EXHIBIT 99.2
MANAGEMENT’S DISCUSSION
AND ANALYSIS
The following interim Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto of Canetic Resources Trust (“Canetic”, the “Trust”, “we”, “our” or “us”) for the year ended December 31, 2006, Canetic’s MD&A for the year ended December 31, 2006, and the unaudited Consolidated Financial Statements of Canetic and Notes thereto for the nine months ended September 30, 2007. This MD&A is dated November 8, 2007. The Consolidated Financial Statements have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). No update is provided where an item is not material or there has been no material change from discussions in our annual MD&A. This discussion provides management’s analysis of Canetic’s historical financial and operating results and provides estimates of Canetic’s future financial and operating performance based on information currently available. Actual results will vary from estimates and the variances may be material. You should be aware that historical results are not necessarily indicative of future performance. Readers are referred to the legal advisories regarding forward-looking information contained in the “Forward-Looking Statements” section of this MD&A.
All references are to Canadian dollars unless otherwise indicated. Natural gas volumes recorded in thousand cubic feet (“mcf”) are converted to barrels of oil equivalent (“boe”) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (“bbl”). BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: one (1) bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.
FORWARD-LOOKING STATEMENTS
Certain statements contained in this MD&A constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of applicable securities law. These statements relate to future events or future performances. All statements other than statements of historical fact may be forward-looking statements. Statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described can be profitably produced in the future.
The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "could", "should", "believe", "intend", "propose", "budget", and similar expressions are intended to identify forward-looking statements. 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 such forward-looking statements. We believe the expectations reflected in the forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements are not guarantees of future performance and should not be unduly relied upon. These statements speak only as of the date of this MD&A.
In particular, this MD&A contains forward-looking statements pertaining to the following: business strategies; production volumes; reserves volumes; drilling plans; expected outages and the impact thereof; operating and other costs and expenses; commodity prices; future cash distribution levels and taxability; capital spending including timing, allocation and amounts of capital expenditures and the sources of funding thereof; sources of funding operations and distributions and the sufficiency thereof; estimates of funds flow from operations; royalty rates; interest rates; asset retirement obligations; hedging and other risk management programs; debt levels, future tax treatment of income trusts such as the Trust and unitholders; the acquisition of Titan Exploration Ltd. and strategic business combination with Penn West Energy Trust and the benefits to be derived there from and the timing there of; income tax pools, and liquidity and financial capacity.
The forward-looking statements contained in this MD&A are based on a number of expectations and assumptions that may prove to be incorrect. In addition to other assumptions identified in this MD&A, assumptions have been made regarding, among other things: that the Trust will continue to conduct its operations in a manner consistent with past operations; the continuance of existing (and in certain circumstances, proposed) tax and royalty regimes; the general continuance of current industry conditions; the accuracy of the estimates of the Trust's reserves volumes; the ability of Canetic to obtain equipment, services and supplies in a timely manner to carry out our activities; the ability of Canetic to market oil and natural gas successfully; the timely receipt of required regulatory and other approvals; the ability of Canetic to obtain financing on acceptable terms; currency, exchange and interest rates; future oil and gas prices; the failure of Canetic to obtain the required approvals for mergers and acquisitions and future cost assumptions. No assurance can be given that these factors, expectations and assumptions will prove to be correct.
2007 THIRD QUARTER REPORT 1
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A: volatility in market prices for oil and natural gas; risks and liabilities inherent in oil and natural gas including operations, exploration, development, exploitation, production, marketing and transportation risks; uncertainties associated with estimating oil and natural gas 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; risks and uncertainties involving geology of oil and gas deposits; unanticipated operating results or production declines; fluctuations in foreign exchange, currency or interest rates, and stock market volatility; general economic conditions; changes in laws and regulations including but not limited to those pertaining to income tax, environmental and regulatory matters; changes in royalty rates including the implementation of “The New Royalty Framework” in Alberta; failure to realize the anticipated benefits of acquisitions; health, safety and environmental risks; and the other factors described in Canetic's public filings from time to time (including under "Risk Factors" in our Annual Information Form) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
The forward-looking statements contained in this MD&A are expressly qualified by the following cautionary statement: Canetic undertakes no obligation to publicly update or revise any forward-looking statements except as expressly required by applicable securities law.
NON-GAAP MEASURES
Throughout the MD&A certain supplemental financial measures that are not specifically determined in accordance with GAAP are used to assist in analyzing the operations of the Trust. In addition to the primary measures of net earnings (loss) and net earnings (loss) per unit and cash flows from operating activities determined in accordance with GAAP, we believe that certain measures not determined in accordance with GAAP assist the reader in assessing performance and understanding the Trusts results. These non-GAAP measures as presented do not have any standardized meaning prescribed by GAAP and therefore may not be comparable with calculations of similar measures for other companies or trusts. These measures should not be considered alternatives to net earnings (loss) and net earnings (loss) per unit or cash flows from operating activities as calculated in accordance with GAAP.
• | Funds flow from operations - defined as net earnings (loss) plus non-cash items before deducting changes in non-cash working capital and asset retirement costs incurred. We use this measure to analyze operating performance and leverage. This measure is an indicator of the Trust’s ability to generate funds flow in order to fund distributions, working capital, principal debt repayments and capital expenditures. Readers should refer to the “Funds Flow From Operations” section of the MD&A for a reconciliation of funds flow from operations to net earnings (loss). |
• | Net debt - defined as long-term debt and working capital excluding financial derivatives. This measure is used to analyze liquidity and capital resources in order to meet the Trusts’ financing needs to fund capital expenditures, acquisitions and short term funding needs. Readers should refer to the “Liquidity and Capital Resources” section of the MD&A for a reconciliation of net debt. |
• | Operating and cash netbacks - defined as revenue and expense items divided by production per boe per day. This measure is used throughout the Oil and Gas industry to analyze margin and cash flow on each boe of production. Readers should refer to the “Netbacks” section of the MD&A for the calculation of operating and cash netbacks. |
2 CANETIC RESOURCES TRUST
• | Total capitalization - defined as net debt including convertible debentures plus unitholders’ equity. Similar to net debt, this measure is an indictor of the Trust’s ability to analyze liquidity and capital resources in order to meet the Trust’s financing needs to fund capital expenditures, acquisitions and short term funding needs. This measure is an indicator of overall Trust leverage. Total capitalization is not intended to represent the total funds from equity and debt received by the Trust. Readers should refer to the “Liquidity and Capital Resources” section of the MD&A for a reconciliation of total capitalization. |
CURRENT AND COMPARATIVE PERIODS
The quarterly and annual financial and operating results for 2006 and 2007 have been influenced by two major acquisitions.
• | On January 5, 2006, Canetic was formed on the completion of the merger of Acclaim Energy Trust (“Acclaim”) and StarPoint Energy Trust (“StarPoint”). The transaction with StarPoint was accounted for as a purchase of StarPoint by Acclaim. Accordingly, the financial and operating results for the year ended December 31, 2006 include those of the StarPoint assets from the date of acquisition, January 5, 2006. At the time of the merger the StarPoint assets were producing approximately 35,000 boe per day. |
• | On August 31, 2006, we closed the Samson acquisition for approximately $900.0 million. At closing, the Samson assets were producing approximately 13,500 boe per day including 70.0 million cubic feet (“mmcf”) per day of natural gas. |
RECENT DEVELOPMENTS
CANETIC RESOURCES TRUST ENTERS INTO A COMBINATION AGREEMENT WITH PENN WEST ENERGY TRUST
On October 31, 2007, Canetic and Penn West Energy Trust (“Penn West”) announced that they had entered into a combination agreement (the “Combination Agreement”) that would provide for the strategic combination of Canetic and Penn West (the “Combined Trust”). The Combined Trust will be the largest conventional oil and gas trust in North America with an enterprise value of over C$15 billion and initial production of over 200,000 boe per day. The combined asset portfolio will include interests in a significant number of Western Canada’s highest quality conventional oil and natural gas pools and will also include a number of non-conventional growth opportunities including oil sands, coalbed methane, shale gas and enhanced oil recovery. At closing, this merger of assets and people will operate under the Penn West name and will be led by a management team and Board of Directors drawn from each of Canetic and Penn West.
Under the terms of the Combination Agreement, Canetic unitholders will receive 0.515 of a Penn West unit for each Canetic unit on a tax-deferred basis for Canadian and U.S. tax purposes. Immediately prior to the closing of the combination, a one-time special distribution of $0.09 per unit will be paid to Canetic unitholders. The special distribution is intended to keep Canetic unitholders whole, in cash distributions, for a period of six months.
Canetic unitholders will receive an aggregate value of C$15.84 per Canetic unit based on the closing price of Penn West units on the Toronto Stock Exchange (“TSX”) on October 30, 2007 which represents a premium of 7.1 percent to the closing price of Canetic units on the TSX on October 30, 2007. On completion of the combination, Penn West unitholders will own approximately 67 percent and Canetic unitholders will own approximately 33 percent of the Combined Trust. Penn West units will continue to be listed on both the TSX and the New York Stock Exchange (“NYSE”).
The combination is subject to stock exchange, court and regulatory approval, and the approval of at least 66 2/3 percent of the votes cast by Canetic unitholders at a Canetic unitholder meeting to be held to approve the combination in mid January 2008 with closing immediately thereafter. An Information Circular is expected to be mailed to unitholders of Canetic in after December 2007.
ACQUISITION OF TITAN EXPLORATION LTD.
On October 18, 2007, Canetic announced its agreement to acquire Titan Exploration Ltd. (“Titan”) pursuant to which Canetic will make an offer to acquire all of the issued and outstanding shares of Titan in exchange for 0.1917 of a Canetic unit for each Titan Class A Share and 0.6609 of a Canetic unit for each Titan Class B Share. The total transaction value is approximately $116.0 million including Titan’s net debt of approximately $17.5 million. It is expected that approximately 6.5 million Canetic units will be issued to effect the acquisition.
2007 THIRD QUARTER REPORT 3
The Board of Directors of Titan has unanimously agreed to support the offer and has unanimously resolved to recommend that all Titan shareholders tender their shares in acceptance of Canetic’s offer. Full details of the offer will be included in a take-over bid circular and related documents that are expected to be filed with securities regulators and mailed to all Titan shareholders on or before November 15, 2007.
Upon completion of the Titan acquisition, Canetic will acquire production of approximately 1,800 boe per day, weighted 63 percent to oil, and a Canetic estimated 7.3 million boe of proved plus probable reserves with a Reserve Life Index of approximately 11 years. More importantly, Canetic will also acquire over 49,000 gross (23,700 net) acres, in the Leitchville area of Southwest Saskatchewan, in close proximity to Canetic’s existing 45,100 gross (41,200 net) acres, to create a dominant position in the emerging and strategically significant Lower Shaunavon trend. Current Titan production in Southwest Saskatchewan exceeds 900 boe per day.
In addition to the production and lands in Southwest Saskatchewan, Canetic will also acquire approximately 900 boe per day of production located in the northern regions of Alberta and British Columbia. Approximately two-thirds of this production is located in the Peace River Arch region in close proximity to Canetic’s existing lands.
ALBERTA’S “NEW ROYALTY FRAMEWORK”
On October 25, 2007, the Province of Alberta announced changes to crude oil and natural gas royalty rates within the Province based on a report from the Alberta Royalty Review Board that was issued on September 18, 2007. “The New Royalty Framework” report released by the Provincial Government confirmed that royalty rates, beginning in 2009, will be based on a sliding scale formula sensitive to both price and production volumes. For the nine months ended September 30, 2007, approximately 50 percent of Canetic’s total royalty burden was paid to the Province of Alberta.
Certain details of the new regime have yet to be released by the Government and as a result the impact on Canetic is not entirely clear.
4 CANETIC RESOURCES TRUST
SELECTED HIGHLIGHTS
As At And For The Three Months Ended September 30 | As At And For The Nine Months Ended September 30 | |||||||||||||||||||||||
($millions except per unit amounts and operating information) | 2007 | 2006 | % change | 2007 | 2006 | % change | ||||||||||||||||||
FINANCIAL | ||||||||||||||||||||||||
Petroleum and natural gas sales | 346.1 | 368.5 | -6 | % | 1,084.7 | 1,060.1 | 2 | % | ||||||||||||||||
Funds flow from operations (1) | 181.6 | 200.3 | -9 | % | 564.0 | 580.1 | -3 | % | ||||||||||||||||
Per unit - basic | 0.80 | 0.95 | -17 | % | 2.48 | 2.91 | -15 | % | ||||||||||||||||
Per unit - diluted | 0.79 | 0.93 | -15 | % | 2.48 | 2.85 | -13 | % | ||||||||||||||||
Net earnings (loss) | 15.7 | 102.7 | -85 | % | (293.0 | ) | 244.7 | -220 | % | |||||||||||||||
Per unit - basic | 0.07 | 0.49 | -86 | % | (1.29 | ) | 1.23 | -205 | % | |||||||||||||||
Per unit - diluted | 0.07 | 0.48 | -86 | % | (1.29 | ) | 1.21 | -206 | % | |||||||||||||||
Cash distributions | 130.0 | 144.9 | -10 | % | 397.5 | 417.0 | -5 | % | ||||||||||||||||
Distributions declared per unit | 0.57 | 0.69 | -17 | % | 1.71 | 2.07 | -17 | % | ||||||||||||||||
Capital expenditures | ||||||||||||||||||||||||
Net development expenditures | 88.0 | 104.4 | -16 | % | 325.3 | 257.2 | 26 | % | ||||||||||||||||
Net capital expenditures | 101.5 | 1,078.4 | -91 | % | 303.7 | 3,773.0 | -92 | % | ||||||||||||||||
Total assets | 5,578.4 | 5,853.2 | -5 | % | 5,578.4 | 5,853.2 | -5 | % | ||||||||||||||||
Long-term debt | 1,374.0 | 1,223.0 | 12 | % | 1,374.0 | 1,223.0 | 12 | % | ||||||||||||||||
Net debt (1) | 1,404.2 | 1,254.4 | 12 | % | 1,404.2 | 1,254.4 | 12 | % | ||||||||||||||||
Unitholders' equity | 2,887.7 | 3,662.5 | -21 | % | 2,887.7 | 3,662.5 | -21 | % | ||||||||||||||||
Weighted average trust units outstanding (000s) | 228,328 | 210,226 | 9 | % | 227,389 | 199,640 | 14 | % | ||||||||||||||||
Trust units outstanding at period end (000s) | 230,108 | 224,530 | 2 | % | 230,108 | 224,530 | 2 | % | ||||||||||||||||
OPERATING | ||||||||||||||||||||||||
Production | ||||||||||||||||||||||||
Natural gas (mmcf/d) | 205.7 | 181.4 | 13 | % | 212.2 | 174.5 | 22 | % | ||||||||||||||||
Crude oil (bbl/d) | 34,578 | 38,314 | -10 | % | 35,636 | 37,765 | -6 | % | ||||||||||||||||
Natural gas liquids (bbl/d) | 5,711 | 5,925 | -4 | % | 6,426 | 5,577 | 15 | % | ||||||||||||||||
Crude oil and NGLs (bbl/d) | 40,289 | 44,239 | -9 | % | 42,062 | 43,342 | -3 | % | ||||||||||||||||
Barrels of oil equivalent(boe/d) @ 6 mcf:1 bbl | 74,572 | 74,475 | 0 | % | 77,435 | 72,431 | 7 | % | ||||||||||||||||
Average prices | ||||||||||||||||||||||||
Natural gas ($/mcf) | 5.33 | 6.21 | -14 | % | 6.91 | 7.04 | -2 | % | ||||||||||||||||
Natural gas ($/mcf)(including realized financial instruments) | 6.64 | 7.23 | -8 | % | 7.51 | 7.72 | -3 | % | ||||||||||||||||
Crude oil ($/bbl) | 68.38 | 67.27 | 2 | % | 61.79 | 63.03 | -2 | % | ||||||||||||||||
Crude oil($/bbl) (including realized financial instruments) | 64.42 | 62.67 | 3 | % | 59.88 | 58.63 | 2 | % | ||||||||||||||||
Natural gas liquids($/bbl) | 50.60 | 50.60 | 0 | % | 46.65 | 48.81 | -4 | % | ||||||||||||||||
Total ($/boe) | 50.45 | 53.78 | -6 | % | 51.31 | 53.61 | -4 | % | ||||||||||||||||
Total ($/boe) (including financial instruments) | 52.22 | 53.91 | -3 | % | 52.09 | 52.96 | -2 | % | ||||||||||||||||
Drilling activity (gross) | ||||||||||||||||||||||||
Natural gas | 33 | 55 | - | 84 | 150 | - | ||||||||||||||||||
Oil | 31 | 34 | - | 92 | 101 | - | ||||||||||||||||||
Other | - | 1 | - | 7 | 5 | - | ||||||||||||||||||
Dry and abandoned | - | 2 | - | 5 | 7 | - | ||||||||||||||||||
Total gross wells | 64 | 92 | - | 188 | 263 | - | ||||||||||||||||||
Total net wells | 27.4 | 43.2 | - | 96.6 | 125.6 | - | ||||||||||||||||||
Success rate (%) | 100 | % | 98 | % | - | 97 | % | 97 | % | - |
(1) | Please refer to the Non-GAAP measures section. |
2007 THIRD QUARTER REPORT 5
RESULTS OF OPERATIONS
Funds flow from operations totalled $181.6 million for the quarter and $564.0 million year-to-date compared to $200.3 million for the third quarter of 2006 and $580.1 million for the nine months ended September 30, 2006. The net loss year-to-date of $293.0 million compared to net earnings of $244.7 million for the same period in 2006 reflects the impact of the future income tax provision that was recorded in the second quarter 2007. Key factors impacting the results are;
• | Production volumes averaged 74,572 boe per day for the third quarter 2007 compared to 74,475 boe per day for the third quarter 2006. On a year-to-date basis, production volumes have averaged 77,435 boe per day in 2007 compared to 72,431 boe per day in 2006. |
• | On a year-to-date basis we have drilled a total of 188 gross (96.6 net) wells, investing approximately $325.3 million on net development expenditures. This compares to a total of 263 gross (125.6 net) wells, and approximately $257.2 million in 2006. In 2007, our focus has been on deeper wells targeting more prolific zones compared to a shallow, more gas (including coalbed methane) focused drilling program in 2006. |
• | The West Texas Intermediate (“WTI”) price averaged US$75.33 (Cdn$78.71) per barrel in the third quarter, as compared to US$70.55 (Cdn$79.10) per barrel for the third quarter 2006. On a year-to-date basis WTI crude oil prices have averaged US$66.26 (Cdn$73.22) per barrel compared to US$68.29 (Cdn$77.32) per barrel for the comparative period in 2006. Conversely, natural gas prices have remained below 2006 levels with the AECO Monthly Spot price for natural gas averaging $5.61 per mcf compared to $6.03 per mcf in the third quarter of 2006 and $6.81 per mcf for the nine months ended September 30, 2007 compared to $7.19 per mcf for the same period in 2006. |
• | Operating costs (before unit-based compensation) for the quarter averaged $10.48 per boe compared to $9.72 per boe in 2006. Year-to-date operating costs have increased 12 percent to $10.10 per boe, from $9.01 per boe during the same period in 2006. Operating costs have been impacted by higher power and labour costs year over year, both significant components of operating expenses. |
• | The passing of Bill C-52 (Budget Implementation Act, 2007) which contained the Specified Investment Flow Through Rules (“SIFT Rules”) during the second quarter of 2007 resulted in an increase to our future income tax expense and liability by approximately $330 million. This adjustment represents the tax effect on timing differences between the accounting and tax basis of net assets held. This adjustment is a non-cash expense and has no immediate impact on funds flow from operations available for distribution to unitholders. |
PRODUCTION
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Production | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Natural gas (mmcf/d) | 205.7 | 181.4 | 212.2 | 174.5 | ||||||||||||
Crude oil (bbl/d) | 34,578 | 38,314 | 35,636 | 37,765 | ||||||||||||
Natural gas liquids (bbl/d) | 5,711 | 5,925 | 6,426 | 5,577 | ||||||||||||
Barrels of oil equivalent (boe/d, 6:1) | 74,572 | 74,475 | 77,435 | 72,431 | ||||||||||||
Percentage natural gas | 46 | % | 41 | % | 46 | % | 40 | % | ||||||||
Percentage crude oil and natural gas liquids | 54 | % | 59 | % | 54 | % | 60 | % |
For the nine months ended September 30, 2007, production volumes averaged 77,435 boe per day as compared to 72,431 boe per day for the same period in 2006. The seven percent increase in average production volumes for the nine months ended September 30, 2007 reflect the full impact of the Samson acquisition which closed on August 31, 2006. Production in 2007 has been impacted by planned and unplanned turnaround activity, weather related downtime in the second and third quarter and minor property dispositions. We continue to add new production volumes through our active drilling and optimization programs which focused in the third quarter in the Rocky, Central and Southern Alberta areas.
6 CANETIC RESOURCES TRUST
Third quarter volumes were negatively impacted by planned and unplanned outages, with a resulting impact of approximately 1,200 boe per day. Major outages occurred at the non-operated Kaybob South and Keyera plants, with smaller non-operated outages in Saskatchewan. In addition, our third quarter volumes were impacted by minor property dispositions totalling approximately 1,000 boe per day in Northeastern Alberta, primarily natural gas.
Looking forward to the fourth quarter, we are anticipating a number of outages that will impact production. We expect that each outage individually will not be significant and will impact production for only a few days. These turnarounds are designed to take advantage of the softness in natural gas prices prior to the winter heating season. These planned turnarounds are all being undertaken for preventative maintenance purposes in accordance with good operating practices.
COMMODITY PRICES
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Benchmark Prices | 2007 | 2006 | 2007 | 2006 | ||||||||||||
WTI crude oil (US$/bbl) | 75.33 | 70.55 | 66.26 | 68.29 | ||||||||||||
NYMEX natural gas average near month contract (US$/mcf) | 6.75 | 6.52 | 7.17 | 7.87 | ||||||||||||
AECO natural gas monthly index($/mcf) | 5.61 | 6.03 | 6.81 | 7.19 | ||||||||||||
Average Canadian/U.S. dollar exchange rate | 0.9571 | 0.8919 | 0.9050 | 0.8832 | ||||||||||||
Average Realized Canetic Prices (before financial derivatives) | ||||||||||||||||
Crude oil ($/bbl) | 68.38 | 67.27 | 61.79 | 63.03 | ||||||||||||
Natural gas liquids($/bbl) | 50.60 | 50.60 | 46.65 | 48.81 | ||||||||||||
Natural gas ($/mcf) | 5.33 | 6.21 | 6.91 | 7.04 |
The price of WTI crude averaged US$75.33 (Cdn$78.71) per bbl during the third quarter 2007, compared to US$70.55 (Cdn$79.10) per bbl for the same period in 2006. For the first nine months of 2007, WTI crude averaged US$66.26 (Cdn$73.22) per bbl compared to US$68.29 (Cdn$77.32) per bbl for the same period in 2006. Crude oil prices remain strong with global demand growth continuing to tighten the supply-demand situation as inventories decline. As the year has progressed there has been a continued call for OPEC production to increase as Non-OPEC supply growth has not been able to meet this increased demand.
For the nine months ended September 30, 2007, we received an average oil price of $61.79 per bbl as compared to $63.03 per bbl for the comparable period in 2006. Our differentials from WTI crude oil prices fluctuate as premiums for our light sweet crude oil are offset by increases in the differentials on heavy crude oil.
The AECO Monthly Index gas price averaged $5.61 per mcf in the third quarter of 2007, compared to $6.03 per mcf in the third quarter of 2006. Year-to-date, the AECO Monthly Index price has averaged $6.81 per mcf, compared to $7.19 per mcf for the same period in 2006. The AECO price continues to remain weak, consistent with 2006 levels. The primary factors influencing the AECO gas price are high inventory levels in North America caused by robust drilling activity in the United States, LNG imports redirected from the European market as a result of lower gas prices in Europe and the lack of significant weather patterns that draw on gas storage. The Western Canadian Sedimentary Basin activity levels are expected to remain weak until prices appreciate to a level where natural gas margins improve and begin to drive supply.
Our average realized natural gas price was $6.91 per mcf for the nine months ended September 30, 2007 as compared to $7.04 per mcf during the same period in 2006. Our average natural gas price for the quarter was $5.33 per mcf compared to $6.21 per mcf in the third quarter 2006.
2007 THIRD QUARTER REPORT 7
COMMODITY PRICE RISK MANAGEMENT
The prices we receive for petroleum and natural gas can fluctuate significantly due to supply and demand fundamentals which are influenced by weather patterns, the economic environment or political uncertainty.
Our commodity price risk management program is designed to provide price protection on a portion of our future production in the event of adverse commodity price movements, while retaining the opportunity to participate in favourable price movements. This practice is designed to allow us to generate stable funds flow for distributions and achieve positive economic returns on capital development and acquisition activities.
For the nine month period ended September 30, 2007 we have realized a gain on financial derivatives of $16.5 million compared to a loss of $12.8 million for the same period in 2006. During the third quarter, 2007, we recorded a realized financial derivative gain of $12.2 million as compared to a gain of $0.8 million for the same period in 2006.
The following commodity commitments have been put in place for the remainder of 2007 and beyond:
Commodity Contracts | Q4 2007 | 2008 | 2009 | |||||||||
Natural Gas | ||||||||||||
Fixed Price Volume (Gj/d) | 20,000 | 11,667 | - | |||||||||
Fixed Price Average($/Gj) | $ | 7.51 | $ | 6.53 | - | |||||||
Collars Volume (Gj/d) | 86,667 | 22,500 | - | |||||||||
Collar Floors ($/Gj) | $ | 6.92 | $ | 7.00 | - | |||||||
Collar Caps($/Gj) | $ | 10.74 | $ | 11.23 | - | |||||||
Total Volume Hedged(Gj/d) | 106,667 | 34,167 | - | |||||||||
Crude Oil | ||||||||||||
CDN Denominated Fixed Price Volumes (bbl/d) | 8,000 | 250 | - | |||||||||
CDN Denominated Fixed Price Average ($CDN/bbl) | $ | 67.26 | $ | 72.20 | - | |||||||
U.S. Denominated Fixed Price Volume(bbl/d) | 1,500 | - | - | |||||||||
U.S. Denominated Fixed Price Average ($US/bbl) | $ | 48.11 | - | - | ||||||||
Collars Volume(bbl/d) | 6,000 | 12,000 | - | |||||||||
Collar Floors ($US/bbl) | $ | 58.00 | $ | 64.17 | - | |||||||
Collar Caps($US/bbl) | $ | 80.76 | $ | 81.49 | - | |||||||
Total Volume Hedged (bbl/d) | 15,500 | 12,250 | - |
CURRENCY RISK MANAGEMENT
The Canadian dollar averaged US$0.9050 during the first nine months of 2007 as compared to US$0.8832 for the same period last year. As the price of WTI crude oil is quoted in U.S. dollars, appreciation in the Canadian dollar reduces the average price received for our production. Canetic can mitigate the impact of exchange rate fluctuations by either entering into foreign exchange contracts directly or executing some portion of our crude oil swaps in Canadian dollars. In 2007, Canetic had no foreign exchange contracts, but had entered into contracts for 8,000 bbl per day of its crude oil production using Canadian dollar denominated swaps.
The Canadian dollar has continued to appreciate and moved above par with the U.S. dollar near the end of the third quarter of 2007. This will continue to impact our revenues as prices for both oil and natural gas are based on U.S. dollar benchmarks, thus reducing the overall margins we receive in Canadian dollars.
8 CANETIC RESOURCES TRUST
PETROLEUM AND NATURAL GAS SALES
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Petroleum and natural gas sales ($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Crude oil and natural gas liquids | 245,221 | 264,898 | 684,067 | 724,509 | ||||||||||||
Natural gas | 100,871 | 103,604 | 400,619 | 335,544 | ||||||||||||
Petroleum and natural gas sales | 346,092 | 368,502 | 1,084,686 | 1,060,053 |
For the nine months ended September 30, 2007, petroleum and natural gas sales increased two percent to $1,084.7 million from $1,060.0 million for the same period in 2006 primarily as a result of increased production volumes. Revenue for the third quarter decreased to $346.1 million from $368.5 million during the same period in 2006.
Crude oil and NGL sales before derivative gains and losses decreased for the nine months ended September 30, 2007, to $684.1 million from $724.5 million in 2006. The decrease is attributable to natural production declines and lower commodity prices as compared to the same period a year earlier. Embedded within Canetic’s average price is the impact of the rising Canadian dollar against the U.S. dollar. Canadian well head prices are based on the posted WTI price which is quoted in U.S. dollars less appropriate offsets for relative quality and transportation. As the Canadian dollar has strengthened in 2007, our overall revenues on a relative basis have been negatively impacted, particularly in the third quarter as the Canadian dollar averaged U.S. $0.9571 as compared to U.S. $0.8919 for the same quarter in 2006.
Natural gas sales increased nineteen percent to $400.6 million during the nine months ended September 30, 2007. Increased sales volumes were partially offset by lower natural gas prices relative to the same period in 2006. Average daily sales of natural gas increased to 212.2 mmcf per day in 2007 from 174.5 mmcf per day in 2006, primarily as a result of the volumes acquired in the Samson acquisition net of property dispositions made during the second quarter 2007. Revenue for the third quarter 2007 of $100.9 million was lower than the $103.6 million for the same period in 2006 as price declines offset the increases in production volumes.
For the remainder of 2007, we expect that the major external forces that will influence revenue will be changes to commodity prices and the exchange rate of the Canadian dollar relative to the U.S. dollar.
ROYALTIES
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Royalties ($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Royalties, net of ARTC | 60,499 | 62,432 | 194,788 | 194,651 | ||||||||||||
Percentage of Petroleum and natural gas revenue | 17.5 | % | 16.9 | % | 18.0 | % | 18.4 | % | ||||||||
$/boe | 8.82 | 9.11 | 9.21 | 9.84 |
For the nine months ended September 30, 2007, royalty expense totalled $194.8 million as compared to $194.7 million during the same period a year earlier. As a percentage of sales, royalties averaged 18.0 percent during the nine months ended September 30, 2007 as compared to 18.4 percent in the same period in 2006.
During the third quarter, royalties averaged $8.82 per boe or approximately 17.5 percent of Canetic’s total petroleum and natural gas sales price (before hedging) of $50.45 per boe. This compares to $9.11 per boe or 16.9 percent of average sales price reported for the same period in 2006.
2007 THIRD QUARTER REPORT 9
OPERATING COSTS
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Operating Costs ($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Operating costs before unit-based compensation | 71,932 | 66,579 | 213,539 | 178,226 | ||||||||||||
Unit-based compensation: | ||||||||||||||||
Cash expense | 228 | 412 | 558 | 412 | ||||||||||||
Non-cash unit-based compensation | 241 | (278 | ) | 907 | 2,522 | |||||||||||
Total operating costs and unit-based compensation | 72,401 | 66,713 | 215,004 | 181,160 | ||||||||||||
$/boe before unit-based compensation | 10.48 | 9.72 | 10.10 | 9.01 | ||||||||||||
$/boe after unit-based compensation | 10.55 | 9.74 | 10.17 | 9.16 |
For the nine months ended September 30, 2007, operating costs before unit-based compensation increased to $213.5 million or $10.10 per boe from $178.2 million or $9.01 per boe for the same period in 2006. The relative dollar increase can be specifically attributed to a higher cost structure in the field due to increased labour and power costs as well as the impact of the Samson acquisition which closed August 31, 2006. Industry trends have been towards higher unit costs as producers are impacted by natural production declines and increasing costs. Canetic expects that recent weakness in natural gas prices will help to reduce upward pressure on costs.
Although operating costs continue to be a challenge, we maintain our commitment to managing operational efficiencies and optimizing field netbacks in all areas where we do business. As we continue to experience higher field costs throughout our asset base, considerable effort and focus is being given to operational efficiencies which will help to control operating costs on a unit-of-production basis, including the divestiture of assets which have a high cost base.
We continue to estimate operating costs will average $10.00 to $11.00 per boe for the remainder of 2007. This estimate reflects the current cost environment that exists in Western Canada and the cost pressures on our production operations.
TRANSPORTATION
Three Months Ended September 30 | Nine Months Ended September 30 | |||
Transportation ($000s) | 2007 | 2006 | 2007 | 2006 |
Transportation expense | 5,909 | 4,980 | 17,816 | 13,716 |
$/boe | 0.86 | 0.73 | 0.84 | 0.69 |
Transportation costs are defined by the point of legal custody transfer of the commodity and are dependent upon the type of product being sold, location of the producing asset, availability of pipeline capacity and sales point of the product.
For crude oil, Canetic sells all of its production at the lease. The purchaser picks up the production at the lease and pays Canetic a price for the applicable crude type based upon a price posted at the appropriate market hub, adjusted for the quality of Canetic’s crude, less the transportation costs between that market hub and the lease. For natural gas, Canetic transports its natural gas from the plant gate to certain established market hubs such as AECO C in Alberta, at which point title transfers to the purchaser. In both cases, transportation costs associated with getting natural gas and clean marketable oil to the point of title transfer are shown separately as a transportation expense.
In British Columbia, Westcoast Energy Inc. (operated by Spectra Energy) controls most of the gas processing infrastructure. Individual producers negotiate tolls with Spectra, under light-handed NEB regulations, for gathering, processing, and transmission. These tolls are included in the transportation expense.
10 CANETIC RESOURCES TRUST
NETBACKS
Cash net operating income represents the profit margin associated with the production and sale of petroleum and natural gas. For the three and nine months ended September 30, 2007, our netbacks were influenced by our product mix, commodity prices, financial derivative gains, royalty rates, the appreciation in the Canadian dollar relative to the U.S. dollar, and operating costs.
Components of our netbacks are as follows:
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Netbacks ($/boe) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Petroleum and natural gas sales | 50.45 | 53.78 | 51.31 | 53.61 | ||||||||||||
Less: | ||||||||||||||||
Royalties | 8.82 | 9.11 | 9.21 | 9.84 | ||||||||||||
Operating costs(before unit-based compensation) | 10.48 | 9.72 | 10.10 | 9.01 | ||||||||||||
Transportation | 0.86 | 0.73 | 0.84 | 0.69 | ||||||||||||
Cash net operating income | 30.29 | 34.22 | 31.16 | 34.07 | ||||||||||||
General and administrative (before unit-based compensation) | 1.49 | 1.29 | 1.57 | 1.42 | ||||||||||||
Interest on long-term debt | 2.67 | 2.03 | 2.37 | 1.73 | ||||||||||||
Interest on convertible debentures | 0.66 | 0.28 | 0.66 | 0.20 | ||||||||||||
Realized (gain) loss on financial derivatives | (1.77 | ) | (0.12 | ) | (0.78 | ) | 0.65 | |||||||||
Unit-based compensation - cash | 0.22 | 0.40 | 0.18 | 0.14 | ||||||||||||
Current income taxes | 0.08 | 0.37 | 0.14 | 0.11 | ||||||||||||
Capital tax | 0.48 | 0.75 | 0.37 | 0.47 | ||||||||||||
Cash netback from operations | 26.46 | 29.22 | 26.65 | 29.35 | ||||||||||||
Reconciliation to net earnings (loss): | ||||||||||||||||
Unit-based compensation - non-cash | 0.24 | (0.27 | ) | 0.29 | 0.85 | |||||||||||
Depletion, depreciation and amortization | 26.11 | 24.61 | 25.13 | 23.72 | ||||||||||||
Accretion | 0.56 | 0.42 | 0.55 | 0.39 | ||||||||||||
Unrealized (gain) on financial derivatives | 1.43 | (10.57 | ) | 0.39 | (4.03 | ) | ||||||||||
Future income taxes (recovery) | (4.17 | ) | 0.06 | 14.15 | (3.98 | ) | ||||||||||
Net earnings (loss) | 2.29 | 14.97 | (13.86 | ) | 12.40 |
GENERAL AND ADMINISTRATIVE EXPENSES
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
General and Administrative Expenses (“G&A”)($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
G&A expenses | 24,272 | 14,017 | 80,025 | 42,204 | ||||||||||||
Overhead recoveries | (14,038 | ) | (5,147 | ) | (46,933 | ) | (14,041 | ) | ||||||||
Cash G&A expenses before unit-based compensation | 10,234 | 8,870 | 33,092 | 28,163 | ||||||||||||
Unit-based compensation: | ||||||||||||||||
Cash expense | 1,292 | 2,336 | 3,163 | 2,336 | ||||||||||||
Non-cash unit-based compensation | 1,365 | (1,578 | ) | 5,141 | 14,292 | |||||||||||
Total G&A and unit-based compensation | 12,891 | 9,628 | 41,396 | 44,791 | ||||||||||||
$/boe before unit-based compensation | 1.49 | 1.29 | 1.57 | 1.42 | ||||||||||||
$/boe after unit-based compensation | 1.88 | 1.41 | 1.96 | 2.27 |
General and administrative expenses, net of overhead recoveries and before unit-based compensation, increased seventeen percent to $33.1 million for the nine months ended September 30, 2007 as compared to $28.2 million for the same period a year earlier. On a unit-of-production basis, general and administrative expenses averaged $1.57 per boe as compared to $1.42 per boe for the same period in 2006. During the period, Canetic has increased staffing and administration levels due to the StarPoint and Samson acquisitions in 2006 and Canetic’s listing on the New York Stock Exchange. As well, increased overall compensation costs associated with remaining competitive and retaining staff in the Calgary market have impacted our overall general and administrative expenses.
2007 THIRD QUARTER REPORT 11
General and administrative expenses for 2007 are expected to average approximately $1.60 per boe before unit-based compensation.
UNIT-BASED COMPENSATION
For the nine months ended September 30, 2007, Canetic recorded unit-based compensation expense of $9.8 million (2006 - $19.6 million) and capitalized unit-based compensation of $4.2 million (2006 - $4.4 million). Upon vesting, the obligation may be settled in units or cash. The amounts due in the current year of $7.5 million (2006 - $16.3 million) is reflected as a current liability in the financial statements. The compensation liability is re-measured each period at the current market price for Canetic’s units. The September 30, 2007, compensation liability was based on the period-end weighted average closing price of $15.26 and the number of Restricted Trust Units (“RTUs”) and Performance Trust Units (“PTUs”) outstanding at that time, with the PTUs adjusted for a PTU multiplier. The PTU multiplier is determined based on the relative performance of Canetic in relation to a basket of other similar trusts. Each tranche of PTUs issued has a different PTU multiplier. As of September 30, 2007, there were 1,018,802 RTUs and 1,657,958 PTUs outstanding.
INTEREST EXPENSE ON BANK DEBT
As At And For The Three Months Ended September 30 | As At And For The Nine Months Ended September 30 | |||||||||||||||
Interest Expense ($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Interest expense | 18,340 | 13,908 | 50,053 | 34,197 | ||||||||||||
Bank loans | 1,374,002 | 1,223,016 | 1,374,002 | 1,223,016 | ||||||||||||
Debt to annualized funds flow | 1.9 | 1.5 | 1.8 | 1.6 |
Interest expense, representing interest on bank debt, increased to $50.1 million or $2.37 per boe from $34.2 million or $1.73 per boe a year earlier. Average debt levels have increased as a result of the Samson acquisition made during 2006 and capital spending late in 2006 and through 2007.
Average interest rates incurred by Canetic during the quarter averaged approximately 5.64 percent and 5.14 percent for the nine months ended September 30, 2007. This compares to 5.02 percent and 5.41 percent for the same periods in 2006, respectively.
INTEREST EXPENSE ON CONVERTIBLE DEBENTURES
Interest expense on convertible debentures totalled $13.9 million for the nine months ended September 30, 2007 as compared to $4.0 million for the same period in 2006. During 2006, debentures totalling $230.0 million were issued in conjunction with the Samson acquisition. At September 30, 2007, debentures totalling $260.2 million remain outstanding.
DEPLETION, DEPRECIATION AND AMORTIZATION
The current quarter provision for depletion, depreciation and amortization totalled $179.0 million as compared to $168.6 million in 2006. On a unit-of-production basis, depletion, depreciation and amortization costs averaged $26.11 per boe as compared to $24.61 per boe for the same period in 2006.
FINANCIAL DERIVATIVES
At September 30, 2007, we recorded a net financial derivative liability of $3.3 million. The estimated fair value is based on a mark-to-market calculation as at September 30, 2007 to settle the financial contracts. The actual gain or loss realized upon settlement could vary significantly due to fluctuations in commodity prices. At September 30, 2007, Canetic recorded an unrealized financial derivative loss of $8.3 million (2006 - gain of $79.8 million).
12 CANETIC RESOURCES TRUST
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Gain (Loss) on Financial Derivatives($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Realized cash gain (loss) on financial derivatives | 12,174 | 844 | 16,457 | (12,831 | ) | |||||||||||
Unrealized gain (loss) on financial derivatives | (9,827 | ) | 72,453 | (8,342 | ) | 79,759 | ||||||||||
Gain on financial derivatives | 2,347 | 73,297 | 8,115 | 66,928 |
ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligation was estimated by management based on the Trust’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the facilities, and the estimated timing of the costs to be incurred in future periods. The costs are expected to be incurred over an average of 15 years. The estimated funds flow from operations has been calculated using a credit adjusted risk free discount rate of eight percent and an inflation rate of two percent.
As of September 30, 2007, the amount to be recorded as the fair value of the liability was estimated to be $194.4 million (December 31, 2006 - $191.9 million). During the nine months ended September 30, 2007, Canetic incurred $11.2 million (2006 - $10.6 million) of actual abandonment and reclamation costs and recorded accretion of $11.6 million (2006 - $7.8 million).
INCOME TAXES
Enactment of Bill C-52, Budget Implementation Act, 2007
Bill C-52 (Budget Implementation Act, 2007) (the “SIFT Tax Act”) which contains the the SIFT Rules received Royal Assent and became law on June 22, 2007. Under the SIFT Rules, commencing January 1, 2011 (provided the Trust experiences only "normal growth" and no "undue expansion" as discussed below) certain of our distributions that would have otherwise been deductible by the Trust for tax purposes will be subject to a special tax at a rate of 31.5 percent (the “Distribution Tax”). The intent of the SIFT rules is to impose tax on income trusts in a similar manner and at rates comparable to Canadian public corporations and to treat our distributions as dividends in the hands of our unitholders. Effectively, trust level taxable income will be subject to the Distribution Tax and any taxes payable as a result will directly reduce cash available for distribution. The funds flow impact will be mitigated to the extent the Trust has tax pools available to shelter the Distribution Tax. Currently, the Trust has approximately $1.7 billion of tax pools that may be used to offset future taxes. This should allow us to defer payment of cash taxes beyond 2011.
Generally, trusts that were publicly traded on October 31, 2006 will have a four-year transition period (the “Transition Period”) and, subject to compliance with the Department of Finance’s Guidelines on “normal growth “ as described below, will not be subject to the SIFT Rules until January 1, 2011.
On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" and “undue expansion” which guidelines have been incorporated in the SIFT Rules. Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to the market capitalization of a Specified Investment Flow-Through Entity (a “SIFT”) as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units) (the "Benchmark"). Those safe harbour limits are 40 percent of the Benchmark for the period from November 1, 2006 to December 31, 2007, and 20 percent of the Benchmark each for calendar 2008, 2009 and 2010. Moreover, these limits are cumulative so that any unused limit for a period carries over into the subsequent period.
Our total Benchmark at October 31, 2006 was approximately $4.5 billion. Available safe harbour through to December 31, 2007 will be approximately $1.8 billion, which is 40 percent of the Benchmark. The safe harbour for each of 2008, 2009, and 2010 is approximately $900 million, which is 20 percent of the Benchmark. Should any portion of the safe harbour not be utilized in any period, this portion will be available in a subsequent period.
2007 THIRD QUARTER REPORT 13
While these guidelines are such that it is unlikely they alone would affect our ability to raise the capital required to maintain and grow our existing operations in the ordinary course during the Transition Period, they could adversely affect the cost of raising capital and our ability to undertake more significant acquisitions.
Future Income Taxes
For the nine months ended September 30, 2007, Canetic recognized future tax expense of $299.0 million compared with a future tax recovery of $78.6 million for the same period in 2006. The increase is due to the one-time charge to future tax expense associated with the enactment of the SIFT Tax Act as described above. This was partially offset by future tax recoveries of $4.0 million as a result of an additional 0.5 percent reduction to the federal general corporate tax rate also enacted during the period and $45.0 million from the change in timing differences in respect of the current period. The Trust has also provided $20.0 million as a reserve against future income taxes due to uncertainty in the ability to fully access a portion of our successor tax pools over time under the SIFT Tax Act.
Current Income Taxes
Although the Trust is not subject to the Distribution Tax until the year 2011, there are certain corporate entities in the underlying structure which hold minority interests in some of the Trust’s operating partnerships which are subject to a small amount of current income tax. Current taxes of $3.0 million were recorded for the nine months ended September 30, 2007, $1.2 million of this amount is non-recurring and arose on the merger of Acclaim and StarPoint.
Capital Taxes
The Trust recorded $7.9 million of capital tax for the nine months ended September 30, 2007, attributable to the Saskatchewan Resource Surcharge. Federal capital taxes were eliminated in 2006.
ESTIMATED INCOME TAX POOLS
Estimated Income Tax Pools ($000s) | September 30, 2007 | |||
Undepreciated capital costs | 561,600 | |||
Canadian oil and gas property expense | 505,736 | |||
Canadian exploration expense | 23,390 | |||
Canadian development expense | 349,832 | |||
Non-capital losses | 270,960 | |||
Other | 38,016 | |||
Total estimated income tax pools | 1,749,534 |
14 CANETIC RESOURCES TRUST
CAPITAL EXPENDITURES
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Capital Expenditures ($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Land | 3,582 | 3,812 | 7,527 | 12,615 | ||||||||||||
Geological and geophysical | (38 | ) | 154 | 2,112 | 2,109 | |||||||||||
Drilling and completion | 69,873 | 79,595 | 256,386 | 212,923 | ||||||||||||
Production equipment and facilities | 14,614 | 20,863 | 59,253 | 29,566 | ||||||||||||
Net development expenditures | 88,031 | 104,424 | 325,278 | 257,213 | ||||||||||||
StarPoint acquisition | - | - | - | 2,511,746 | ||||||||||||
Acquistion of property interests | - | 967,204 | - | 967,204 | ||||||||||||
Property acquisitions | 14,465 | 4,480 | 16,637 | 28,349 | ||||||||||||
Property dispositions | (6,005 | ) | - | (55,768 | ) | (5,000 | ) | |||||||||
Net capital expenditures | 96,491 | 1,076,108 | 286,147 | 3,759,512 | ||||||||||||
Office | 1,609 | 3,780 | 6,557 | 6,843 | ||||||||||||
Asset retirement obligation on new wells | 593 | 767 | 2,086 | 2,239 | ||||||||||||
Capitalized compensation | 2,786 | (2,240 | ) | 8,884 | 4,414 | |||||||||||
Total capital expenditures | 101,479 | 1,078,415 | 303,674 | 3,773,008 |
During the nine months ended September 30, 2007, expenditures for development activities totalled $325.3 million as compared to $257.2 million for the same period in 2006. A total of 188 gross (96.6 net) wells have been drilled, including 84 gross (41.1 net) natural gas wells and 92 gross (53.0 net) oil wells, 7 gross (1.0 net) service wells and 5 gross (1.5 net) dry and abandoned wells. The increase in development expenditures reflects the inventory of locations associated with our asset base resulting from the acquisitions made in previous years and a decision by Canetic to become more focused on internal growth opportunities. Of the total wells drilled to September 30, 2007, 69 gross (63.6 net) were operated by Canetic resulting in 46 gross (43.5 net) oil wells, 22 gross (19.1 net) natural gas wells and 1 gross (1.0 net) dry and abandoned (“D&A”) well. Canetic has also changed the profile of its operated drilling program in 2007 over 2006, targeting deeper more prolific horizons and consequently higher cost wells.
During the nine months ended September 30, 2007, we completed net property dispositions totalling $55.8 million representing approximately 1,000 boe per day, primarily natural gas, in Northeast Alberta. Proceeds from the dispositions have been utilized to fund a portion of our 2007 capital expenditure program.
Sources of Funding Net Capital Expenditures
Nine Months Ended September 30, 2007 | ||||||||||||||||
Net Capital Expenditures ($000s) | 2007 | 2006 | ||||||||||||||
Funded by: | Amount | % | Amount | % | ||||||||||||
Cash flow | 176,449 | 62 | % | 68,849 | 2 | % | ||||||||||
DRIP and base shelf prospectus, net of costs | 51,466 | 18 | % | 44,825 | 1 | % | ||||||||||
Units issued pursuant to arrangement | - | - | 2,562,563 | 68 | % | |||||||||||
Convertible debentures, net of costs | - | - | 220,800 | 6 | % | |||||||||||
Bought deal financing, net of costs | - | - | 437,001 | 12 | % | |||||||||||
Bank debt and non-cash working capital | 58,232 | 20 | % | 425,474 | 11 | % | ||||||||||
286,147 | 100 | % | 3,759,512 | 100 | % |
LIQUIDITY AND CAPITAL RESOURCES
Typical of oil and gas trusts, Canetic’s asset base will decline over time and therefore we rely on acquisitions and ongoing development activities to mitigate production and reserve declines. Future production volumes and reserves are highly dependent on our success in exploiting our asset base and acquiring additional reserves.
2007 THIRD QUARTER REPORT 15
We finance our operations and capital activities primarily with funds generated from operating activities, but also through the issuance of trust units, debentures and borrowings from our credit facility. The amount of equity we raise through the issuance of trust units depends on many factors including projected cash needs, availability of funding through other sources, our unit price and the state of the capital markets. We believe our sources of cash, including anticipated financings and bank debt, will be sufficient to fund our operations and planned capital expenditure program in 2007 as well as make monthly distribution payments. Our ability to fund distributions also depends on performance and is subject to commodity prices and other economic factors beyond our control.
Canetic’s capital structure at September 30, 2007, is reconciled as follows:
Nine Months Ended September 30, 2007 | Year Ended December 31, 2006 | |||||||||||||||
($000s unless otherwise indicated) | Amount | % | Amount | % | ||||||||||||
Debt | ||||||||||||||||
Bank debt | 1,374,002 | 30 | % | 1,289,678 | 25 | % | ||||||||||
Working capital deficiency | 31,774 | 1 | % | 29,794 | 1 | % | ||||||||||
Net financial derivatives included in working capital | (1,563 | ) | _ | (1,124 | ) | _ | ||||||||||
Net debt | 1,404,213 | 31 | % | 1,318,348 | 26 | % | ||||||||||
Convertible debentures (long-term portion) | 245,128 | 5 | % | 258,959 | 5 | % | ||||||||||
Unitholders’ equity | 2,887,693 | 64 | % | 3,506,915 | 69 | % | ||||||||||
Total capitalization | 4,537,034 | 100 | % | 5,084,222 | 100 | % |
CREDIT FACILITIES AND CONVERTIBLE DEBENTURES
Canetic has an unsecured covenant based credit facility with a syndicate of financial institutions in the amount of $1.6 billion, including a $50.0 million operating facility. The facility carries floating interest rates which range between 65.0 and 115.0 basis points over Banker’s Acceptance rates. This facility was increased in the third quarter of 2006 from $1.1 billion upon closing of the Samson acquisition. The facility has a maturity date of May 31, 2009, is reviewed annually and may be extended at the option of the lender for an additional one-year period. All amounts owing under the facility have therefore been classified as long-term on the balance sheet.
At September 30, 2007, $1.37 billion was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At September 30, 2007, Canetic had a working capital deficiency of $31.8 million.
The following tables summarize the dollar value of issuances and conversions of the convertible debentures:
9.4 | % | 6.5 | % | 8 | % | 11 | % | 6.5 | % | |||||||||||||||
(CNE.DB.A) | (CNE.DB.B) | (CNE.DB.C) | (CNE.DB.D) | (CNE.DB.E) | Total | |||||||||||||||||||
Balance, December 31, 2006 ($000s) | 5,622 | 17,821 | 8,046 | 1,697 | 227,470 | 260,656 | ||||||||||||||||||
Converted to units | - | - | (17 | ) | (414 | ) | - | (431 | ) | |||||||||||||||
Deferred transaction costs | - | - | (264 | ) | (42 | ) | (7,928 | ) | (8,234 | ) | ||||||||||||||
Balance, end of period | 5,622 | 17,821 | 7,765 | 1,241 | 219,542 | 251,991 | ||||||||||||||||||
Units Issuable Upon Conversion (000’s) | ||||||||||||||||||||||||
Balance, December 31, 2006 | 351 | 940 | 517 | 152 | 8,663 | 10,623 | ||||||||||||||||||
Converted to units | - | - | (1 | ) | (37 | ) | - | (38 | ) | |||||||||||||||
Balance, end of period | 351 | 940 | 516 | 115 | 8,663 | 10,585 |
Our intention in the near term is not to convert any of the convertible debentures to trust units where we have the option of redemption.
16 CANETIC RESOURCES TRUST
TRUST UNIT CAPITAL
As at September 30, 2007, Canetic had issued capital of 230.1 million trust units and as at November 8, 2007, we had issued capital of 231.5 million trust units. If all outstanding convertible debentures were converted into trust units, a total of 240.7 million trust units would have been outstanding as at September 30, 2007 and 242.0 million trust units as at November 8, 2007.
Nine Months Ended September 30, 2007 | Year ended December 31, 2006 | |||||||||||||||
Trust Units | Units (000s) | Amount ($000s) | Units (000s) | Amount ($000s) | ||||||||||||
Balance, beginning of period | 225,796 | 4,224,470 | 91,583 | 1,087,459 | ||||||||||||
Issued: | ||||||||||||||||
Base shelf prospectus, net of costs | 1,450 | 20,507 | - | - | ||||||||||||
Bought deal financing, net of costs | - | - | 20,769 | 437,001 | ||||||||||||
Employee Unit Savings Plan | 353 | 5,450 | 274 | 6,184 | ||||||||||||
Distribution reinvestment plan | 2,113 | 30,959 | 2,470 | 44,825 | ||||||||||||
Issued pursuant to Arrangement | - | - | 106,242 | 2,562,563 | ||||||||||||
Properties contributed to TriStar | - | - | - | (5,000 | ) | |||||||||||
Conversion of debentures | 38 | 431 | 2,042 | 36,302 | ||||||||||||
Conversion of debentures - equity portion | - | - | - | 4,636 | ||||||||||||
Conversion of exchangeable shares | - | - | 358 | 3,804 | ||||||||||||
Unit award incentive plan | 358 | 5,721 | 2,058 | 46,696 | ||||||||||||
Balance, end of period | 230,108 | 4,287,538 | 225,796 | 4,224,470 |
On August 20, 2007, we filed a Short Form Base Shelf Prospectus with the securities regulatory authorities in Canada and a Registration Statement with the US Securities and Exchange Commission. The registration allows Canetic to offer and issue trust units or Subscription Receipts convertible into trust units by way of one or more Prospectus Supplements for a 25 month period commencing on the date of filing. The Securities may be offered from time to time, with an aggregate offering amount not to exceed Cdn $750.0 million.
On August 23, 2007, we filed a Prospectus Supplemental to the Short Form Base Shelf Prospectus dated August 20, 2007, with regulatory authorities in Canada and a supplement to the U.S. Prospectus dated August 20, 2007 forming part of the Registration Statement with the U.S. Securities and Exchange Commission. By way of an Equity Distribution Agreement dated August 23, 2007, Canetic will be able to sell trust units by way of “at-the-market” offerings over the TSX, the New York Stock Exchange and other existing trading markets for the trust units in the U.S.. Subject to the terms of the Equity Distribution Agreement and applicable regulatory requirements, up to 15,500,000 trust units may be issued and sold from time to time at the discretion of Canetic over a period of up to 25 months.
Up to the end of September 2007, Canetic sold 1,450,000 trust units at an average price of US$15.08 per unit (net US$14.22 per unit) for gross proceeds of US$21.9 million (net US$20.6 million after costs, of US$1.3 million, including commissions). No sales were made on the TSX. Net proceeds from the issuances of trust units under the base shelf prospectus have been used for working capital purposes.
2007 THIRD QUARTER REPORT 17
FUNDS FLOW FROM OPERATIONS
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
Funds Flow ($000s) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Net earnings (loss) | 15,698 | 102,663 | (292,970 | ) | 244,733 | |||||||||||
Adjustments for: | ||||||||||||||||
Unit-based compensation expense | 1,606 | (1,856 | ) | 6,048 | 16,814 | |||||||||||
Depletion, depreciation and amortization | 179,043 | 168,639 | 531,267 | 469,129 | ||||||||||||
Accretion of asset retirement obligation | 3,870 | 2,851 | 11,609 | 7,759 | ||||||||||||
Unrealized loss on financial derivatives | 9,827 | (72,453 | ) | 8,342 | (79,759 | ) | ||||||||||
Future income taxes | (28,599 | ) | 424 | 298,956 | (78,614 | ) | ||||||||||
Accretion of deferred transaction costs | 159 | - | 763 | - | ||||||||||||
Funds flow from operations | 181,604 | 200,268 | 564,015 | 580,062 |
For the nine months ended September 30, 2007, funds flow from operations totalled $564.0 million or $2.48 per diluted unit, representing a decrease from $580.1 million, or $2.85 per diluted unit during the same period in 2006. Funds flow from operations during the third quarter amounted to $181.6 million or $0.79 per diluted unit as compared to $200.3 million or $0.93 per diluted unit for the comparable period in 2006.
We believe that funds flow generated from our operations, together with anticipated financings, borrowings under our credit facility, proceeds from sales of securities under the Base Shelf Prospectus and Registration Statement and proceeds from property dispositions, will be sufficient to finance our operations and planned capital expenditure program through the remainder of 2007. We establish our capital expenditure program based on an annual budget review process, including budgeted funds flow from operations, and we closely monitor changes throughout the year.
CASH DISTRIBUTIONS
Cash flow from operating activities and cash distributions are reported on the Consolidated Statements of Cash Flows. During the third quarter of 2007, cash distributions of $130.0 million were funded entirely through cash flow from operating activities of $182.2 million. For the nine months ended September 30, 2007 our cash distributions were $397.5 million and were funded entirely through cash flow from operating activities of $574.0 million.
For 2007, we estimate that for Canadian taxpayers, 100 percent of cash distributions will be taxable and no portion of the distributions will be a tax-deferred return of capital. Actual taxable amounts will vary depending upon production volumes, commodity prices and other factors. We estimate that for U.S. taxpayers, 100 percent of cash distributions paid during the year will be taxable as “Qualified Dividends” and no portion of the distributions will be a tax-deferred return of capital. Actual taxable amounts may vary and are dependent upon Canetic’s current and accumulated earnings and profits as determined under U.S. tax laws.
After consideration of cash distributions, the balance of our third quarter cash flow from operations of $52.1 million was used to partially fund our capital program. Our remaining capital program was financed from our credit facility.
For the three months ended September 30, 2007, our cash distributions exceeded our net income by $114.3 million (2006 - $42.2 million), however net income includes $165.9 million of non-cash items (2006 - $97.6 million) such as future income taxes and depreciation, depletion and amortization that do not impact our cash flow from operations. For the nine months ended September 30, 2007, our cash distributions exceeded our net income by $690.5 million (2006 - $172.2 million) which includes non-cash items of $857.0 million (2006 - $335.3 million) that do not impact our cash flow from operations. Future income taxes can fluctuate from period to period as a result of changes in tax rates (such as the enactment of the SIFT tax during the second quarter of 2007). Other non-cash charges such as depreciation, depletion and amortization are not a good proxy for the cost of maintaining our productive capacity as they are based on the historical costs of our property, plant and equipment and not the fair market value of replacingthose assets within the context of the current commodity price environment. The level of investment in a given period may not be sufficient to replace productive capacity given the natural declines associated with oil and natural gas assets. In these instances a portion of the cash distributions paid to unitholders may represent a return of the unitholder’s capital.
18 CANETIC RESOURCES TRUST
The following table compares cash distributions to cash flow from operating activities and net income (loss).
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
($000s, except where indicated) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Cash flows from operating activities | 182,162 | 138,644 | 573,983 | 485,823 | ||||||||||||
Use of cash flow: | ||||||||||||||||
Cash distributions | 130,017 | 144,859 | 397,534 | 416,974 | ||||||||||||
Capital expenditures | 52,145 | (6,215 | ) | 176,449 | 68,849 | |||||||||||
182,162 | 138,644 | 573,983 | 485,823 | |||||||||||||
Excess (deficiency) of cash flow over cash distributions | 52,145 | (6,215 | ) | 176,449 | 68,849 | |||||||||||
Net earnings (loss) | 15,698 | 102,663 | (292,970 | ) | 244,733 | |||||||||||
Shortfall of net income over cash distributions | (114,319 | ) | (42,196 | ) | (690,504 | ) | (172,241 | ) |
CONTRACTUAL OBLIGATIONS
In addition to financial derivative commitments, the Trust has the following contractual obligations as at September 30, 2007:
($000s) | Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | |||||||||||||||||||||
Bank debt | 1,374,002 | - | - | 1,374,002 | - | - | - | |||||||||||||||||||||
Convertible debentures(1) | 260,225 | 1,283 | 5,622 | 8,029 | 17,821 | 227,470 | - | |||||||||||||||||||||
Office lease | 103,664 | 1,653 | 6,436 | 6,436 | 8,950 | 9,948 | 70,241 | |||||||||||||||||||||
Pipeline contract | 8,596 | 163 | 788 | 997 | 1,055 | 1,341 | 4,252 | |||||||||||||||||||||
Total | 1,746,487 | 3,099 | 12,846 | 1,389,464 | 27,826 | 238,759 | 74,493 |
(1) Gross of deferred transaction costs.
QUARTERLY FINANCIAL AND OPERATING INFORMATION
2007 | 2006 | 2005 | ||||||||||||||||||||||||||||||
($000s except per unit amounts) | Sept. 30 | June 30 | Mar. 31 | Dec. 31 | Sept. 30 | Jun. 30 | Mar. 31 | Dec. 31 | ||||||||||||||||||||||||
Production | ||||||||||||||||||||||||||||||||
Oil and NGLs (bbl/d) | 40,289 | 42,592 | 43,337 | 43,402 | 44,239 | 42,391 | 43,388 | 21,915 | ||||||||||||||||||||||||
Natural gas (mmcf/d) | 205.7 | 211.0 | 220.1 | 221.2 | 181.4 | 166.0 | 176.1 | 105.8 | ||||||||||||||||||||||||
Boe/d @ 6:1 | 74,572 | 77,765 | 80,027 | 80,276 | 74,475 | 70,061 | 72,737 | 39,541 | ||||||||||||||||||||||||
Petroleum and natural gas sales | 346,092 | 372,385 | 366,209 | 347,701 | 368,502 | 341,205 | 350,346 | 234,098 | ||||||||||||||||||||||||
Funds flow from operations | 181,604 | 192,044 | 190,368 | 170,084 | 200,268 | 185,053 | 194,741 | 106,477 | ||||||||||||||||||||||||
Per unit - basic(1)(2) | 0.80 | 0.84 | 0.84 | 0.76 | 0.95 | 0.92 | 0.97 | 1.16 | ||||||||||||||||||||||||
Per unit - diluted(1)(2) | 0.79 | 0.84 | 0.83 | 0.75 | 0.93 | 0.89 | 0.96 | 1.14 | ||||||||||||||||||||||||
Net earnings (loss) | 15,698 | (301,798 | ) | (6,870 | ) | (21,632 | ) | 102,663 | 82,875 | 59,195 | 48,662 | |||||||||||||||||||||
Per unit - basic(1)(2) | 0.07 | (1.33 | ) | (0.03 | ) | (0.10 | ) | 0.49 | 0.41 | 0.29 | 0.53 | |||||||||||||||||||||
Per unit - diluted(1)(2) | 0.07 | (1.33 | ) | (0.03 | ) | (0.10 | ) | 0.48 | 0.40 | 0.29 | 0.53 | |||||||||||||||||||||
Distributions declared | ||||||||||||||||||||||||||||||||
Per unit | 0.570 | 0.570 | 0.570 | 0.690 | 0.690 | 0.690 | 0.690 | 0.585 |
(1) | When calculating the weighted average number of units at the end of a quarter, all units outstanding from the previous quarter are deemed to be outstanding for the entire period, whereas in the year-to-date calculation those units are weighted according to the date of issue. Consequently, the addition of the quarterly per unit results will not add to the annual earnings per unit. |
(2) | The merger of Acclaim Energy Trust (“Acclaim”) and StarPoint Energy Trust (“StarPoint”) has been accounted for as a purchase of StarPoint by Acclaim. Accordingly, the financial and operating results of StarPoint have been included from the date of acquisition, January 5, 2006. All disclosures of units and per unit amounts of Acclaim up to the merger on January 5, 2006 have been restated using the exchange ratio of 0.8333 of a Canetic unit for each Acclaim unit. |
2007 THIRD QUARTER REPORT 19
The variation of net earnings (loss), quarter-over-quarter, is primarily a result of changes in depletion rates, the provision for future income taxes, and accounting for unrealized gains and losses on financial derivatives. The net loss in the second quarter 2007 reflects the adjustment made to future income taxes as a result of the SIFT Rules.
BUSINESS RISKS
The operations of Canetic are subject to underlying risks associated with the business and structure of the Trust. Certain of these risks are summarized in the “Forward-Looking Statements” section of the MD&A. For a detailed discussion of business risks, please refer to “Risk Factors” in the Trust’s most recently filed Annual Information Form.
CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2007, the Trust adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 1530 “Comprehensive Income”, Section 3251 “Equity”, Section 3855 “Financial Instruments - Recognition and Measurement”, Section 3861 “Financial Instruments - Disclosure and Presentation”, and Section 3865 “Hedges”. As required by the new standards prior periods have not been restated. The adoption of these standards has had no material impact on the Trust’s net earnings (loss) or cash flows from operating activities. The effects of the implementation of the new standards are discussed below.
COMPREHENSIVE INCOME
The Trust does not have any items to be accounted as components of other comprehensive income (“OCI”) and as a result comprehensive income equals net earnings (loss).
FINANCIAL INSTRUMENTS
The financial instruments standard establishes the recognition and measurement criteria for financial assets, financial liabilities and derivatives. All financial instruments are required to be measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as “held-for-trading”, “available-for-sale”, “held-to-maturity”, “loans and receivables”, or “other financial liabilities” as defined by the standard.
Financial assets and financial liabilities “held-for-trading” are measured at fair value with changes in those fair values recognized in net earnings (loss). Financial assets “available-for-sale” are measured at fair value, with changes in those fair values recognized in OCI. Financial assets “held-to-maturity”, “loans and receivables”, and “other financial liabilities” are measured at amortized cost using the effective interest method of amortization. All derivative instruments, including embedded derivatives, are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale, or usage exemption. All changes in fair value are recorded in earnings unless hedge accounting is applied, in which case changes in fair value related to the effective portion of cash flow hedges is recognized in OCI.
As a result of the adoption of these new standards, the Trust has classified its accounts receivable as “loans-and-receivables”. Deposits have been classified as “held-to-maturity”. Accounts payable and accrued liabilities, distributions payable, bank debt, and convertible debentures have been classified as “other financial liabilities”. Changes in fair values of derivatives and embedded derivatives are recognized in earnings as the Trust has maintained its policy not to use hedge accounting.
Transaction costs are netted against the carrying value of the asset or liability to which it relates and then amortized over the expected life of the instrument using the effective interest method. On adoption of Section 3855 “Financial Instruments - Recognition and Measurement”, the Trust netted its remaining deferred financing charges against convertible debentures.
20 CANETIC RESOURCES TRUST
The Trust also adopted Section 1506 “Accounting Changes”, the only impact of which is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862 “Financial Instruments Disclosures”, Section 3863 “Financial Instruments Presentations”, and section 1535 “Capital Disclosures” which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Trust will adopt these standards on January 1, 2008 and it is expected the only effect on the Trust for adopting Sections 3862 and 3863 will be incremental disclosures regarding the significance of financial instruments for the entity's financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed. The effect on the Trust for adopting Section 1535 will be increased disclosure surrounding our objectives, policies and processes for managing capital.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to senior management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), on a timely basis so that appropriate decisions can be made regarding public disclosure. As at December 31, 2006, the CEO and the CFO have evaluated the effectiveness of Canetic’s disclosure controls and procedures as defined in Multilateral Instrument 52-109 (“MI 52-109”) of the Canadian Securities Administrators and have concluded that such disclosure controls and procedures are effective to provide reasonable assurance that material information related to the Trust is made known to them by employees or third party consultants working for the Trust. It should be noted that while the CEO and CFO believe that the disclosure controls and procedures are effective, they do not expect the controls and procedures to prevent all errors and fraud. A control system, regardless of how well conceived or operated, can only provide reasonable assurance, and not absolute assurance, that the objectives of the control system are met.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There have been no changes in internal control over financial reporting during the quarter ended September 30, 2007 that have materially affected, or are reasonably likely to materially effect, the Trust’s internal control over financial reporting.
OUTLOOK
Looking forward, we are very excited about the opportunity presented by our announced strategic combination with Penn West. Through this combination we will have created what we believe to be Canada’s flagship energy trust and a world-class platform to compete in Canadian and global energy markets. The combination will form the largest conventional oil and natural gas trust in North America and the dominant independent light oil producer in the Western Canadian Sedimentary Basin with anticipated production in 2008 of over 200,000 boe per day and conventional proven plus probable reserves in excess of 800 million boe. The increased size of the combined entity will facilitate the future development of its extensive inventory of conventional and unconventional opportunities including the multi-billion barrel (discovered heavy oil resources in place) Peace River Oil Sands Project, coalbed methane, shale gas and enhanced oil recovery from some of Canada’s largest legacy light oil pools.
We anticipate that the larger size of the combined trust will not only increase the opportunity base for future growth but will also enhance the liquidity of its units on both the Toronto and New York stock exchanges, increase its weighting in major indices, including the S&P/TSX 60 Index, and lead to greater attention from both equity and income investors. We also expect that the increased liquidity and enhanced financial strength of the combined trust will enable meaningful expansion both domestically and outside Canada as we look to position the trust for 2011 and beyond. At closing the combined trust will have tax pools in excess of $5.5 billion and safe harbour capacity for the issuance of new units under the undue expansion rules of approximately $8.7 billion in 2008 and approximately $15 billion in total.
2007 THIRD QUARTER REPORT 21
We believe that the combined trust will have the size and scale needed to develop and grow in today’s dynamic market. The combination brings together two organizations with complementary strategies, asset bases and management teams which should translate into a strong shared future. We believe the combined trust will be greater than the sum of its parts and look forward to unlocking its potential and delivering upon the value proposition it represents for our unitholders.
22 CANETIC RESOURCES TRUST
CORPORATE INFORMATION
OFFICERS AND SENIOR MANAGEMENT J. Paul Charron, CA President and Chief Executive Officer David J. Broshko, B.Comm., CA Vice President, Finance and Chief Financial Officer Richard J. Tiede, P.Eng. Chief Operating Officer Mark P. Fitzgerald, MBA, P.Eng. Vice President, Operations Brian K. Keller, B.Sc. Vice President, Exploitation Brian D. Evans, LLB Vice President, General Counsel and Secretary David M. Sterna, BA Economics Vice President, Corporate Planning and Marketing Donald W. Robson, Vice President, Land Keith S. Rockley, BA Vice President, Human Resources & Corporate Administration DIRECTORS Jack C. Lee, BA, B.Comm. ICD.D, Calgary, Alberta Chairman Robert G. Brawn, P.Eng., Calgary, Alberta Chairman, Emeritus and Director J. Paul Charron, CA, Calgary, Alberta President, Chief Executive Officer and Director W. Peter Comber,MBA, CA, Toronto, Ontario Murray M. Frame, Calgary, Alberta Daryl Gilbert, P.Eng., Calgary, Alberta Nancy M. Laird, MBA, Calgary, Alberta R. Gregory Rich,MBA, B.Sc. (Eng.), Houston, Texas AUDITORS Deloitte & Touche LLP Calgary, Alberta | INVESTOR RELATIONS Telephone: (403) 539-6300 Investor Toll Free: 1-877-539-6300 E-mail: info@canetictrust.com BANKERS Bank of Montreal The Toronto Dominion Bank Canadian Imperial Bank of Commerce The Bank of Nova Scotia Royal Bank of Canada BNP Paribas (Canada) Alberta Treasury Branches National Bank of Canada Union Bank of California, NA Deutsche Bank AG HSBC Bank Canada Société Générale (Canada) Canadian Western Bank JP Morgan Chase Bank, NA Fortis Capital (Canada) Ltd. PETROLEUM CONSULTANTS GLJ Petroleum Consultants Ltd. Calgary, Alberta Sproule Associates Ltd. Calgary, Alberta LEGAL COUNSEL Burnet, Duckworth & Palmer LLP Calgary, Alberta Dorsey & Whitney LLP New York, NY; Vancouver, BC REGISTRAR AND TRANSFER AGENT Computershare Trust Company of Canada Calgary, Alberta Computershare Trust Company, Inc. Golden, Colorado STOCK EXCHANGE LISTING Toronto Stock Exchange: CNE.UN New York Stock Exchange: CNE Debentures: 9.4% CNE.DB.A; 6.5% CNE.DB.B; 8.0% CNE.DB.C; 11.0% CNE.DB.D; 6.5% CNE.DB.E |
2007 THIRD QUARTER REPORT 23
1900, 255 – 5th Avenue SW Calgary, Alberta Canada T2P 3G6 Telephone: (403) 539-6300 Toll Free: 1-877-539-6300 Facsimile: (403) 539-6499 Email: info@canetictrust.com Website: www.canetictrust.com |