------------------------- Sep 30, Sep 30, Sep 30, Sep 30, ($ millions) (unaudited) 2007 2006 2007 2006 ---------------------------------------------------------------------------- Deficit, beginning of period $(1,071.1) $ (983.3) $(1,046.0) $ (948.5) Adoption of new financial instrument accounting standard (net of income tax recovery of $0.1 million) (note 2) - - (7.3) - Net income 46.9 64.0 165.0 198.7 Distributions paid or declared (108.8) (74.0) (244.7) (243.5) ---------------------------------------------------------------------------- Deficit, end of period $(1,133.0) $ (993.3) $(1,133.0) $ (993.3) ---------------------------------------------------------------------------- Accumulated other comprehensive income, beginning of period (7.2) - 6.2 - Other comprehensive income, net of tax (7.3) - (20.7) - ---------------------------------------------------------------------------- Accumulated other comprehensive income, end of period (14.5) - (14.5) - ---------------------------------------------------------------------------- Deficit and accumulated other comprehensive income $(1,147.5) $ (993.3) $(1,147.5) $ (993.3) ---------------------------------------------------------------------------- See notes to interim consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2007, all amounts (except per Trust Unit amounts) are expressed in millions of Canadian dollars unless otherwise indicated.
1. Significant Accounting Policies
These interim consolidated financial statements of PrimeWest Energy Trust (PrimeWest or the Trust) have been prepared in accordance with Canadian generally accepted accounting principles. The specific accounting principles used are described in the annual consolidated financial statements of the Trust appearing on pages 65 and 66 of the Trust's 2006 Annual Report, with the exception of policies disclosed in note 2, and should be read in conjunction with these interim financial statements.
2. Changes in Accounting Policies
Financial Instruments, Hedging Activities and Comprehensive Income
Effective January 1, 2007, the Trust adopted CICA Handbook section 3855, "Financial Instruments - Recognition and Measurement" and CICA Handbook section 3861, "Financial Instruments - Disclosure and Presentation." The Trust has adopted these sections prospectively and the comparative interim consolidated financial statements have not been restated for these accounting policy changes. Adoption of section 3855 allows for the cumulative effect of the change in accounting policy to be booked as an adjustment to accumulated deficit with no restatement of prior periods. At January 1, 2007, $7.2 million in financing charges net of income tax recovery of $0.1 million were written off to the deficit. At January 1, 2007, other assets and deferred charges on the balance sheet were reduced to $0.2 million.
Effective January 1, 2007, the Trust adopted CICA Handbook section 1530, "Comprehensive Income." The Trust has adopted this section retroactively and prior periods have been restated. At January 1, 2007, the change in accounting policy resulted in an increase to accumulated other comprehensive income of $6.2 million net of tax (2006 - nil) and a decrease and elimination of the cumulative translation account of $6.2 million (2006 - nil).
Financial Instruments
All financial instruments must initially be recognized at fair value on the balance sheet. The Trust has classified its financial instruments into the following categories: held for trading financial assets and financial liabilities, loans or receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses, other than impairment losses, on available for sale financial assets are recognized in other comprehensive income and are transferred to earnings when the asset is de-recognized. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method. Impairment losses are recorded in earnings when incurred.
Upon adoption and with any new financial instrument, an irrevocable election is available that allows entities to classify any financial asset or financial liability as held for trading, even if the financial instrument does not meet the criteria to designate it as held for trading. The Trust has not elected to classify any financial assets or financial liabilities as held for trading unless they meet the held for trading criteria. A held for trading financial instrument is not a loan or receivable and includes one of the following criteria:
- is a derivative, except for those derivatives that have been designated as effective hedging instruments;
- has been acquired or incurred principally for the purpose of selling or repurchasing in the near future; or
- is part of a portfolio of financial instruments that are managed together and for which there is evidence of a recent actual pattern of short-term profit taking.
For financial assets and financial liabilities that are not classified as held for trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are expensed to earnings as incurred.
Derivative Instruments and Hedging Activities
Derivative instruments are utilized by the Trust to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Trust's policy is not to utilize derivative instruments for speculative purposes. The Trust may choose to designate derivative instruments as hedges. To date, the Trust has not elected to apply hedge accounting.
All derivative instruments are recorded on the balance sheet at fair value. Freestanding derivative instruments are classified as held for trading financial instruments. Gains and losses on these instruments are recorded in the change in unrealized gains and losses on derivatives in the consolidated statement of income and comprehensive income in the period they occur.
The Trust enters into commodity price contracts to hedge anticipated sales of crude oil and natural gas production to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in realized gains and losses on derivatives when the contracts are settled.
The Trust enters into cross currency swap agreements to hedge its fixed interest rate and foreign currency exposures on foreign currency denominated long-term debt. Gains and losses from these contracts are recognized in realized gains and losses on derivatives as the related interest payments are made.
Fair values of the derivatives are based on quoted market prices where available. The fair values of swaps and forwards are based on forward market prices. If a forward price is not available for a commodity based forward, a forward price is estimated using an existing forward price adjusted for quality or location.
Embedded Derivatives
Derivatives embedded in a host contract are classified as embedded derivatives. These derivatives are required to be recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not classified as held for trading or designated at fair value. The Trust has selected January 1, 2004, as its transition date for accounting for any potential embedded derivatives.
Comprehensive Income
Comprehensive income consists of net income and other comprehensive income. Other comprehensive income comprises the change in the unrealized foreign exchange gain/loss on translation of financial statements of self-sustaining foreign operations. Amounts included in other comprehensive income are shown net of tax. Accumulated other comprehensive income is a new equity category comprised of the cumulative amounts of other comprehensive income.
Foreign Currency Translation
The Trust has US dollar operations, which are self-sustaining. The self-sustaining operations are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated using period end exchange rates with revenues and expenses translated using average rates for the period. Effective January 1, 2007, gains and losses arising on the translation of assets and liabilities are included in the comprehensive income account under Unitholder's equity.
Accounting Changes
Effective January 1, 2007, the Trust adopted the revised recommendations of CICA Handbook Section 1506, "Accounting Changes."
The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide reliable and more relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007.
Future Accounting Changes
The CICA has issued the following accounting standards which will be effective January 1, 2008: Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 1535 "Capital Disclosures."
These new accounting standards will require the Trust to provide additional disclosures relating to its financial instruments, including hedging instruments, and the Trust's capital. Section 3863 does not change the presentation guidance provided in Section 3861 "Financial Instruments - Disclosure and Presentation" which it replaces. It is not anticipated that the adoption of these new accounting standards will impact the amounts reported in the Trust's financial statements as they primarily relate to disclosure.
3. Acquisitions
On July 11, 2007, PrimeWest merged with Shiningbank Energy Income Fund. Pursuant to the merger each trust unit of Shiningbank Energy Income Fund was exchanged for 0.62 of a PrimeWest Trust Unit resulting in the issuance of 53,647,473 PrimeWest Trust Units. The transaction was accounted for as a business combination using the purchase price method with net assets acquired and consideration paid as follows:
Net Assets Acquired at Assigned Values Consideration Paid ---------------------------------------------------------------------------- ($ millions) ($ millions) ---------------------------------------------------------------------------- Petroleum and natural gas assets 1,729.7 Goodwill 250.0 Other assets 2.4 Derivative assets 6.8 Working capital 5.2 Long term debt (450.3) Asset retirement obligation (39.9) Issuance of PrimeWest Trust Units 1,236.6 Future income taxes (242.6) Costs associated with merger 24.7 ---------------------------------------------------------------------------- 1,261.3 1,261.3 ----------------------------------------------------------------------------
4. Asset Retirement Obligations
Management has estimated the future asset retirement obligation based on the Trust's net ownership interest in wells and facilities. This includes estimated costs to dismantle, remove, reclaim and abandon the wells and facilities and the estimated time period during which these costs will be incurred in the future.
The following table reconciles the asset retirement obligation associated with the retirement of oil and gas properties: ---------------------------------------------------------------------------- Asset Retirement Obligation $ millions ---------------------------------------------------------------------------- Asset Retirement Obligation, December 31, 2006 91.5 Liabilities acquired due to merger 39.9 Liabilities incurred 7.9 Liabilities settled (10.7) Assets sold (5.4) Accretion expense 4.6 ---------------------------------------------------------------------------- Asset Retirement Obligation, September 30, 2007 127.8 ----------------------------------------------------------------------------
As at September 30, 2007, the undiscounted amount of estimated cash flows required to settle the obligation is $582.7 million. The estimated cash flow has been discounted using a credit-adjusted risk free rate of 6.8% and an inflation rate of 2.0%. Although the expected period until settlement ranges from a minimum of one year to a maximum of 50 years, the expectation is that costs will be paid over an average of 31 years.
Long-Term Debt
---------------------------------------------------------------------------- Sep 30, Dec 31, Sep 30, Dec 31, Sep 30, Dec 31, Maturity 2007 2006 2007 2006 2007 2006 ---------------------------------------------------------------------------- Canadian Dollar US Dollar Pounds Amounts Denominated Sterling ($ millions) ($ millions) (millions) Bank credit facilities 630.4 477.3 207.0 202.0 - - 7.5% debentures 2009 24.0 24.0 - - - - US secured notes 2010 93.3 145.7 93.8 125.0 - - 7.75% debentures 2011 15.0 15.0 - - - - 6.5% debentures 2012 193.5 - - - - - U.K. secured notes 2016 128.0 143.8 - - 63.0 63.0 ---------------------------------------------------------------------------- Total debt 1,084.2 805.8 300.8 327.0 63.0 63.0 ---------------------------------- Current portion of long-term debt 31.1 186.4 ---------------------------------------- Total of long-term debt 1,053.1 619.4 ----------------------------------------
On July 11, 2007, PrimeWest entered into a new 3-year unsecured extendible revolving credit facility with a syndicate of chartered banks and other financial institutions. The credit facility provides for Cdn $1.1 billion of credit capacity for PrimeWest's operations in Canada and US $235 million of credit capacity for PrimeWest's operations in the US. With the consent of the lenders, the 3-year term of the credit facility may be extended on an annual basis for an additional one year term. Advances under the credit facility may be made by way of Canadian and US dollar denominated prime rate loans, Canadian dollar denominated bankers' acceptances, US dollar denominated LIBOR advances and letters of credit. These advances bear interest at the lenders' borrowing costs plus a stamping fee, or the applicable prime rate plus a margin. PrimeWest is required under the credit facility to maintain certain financial covenants.
On January 11, 2007, PrimeWest issued $200 million of Series III Convertible Unsecured Debentures for net proceeds of $192.0 million. The debt issue costs of $8.0 million were expensed to earnings. The Debentures bear interest at 6.5% payable semi-annually at January 31 and July 31 commencing July 31, 2007. The Debentures are convertible at any time at the option of the debenture holder into PrimeWest Trust Units at a conversion price of $26.25 per Trust Unit prior to maturity on January 31, 2012. The Debentures may be redeemed in whole or in part at the option of the Trust at a price of $1,050 per Debenture after February 1, 2010, and on or before January 31, 2011, and at a price of $1,025 per Debenture after February 1, 2011, and on or before January 31, 2012. On redemption or maturity the Trust may opt to satisfy its obligation to repay the principal by issuing Trust Units.
The Series III Convertible Debentures are presented on the balance sheet in their debt and equity components. The debt component represents the discounted present value of the semi-annual interest obligations and the principal payment due at maturity, using the rate of the interest that would have been applicable to a non-convertible debt instrument of comparable term and risk at the date of issue. The debt component increases over the term of the debenture to the full fair value of the outstanding debenture at maturity. The difference is reflected as accretion expense on the income statement. The equity component is presented in Unitholders' Equity on the balance sheet. The equity component represents the value ascribed to the conversion right which remains a fixed amount over the term of the debenture. Upon conversion of the debenture into Trust Units, a proportionate amount of both the debt and equity components are transferred to Unitholders' capital.
The current portion of long-term debt includes $31.1 million relating to the US Secured Notes payable on May 7, 2008.
5. Unitholders' Equity The authorized capital of the Trust consists of an unlimited number of Trust Units. ---------------------------------------------------------------------------- Trust Units Number of Units $ millions ---------------------------------------------------------------------------- Balance, December 31, 2006 83,256,610 2,378.9 Issued pursuant to equity offering 6,420,000 142.4 Issued pursuant to merger with Shiningbank 53,647,473 1,236.5 Issued pursuant to Distribution Reinvestment Plan 1,032,727 21.6 Issued pursuant to Premium Distribution Plan 873,932 18.5 Issued pursuant to Optional Trust Unit Purchase Plan 426,950 9.0 Issued pursuant to Long-Term Incentive Plan 226,985 1.0 Conversion of Convertible Unsecured Subordinated Debentures 9,312 0.2 Issued pursuant to exchange of Exchangeable Shares 7,895 0.1 Issued pursuant to Consolidation/Fractional Units 6 - ---------------------------------------------------------------------------- Balance, September 30, 2007 145,901,890 3,808.2 ----------------------------------------------------------------------------
The weighted average number of Trust Units and Exchangeable Shares outstanding for the three months ended September 30, 2007 was 138,036,123 (2006 - 82,365,441). For purposes of calculating diluted net income per Trust Unit for the three months ended September 30, 2007, 1,065,058 Trust Units issueable pursuant to the Long-Term Incentive Plan (LTIP) were added to the weighted average number. The diluted net income per Trust Unit calculation for the three months ended September 30, 2007 does not include 9,066,122 Trust Units issueable pursuant to the conversion of the Debentures as the impact on net income per Trust Unit was anti-dilutive. For the purposes of calculating diluted net income per Trust Unit for the three months ended September 30, 2006, 584,583 Trust Units issueable pursuant to the conversion of the Debentures and 941,431 Trust Units issueable pursuant to the LTIP were added to the weighted average numbers.
The weighted average number of Trust Units and Exchangeable Shares outstanding for the nine months ended September 30, 2007 was 107,180,698 (2006 - 81,793,030). For the purposes of calculating diluted net income per Trust Unit for the nine months ended September 30, 2007, 1,065,058 (2006 - 913,460) Trust Units issueable pursuant to the LTIP and 9,066,942 (2006 - 677,386) Trust Units issueable pursuant to the conversion of the Debentures were added to the weighted average number.
On January 11, 2007, PrimeWest issued 6,420,000 Trust Units at a price of $23.35 per Trust Unit for net proceeds of $142.4 million.
On July 11, 2007 PrimeWest merged with Shiningbank Energy Income Fund. Shiningbank Trust Units were exchanged for 0.62 of a PrimeWest Trust Unit resulting in the issuance of 53,647,473 Trust Units.
Exchangeable Shares
The Exchangeable Shares are exchangeable into Trust Units at any time up to March 29, 2015 based on an exchange ratio that adjusts each time the Trust makes a distribution to its Unitholders. The exchange ratio, which was 1:1 on the date that the Exchangeable Shares were first issued, is based on the total monthly distribution, divided by the closing unit price on the distribution payment date. The exchange ratio effective September 15, 2007, was 0.70406:1 which is equivalent to 809,955 Trust Units.
---------------------------------------------------------------------------- Exchangeable Shares Number of Shares $ millions ---------------------------------------------------------------------------- Balance, December 31, 2006 1,161,864 12.3 Exchanged for Trust Units (11,458) (0.1) ---------------------------------------------------------------------------- Balance, September 30, 2007 1,150,406 12.2 ----------------------------------------------------------------------------
6. Financial Instruments and Risk Management
The Trust's financial instruments presented on the balance sheet consist of cash, accounts receivable, accounts payable and accrued liabilities, accrued distributions to Unitholders, derivative assets, derivative liabilities and long-term debt. Other than the long-term debt, the fair market value of these financial instruments approximate their carrying value due to the short term to maturity and the risk management contacts are presented at fair value on the balance sheet. The fair value of long-term debt is disclosed in the following table.
Sep 30, Sep 30, Sep 30, Dec 31, Dec 31, 2007 2007 2007 2006 2006 ---------------------------------------------------------------------------- Face Carrying(1) Fair Face Carrying(1) value value value value value Bank credit facilities 424.5 424.5 424.5 242.0 242.0 7.5% debentures 23.7 24.0 24.0 24.0 24.0 7.75% debentures 14.7 15.0 14.9 15.0 15.0 6.5% debentures 199.8 193.5 204.3 - - ---------------------------------------------------------------------------- Total Cdn $ denominated debt 662.7 657.0 667.7 281.0 281.0 ---------------------------------------------------------------------------- Bank credit facilities 207.0 207.0 207.0 202.0 202.0 US $ denominated secured notes 93.8 93.8 91.0 125.0 125.0 ---------------------------------------------------------------------------- Total US $ denominated debt 300.8 300.8 298.0 327.0 327.0 ---------------------------------------------------------------------------- Pounds Sterling denominated debt - U.K. secured notes 63.0 63.0 59.8 63.0 63.0 ---------------------------------------------------------------------------- (1) Excludes equity component.
7. Commodity Price Risk Management
PrimeWest generally sells its oil and natural gas under short-term market-based contacts. Derivative financial instruments, collars and swaps may be used to hedge the impact of oil and natural gas fluctuations.
Foreign Exchange Rate Risk
The Trust is exposed to fluctuations in the Canadian/US dollar exchange rate on the sale of commodities that are denominated in US dollars or directly influenced by US dollar benchmark prices. In addition, the Trust's 4.19% US Secured Notes are denominated in US dollars. The semi-annual interest payments and principal payments associated with the US Senior Notes can be impacted by movement in the Canadian/US dollar exchange rate. PrimeWest, through the use of a financial swap, has converted the U.K. Secured Notes from pounds sterling to Canadian dollar debt. This currency swap has fixed the aggregate principal value and annual interest payments on this Pounds Sterling 63.0 million debt at $130.7 million and $3.9 million, respectively.
Impact on Financial Statements
The commodity price risk financial instruments and currency swaps have been recorded at fair value on the balance sheet with the offset included in the unrealized gain or loss on derivatives on the income statement.
At September 30, 2007, $26.9 million was recorded as a current derivative asset comprised of $26.8 related to natural gas and $0.1 related to power. $1.7 million was recorded as a long-term derivative asset related to natural gas and $7.0 million was recorded as a current derivative liability related to crude oil. $11.3 million was recorded as a long-term derivative liability comprised of a $0.7 million unrealized loss on crude oil and a $10.6 million unrealized loss attributable to foreign exchange.
For the three months ended September 30, 2007, the change in the unrealized loss on the statement of income was $5.3 million comprised of a $5.9 million change in the gain related to natural gas, a $6.0 million change in the loss related to crude oil, a $0.1 million change in the gain related to power and a $5.3 million change in the loss related to foreign exchange. For the nine months ended September 30, 2007, the total change in unrealized loss on the income statement was $25.3 million comprised of a $13.6 million change in the loss related to crude oil, a $3.5 million change in the gain related to natural gas, a $0.1 million change in the gain related to power, and a $15.3 million change in the loss attributable to foreign exchange.
The financial impact on the settlement of contracts during the third quarter of 2007 recorded in realized derivative gain on the income statement was a $14.9 million gain comprised of a $15.4 million gain related to natural gas, a $0.6 million loss related to crude oil and a $0.1 million gain related to power. The financial impact of the settlement of contracts for the nine months ended September 30, 2007 was a $22.4 million realized derivative gain comprised of a $2.8 million gain related to crude oil, a $19.6 million gain related to natural gas, a $0.1 million gain related to power and a $0.1 million loss related to foreign exchange.
8. Contributed Surplus
Contributed surplus includes the accumulated unit-based compensation charge in respect of PrimeWest's unexercised Unit Appreciation Rights (UARs) granted under the LTIP on or after January 1, 2002. Upon exercise of the UARs and delivery of the Trust Units, the contributed surplus account is reduced and the amount is transferred to net capital contributions.
---------------------------------------------------------------------------- $ millions ---------------------------------------------------------------------------- Balance, December 31, 2006 11.9 General and administrative expense - unit appreciation rights 5.6 Unit Appreciation Rights exercised (1.0) ---------------------------------------------------------------------------- Balance, September 30, 2007 16.5 ---------------------------------------------------------------------------- 9. Deficit ---------------------------------------------------------------------------- ($ millions) Sep 30, 2007 Dec 31, 2006 ---------------------------------------------------------------------------- Accumulated income 666.6 512.1 Accumulated distributions paid or declared (1,794.9) (1,550.1) Accumulated dividends (8.0) (8.0) ---------------------------------------------------------------------------- (1,136.3) (1,046.0) ----------------------------------------------------------------------------
10. Long-Term Incentive Plan
PrimeWest recorded $2.2 million (2006 - $1.2 million) and $5.6 million (2006 - $3.2 million) in general and administrative expense related to the Long-Term Incentive Plan for the three and nine months ended September 30, 2007, respectively, using the fair value method of accounting.
PrimeWest used a binomial lattice pricing model to calculate the estimated fair value of outstanding UARs issued on or after January 1, 2002. The following assumptions were used to arrive at the estimated fair value:
---------------------------------------------------------------------------- Weighted Average Assumptions: Sep 30, 2007 Sep 30, 2006 ---------------------------------------------------------------------------- Risk-free interest rate 4.27% 4.17% Expected volatility in Trust Unit price 26.5% 22.5% Expected time until exercise 1.5 - 3.5 years 1.5 - 3.5 years Expected forfeiture rate 14.3% 13.9% Expected annual dividend yield zero zero ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Summary of Changes in Unit Appreciation Weighted Average Rights Number of UARs Strike Price ---------------------------------------------------------------------------- Balance outstanding at December 31, 2006 4,460,040 31.96 Granted 3,403,448 24.07 Forfeited (405,215) 30.86 Exercised (398,772) 27.94 ---------------------------------------------------------------------------- Balance outstanding at September 30, 2007 7,059.501 28.47 ----------------------------------------------------------------------------
11. Future Income Tax
On June 22, 2007, legislation was enacted that effectively imposes income tax for income trusts, including royalty trusts, for taxation years beginning in 2011. The enactment of this legislation triggered the recognition of future Canadian corporate income tax assets on all entities within the PrimeWest structure, with a corresponding impact on future Canadian corporate income tax recovery, based on temporary differences expected to reverse after the date that the taxation changes take effect. The $46.7 million recovery to future income tax recorded in the second quarter of 2007 as a result of this new legislation was based on estimated gross temporary differences of approximately $170.2 million that are expected to reverse after 2010, which, using an effective tax rate of 31.5%, resulted in a future tax asset of $46.7 million at June 30, 2007.
12. Contingent Liabilities
Pursuant to the September 24, 2007 Arrangement Agreement with 1350849 Alberta Ltd. and TAQA North Ltd., PrimeWest has agreed to pay to the Purchaser a termination fee of $75 million in certain circumstances, including the withdrawal by the Board of Directors of its recommendations with respect to the Arrangement, the execution of an agreement to proceed with, or the completion of, an alternative transaction in circumstances in which the Securityholders have not approved the Arrangement, the acceptance of a superior proposal or an unremedied material breach by PrimeWest of a representation, warranty or covenant contained in the Arrangement Agreement. In certain other and alternative circumstances, PrimeWest will become obligated to pay to the Purchaser an expense fee in the amount of $10 million.
13. Subsequent Event
a) On September 24, 2007 PrimeWest announced that it had entered into an arrangement agreement (the "Agreement") with 1350849 Alberta Ltd. ("Purchaser") and TAQA North Ltd., wholly-owned subsidiaries of the Abu Dhabi National Energy Company PJSC. The Agreement provides for the acquisition by the Purchaser of all of the issued and outstanding trust units of PrimeWest and all of the issued and outstanding exchangeable shares of PrimeWest Energy Inc. for a cash consideration of C$26.75 per Trust Unit pursuant to a plan of arrangement under the Business Corporations Act (Alberta) (the "Arrangement"). The cash consideration payable for the Exchangeable Shares will be calculated on the basis of the exchange ratio in effect at the time the transaction is completed.
The Arrangement is subject to a number of conditions including, but not limited to, court and regulatory approval and other conditions that are typical of transactions of this nature, in particular, the approval of at least 66 2/3% of the Trust Units, Exchangeable Shares and unit appreciation rights, voting together as a single class, represented in person or by proxy at the Special Meeting of Securityholders. Provided that the PrimeWest Securityholders approve the Arrangement at the Special Meeting, and that all of the other conditions to the completion of the Arrangement are satisfied, the earliest completion date for the transaction is anticipated to be November 23, 2007. The completion date may be later depending on regulatory approvals but in all cases shall be on or before January 31, 2008 or the Arrangement terminates, unless extended in accordance with the terms of the Arrangement Agreement.
b) On October 25, 2007 the Government of Alberta announced major proposed changes to the oil and gas royalty structure which are scheduled to take effect on January 1, 2009. A preliminary analysis indicates that PrimeWest's mature, gas weighted asset base will attract only marginally higher royalty rates when compared to the existing structure.
c) The Finance Minister delivered the Government's Economic Statement on October 30, 2007 which proposed corporate tax rate reductions over the next five years. The proposed corporate tax rate reductions will apply to the distributions on income trusts as of 2011.
TRADING PERFORMANCE ---------------------------------------------------------------------------- For the quarter ended Sep 30/07 Jun 30/07 Mar 31/06 Dec 31/06 Sep 30/06 ---------------------------------------------------------------------------- TSX Trust Unit Prices (C$ per Trust Unit) High 26.75 23.94 23.37 29.21 35.42 Low 19.46 22.12 19.98 20.87 27.33 Close 26.26 22.39 22.72 21.50 27.35 ---------------------------------------------------------------------------- Average daily traded volume 1,565,123 334,005 255,263 391,293 225,732 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- For the quarter ended Sep 30/07 Jun 30/07 Mar 31/06 Dec 31/06 Sep 30/06 ---------------------------------------------------------------------------- NYSE Trust Unit Prices (US$ per Trust Unit) High 26.97 22.47 20.26 25.94 31.29 Low 18.06 19.34 17.01 18.03 24.45 Close 26.41 21.03 19.69 18.47 24.64 ---------------------------------------------------------------------------- Average daily traded volume 1,279,957 478,381 450,593 796,677 441.508 ---------------------------------------------------------------------------- Number of Trust Units outstanding including Exchangeable Shares (thousands of Trust Units) 146,712 91,817 91,144 83,257 82,719 ---------------------------------------------------------------------------- Distribution paid per Trust Unit 0.75 0.75 0.75 0.75 0.90 ---------------------------------------------------------------------------- CORPORATE INFORMATION Board of Directors Corporate Offices Harold P. Milavsky, Chair (1,2) Suite 5100, 150 Sixth Avenue S.W. Barry E. Emes (1,2) Calgary, Alberta Canada T2P 3Y6 David M. Fitzpatrick (4) Tel: (403) 234-6600 Fax: (403) 699-7477 Robert B. Hodgins (1) Toll-Free: 1-877-968-7878 Harold N. Kvisle (3,4) Kent J. MacIntyre (3,4) W. Glen Russell, (3,4) Trust Units and Exchangeable Shares Warren D. Steckley (4) Toronto Stock Exchange (PWI.UN; PWX) Peter Valentine (1,2) The New York Stock Exchange (PWI) (1) Audit and Finance Committee Convertible Debentures (2) Governance Committee (3) Compensation Committee Toronto Stock Exchange (4) Operations and Reserves Committee Series I Debentures (PWI.DB.A) Series II Debentures (PWI.DB.B) Officers Series III Debentures (PWI.DB.C) Donald A. Garner President and Chief Executive Officer Registrar and Transfer Agent Ronald J. Ambrozy Vice President, Business Development Computershare Trust Company of Canada Toll-free in Canada: 1-800-564-6253 Douglas S. Fraser Vice President, Finance and Chief Financial Officer Timothy S. Granger Auditor Chief Operating Officer PricewaterhouseCoopers LLP Calgary, Alberta Gordon D. Haun Vice President, Legal and General Counsel Gregory D. Moore Vice President, Operations Engineering Consultants J. Lance Petersen GLJ Petroleum Consultants Ltd. Vice President, Land Calgary, Alberta R. Bruce Thornhill Vice President, Geosciences Legal Counsel Stikeman Elliott LLP Calgary, Alberta
Contacts: PrimeWest Energy Trust George Kesteven Manager Investor Relations (403) 699-7367 or Toll Free: 1-877-968-7878 PrimeWest Energy Trust Debbie Carver Investor Relations Advisor (403) 699-7464 or Toll Free: 1-877-968-7878 Email: investor@primewestenergy.com Website: www.primewestenergy.com