UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(MARK ONE) | ||||
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| Registration statement pursuant to Section 12(b) of the Securities Exchange Act of 1934 | ||
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| Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | ||
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| For the fiscal year ended: December 31, 2003 | ||
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| Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | ||
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Commission File Number: 333-07612 |
BAYTEX ENERGY LTD.
(Exact name of Registrant as specified in its charter)
Alberta | 1311 | Not Applicable | ||
(Province or other jurisdiction of |
| (Primary standard industrial |
| (I.R.S. employer identification |
Suite 2200, 205 – 5th Avenue S.W. |
(Address and telephone number of registrant’s principle executive offices) |
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class: NONE
Securities registered or to be registered pursuant to Section 12(g) of the Act:
NONE
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
NONE
Indicate the number of outstanding shares of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
Common Shares: |
| 1 |
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Exchangeable Shares |
| 3,724,649 |
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Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ý No o
Indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 ý Item 18 o
Contents |
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Material Modifications to the Rights of Security Holders and Use of Proceeds |
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Purchases of Equity Securities by the Issuer and Affiliated Purchases |
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PART III |
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3
SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS
Certain statements included or incorporated by reference in this annual report constitute “forward-looking statements” within the meaning of the United States Private Securities Legislation Act of 1995. Such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. When used in this annual report or in documents incorporated by reference in this annual report, the words “believe,” “anticipate,” “estimate,” “project,” “intend,” “expect,” “may,” “will,” “plan,” “should,” “would,” “contemplate,” “possible,” “attempts,” “seeks” and similar expressions are intended to identify these forward-looking statements. These forward-looking statements were based on various factors and were derived utilizing numerous assumptions and other important factors that could cause actual results to differ materially from those in the forward-looking statements. Specific forward-looking statements contained in this annual report or in the documents incorporated by reference in this annual report include, among others, statements regarding:
• our expected financial performance in future periods;
• expected increases in revenues attributable to our exploration and production activities;
• our competitive advantages and ability to compete successfully;
• our intention to continue adding value through drilling;
• our plan to diversify our production mix by expanding our natural gas operations;
• our emphasis on having a low cost structure;
• our intention to match our exploration and development capital expenditures to our cash flow;
• our reserve estimates and our estimates of the present value of our future net cash flows;
• our methods of raising capital for exploration and development of reserves;
• the factors upon which we will decide whether or not to undertake an exploration or exploitation project;
• our plans to make acquisitions;
• our expectations regarding the exploration and production potential of our properties; and
With respect to forward-looking statements contained in this annual report or in the documents incorporated by reference in this annual report, we have made assumptions regarding, among other things:
• future oil and gas prices;
• the cost of expanding our property holdings;
• our ability to obtain equipment in a timely manner to meet our demand;
• our ability to market oil and gas successfully to current and new customers;
• the impact of increasing competition; and
• our ability to obtain financing on acceptable terms.
Some of the risks that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include:
• the volatility of oil and gas prices, including the differential between the price of light and heavy oil;
• the uncertainty of estimates of oil and natural gas reserves;
• the impact of competition;
• difficulties encountered during the exploration for and production of oil and natural gas;
• the difficulties encountered in delivering oil and natural gas to commercial markets;
• changes in customer demand;
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• any decrease in investor demand for trust units;
• foreign currency fluctuations;
• the uncertainty of our ability to attract capital;
• changes in, or the introduction of new, government regulations relating to the oil and natural gas business;
• costs associated with exploring for and producing oil and natural gas;
• compliance with environmental regulations;
• liabilities stemming from accidental damage to the environment;
• loss of the services of any of our executive officers; and
• adverse changes in the economy generally.
The information contained in this annual report and in the documents incorporated by reference in this annual report, including the information provided under the heading “Risk Factors,” identifies additional factors that could affect our operating results and performance. We urge you to carefully consider those factors.
All written or oral forward-looking statements attributable to us are expressly qualified in their entirety by the foregoing cautionary statement. You are cautioned not to rely on the forward-looking statements, which speak only as of the date of this annual report. We assume no obligation to update or to publicly announce the results of any revisions to any of the forward-looking statements to reflect actual results, future events or developments, changes in assumptions or changes in other factors affecting the forward-looking statements.
DEFINITIONS AND OTHER MATTERS
As used in this annual report, the following terms have the meaning indicated:
• “bbls” and “mbbls” mean barrels and thousand barrels, respectively;
• “mcf “, “mmcf” and “bcf” mean thousand cubic feet, million cubic feet and billion cubic feet, respectively;
• “boe” and “mboe” mean barrel of oil equivalent and thousand barrels of oil equivalent, respectively;
• “bbls/d”, “mcf/d” and “boe/d” mean barrels per day, thousand cubic feet per day and barrels of oil equivalent per day, respectively;
• “ngl” means natural gas liquids; and
Developed acreage means acreage on which we have a productive well. Undeveloped acreage means acreage on which we do not have a productive well and includes exploratory acreage. Proved reserves are those reserves estimated as recoverable under current technology and existing economic conditions under constant dollar economics, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economical and technically successful in the subject reservoir. Gross proved reserves or gross production are proved reserves or production attributable to our interest before deducting royalties; net proved reserves or net production are proved reserves or production after deducting royalties. Natural gas volumes are converted to barrels of oil equivalent using the ratio of 6 thousand cubic feet of natural gas to one barrel of oil. Natural gas volumes are stated at the official temperature and pressure bases of the area in which the reserves are located.
5
Item 1. Identity of Directors, Senior Management and Advisors
Not Applicable
Item 2. Offer Statistics and Expected Timetable
Not Applicable
Item 3. Key Information
A. Selected Financial Data
The financial data set forth below as at December 31, 2003 and 2002 and for each of the years in the three-year period ended December 31, 2003 have been derived from our audited consolidated financial statements included in Item 17 of this Form 20-F. Financial data at December 31, 2001, 2000 and 1999 and for each of the years in the three-year period ended December 31, 2000 have been derived from our previously published audited consolidated financial statements not included in this document.
The financial data as at December 31, 2003 and 2002 and for each of the years in the three-year period ended December 31, 2003 should be read in conjunction with, and are qualified in their entirety by reference to, our audited consolidated financial statements.
The financial data is derived from our financial statements which have been prepared in accordance with generally accepted accounting principles in Canada (“Canadian GAAP”), the application of which, in the case of Baytex Energy Ltd., conforms in all material respects for the periods presented with generally accepted accounting principles in the United States of America (“U.S. GAAP”), except as disclosed in footnotes to the consolidated financial statements.
The following table presents a summary of our consolidated statement of operations derived from our financial statements for 2003, 2002, 2001, 2000 and 1999. All data presented below should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and accompanying notes included elsewhere in this Form 20-F.
Amounts in accordance with Canadian GAAP
(in thousands of Canadian $, except per share data)
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| December 31, |
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| 2003 |
| 2002 |
| 2001 |
| 2000 |
| 1999 |
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Petroleum and natural gas sales |
| 351,404 |
| 365,860 |
| 329,700 |
| 286,226 |
| 120,087 |
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Income (loss) from operations |
| 19,539 |
| 92,808 |
| (237,306 | ) | 75,797 |
| 25,231 |
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Net income (loss) |
| 21,376 |
| 45,136 |
| (137,107 | ) | 43,788 |
| 14,128 |
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Net income (loss) per common share: |
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basic |
| 0.60 |
| 0.86 |
| (2.77 | ) | 1.04 |
| 0.40 |
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Net income (loss) per common share: |
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diluted |
| 0.60 |
| 0.85 |
| (2.77 | ) | 1.01 |
| 0.39 |
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Total assets |
| 864,991 |
| 997,760 |
| 967,046 |
| 829,414 |
| 418,426 |
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Share capital |
| — |
| 398,176 |
| 394,734 |
| 326,767 |
| 210,426 |
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Shareholders’ equity |
| (288,546 | ) | 359,687 |
| 311,109 |
| 379,322 |
| 230,264 |
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Number of shares outstanding |
| — |
| 52,819 |
| 52,008 |
| 45,797 |
| 35,469 |
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Dividends declared |
| Nil |
| Nil |
| Nil |
| Nil |
| Nil |
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Amounts in accordance with U.S. GAAP
(in thousands of Canadian $, except per share data)
|
| December 31, |
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| 2003 |
| 2002 |
| 2001 |
| 2000 |
| 1999 |
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Petroleum and natural gas sales |
| 351,404 |
| 365,860 |
| 329,700 |
| 286,226 |
| 120,087 |
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Net income (loss) |
| (26,154 | ) | 22,889 |
| (124,936 | ) | 52,175 |
| 30,348 |
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Net income (loss) per common share: |
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basic |
| (0.73 | ) | 0.44 |
| (2.52 | ) | 1.24 |
| 0.86 |
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Net income (loss) per common share: |
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diluted |
| (0.73 | ) | 0.43 |
| (2.52 | ) | 1.20 |
| 0.84 |
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Total assets |
| 719,078 |
| 855,719 |
| 829,027 |
| 707,352 |
| 315,183 |
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Share capital |
| — |
| 412,118 |
| 408,676 |
| 340,709 |
| 224,368 |
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Shareholders’ equity |
| (437,518 | ) | 286,129 |
| 259,799 |
| 317,134 |
| 155,026 |
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Number of shares outstanding |
| — |
| 52,819 |
| 52,008 |
| 45,797 |
| 35,469 |
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Dividends declared |
| Nil |
| Nil |
| Nil |
| Nil |
| Nil |
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Exchange Rate Information
We publish our consolidated financial statements in Canadian dollars. In this annual report, except where otherwise indicated, all dollar amounts are stated in Canadian dollars. References to “$” or “Cdn.$” are to Canadian dollars and references to “US$” are to U.S. dollars. The following table sets forth for each period indicated the period end exchange rates for conversion of U.S. dollars to Canadian dollars, the average exchange rates on the last day of each month during such period and the high and low exchange rates during such period. These rates are based on the noon buying rate in New York City, expressed in U.S. dollars, for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York. The exchange rates are presented as Canadian dollars per $1.00. On May 31, 2004, the noon buying rate was US$1.00 equals Cdn. $1.3634 and the inverse noon buying rate was Cdn.$1.00 equals US$0.7335.
U.S. Dollar/Canadian Dollar Exchange Rates for Five Most Recent Financial Years
Year Ended December 31, |
| 2003 |
| 2002 |
| 2001 |
| 2000 |
| 1999 |
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End of period |
| 0.7738 |
| 0.6344 |
| 0.6285 |
| 0.6669 |
| 0.6918 |
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Average for the period |
| 0.7139 |
| 0.6372 |
| 0.6456 |
| 0.6732 |
| 0.6691 |
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7
U.S. Dollar/Canadian Exchange Rates for Previous Six Months
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| December |
| January |
| February |
| March |
| April |
| May |
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High |
| 0.7747 |
| 0.7883 |
| 0.7650 |
| 0.7659 |
| 0.7638 |
| 0.7335 |
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Low |
| 0.7447 |
| 0.7481 |
| 0.7398 |
| 0.7357 |
| 0.7301 |
| 0.7159 |
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B. Capitalization and Indebtedness
Not Applicable
C. Reasons for the Offer and Use of Proceeds
Not Applicable
D. Risk Factors
Set out below are certain risk factors that could materially adversely affect our business and our cash flow, operating results and financial condition.
Oil and natural gas prices are volatile, and low prices will adversely affect our business.
Fluctuations in the prices of oil and natural gas will affect many aspects of our business, including:
• our revenues, cash flows and earnings;
• our ability to attract capital to finance our operations;
• our cost of capital;
• the amount we are allowed to borrow under our senior credit facilities; and
• the value of our oil and natural gas properties.
Both oil and natural gas prices are extremely volatile. Any material decline in prices will result in a reduction of our net production revenue, overall value and the economics of producing from some wells. Any material decline in prices would likely also result in a reduction in our oil and natural gas acquisition and development activities.
In addition, a material decline in oil and natural gas prices from historical average prices would reduce our borrowing base under our senior credit facilities, therefore reducing amounts available to us and possibly requiring that a portion of our senior credit facilities be repaid.
You should not unduly rely on reserve information because reserve information represents estimates and our actual reserves could be lower than the estimates.
Estimates of oil and natural gas reserves involve a great deal of uncertainty, because they depend in large part upon the reliability of available geologic and engineering data, which is inherently imprecise. Geologic and engineering data are used to determine the probability that a reservoir of oil and natural gas exists at a particular location, and whether oil and natural gas are recoverable from a reservoir.
The probability of the existence and recoverability of reserves is less than 100% and actual recoveries of proved reserves usually differ from estimates.
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Estimates of oil and natural gas reserves also require numerous assumptions relating to operating conditions and economic factors, including, among others:
• the price at which recovered oil and natural gas can be sold;
• the costs associated with recovering oil and natural gas;
• the prevailing environmental conditions associated with drilling and production sites;
• the availability of enhanced recovery techniques;
• the ability to transport oil and natural gas to markets; and
• governmental and other regulatory factors, such as taxes and environmental laws.
A change in any one or more of these factors could result in known quantities of oil and natural gas previously estimated as proved reserves becoming unrecoverable and the present value of future net cash flows from estimated reserves being reduced.
In addition, estimates of reserves and future net cash flows expected from them prepared by different independent engineers or by the same engineers at different times, may vary substantially.
In addition, in accordance with Canadian GAAP, we could be required to write down the carrying value of our oil and natural gas properties if oil and natural gas prices become depressed for even a short period of time, or if there are substantial downward revisions to our quantities of proved reserves. A write down would result in a charge to earnings and a reduction of shareholders’ equity.
Our heavy oil production increases our susceptibility to low oil prices, because the price we receive for heavy oil is lower than for light oil.
The price we receive for heavy oil is lower than for light oil. In addition, seasonal fluctuation in demand for heavy oil affects the price differential between light and heavy oil. One of the main by-products from refining heavy oil is asphalt that is used in road paving. In general, municipal, state and provincial governments, particularly in Canada and the northern states of the United States, expend the majority of their budgets for road infrastructure improvements during the spring and summer months. Thus, the demand from the refineries to process heavy oil is the strongest during this period, which usually leads to higher prices for heavy oil in the spring and summer months. The effect of an increase in the price differential between light and heavy oil could adversely affect the profitability of heavy oil compared to light oil.
If we are unsuccessful in acquiring and developing oil and gas properties, we will be prevented from increasing our reserves and our business will be adversely affected because we will eventually run out of reserves.
The successful acquisition and development of oil and gas properties requires an assessment of:
• recoverable reserves;
• future oil and gas prices and operating costs;
• potential environmental and other liabilities; and
• productivity of new wells drilled.
These assessments are inexact and if they are made too inaccurately, we will not recover the purchase price of a property from the sale of production from the property, or will not recognize an acceptable return from properties we acquire.
In addition, the costs of exploitation and development could materially exceed initial estimates.
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We will not be able to develop our reserves or make acquisitions if we are unable to generate sufficient cash flow or raise capital. If we are unable to increase our reserves, our business will be adversely affected because we will eventually run out of reserves.
We will be required to make substantial capital expenditures to develop our existing reserves, to discover new oil and gas reserves and to make acquisitions. We will be unable to accomplish these tasks if we are unable to generate sufficient cash flow or raise capital in the future.
Drilling activities are subject to many risks and any interruption or lack of success in our drilling activity will adversely affect our business because drilling is expensive and a lack of success will prevent us from increasing our reserves.
Drilling activities are subject to many risks, including the risk that no commercially productive and profitable reservoirs will be encountered and that we will not recover all or any portion of our investment. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations could be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond our control, including:
• adverse weather conditions;
• compliance with governmental requirements; and
• shortages or delays in the delivery of equipment and services.
Our operations are affected by operating hazards and uninsured risks and a shutdown or slowdown of our operations will adversely affect our business.
There are many operating hazards in exploring for and producing oil and natural gas, including:
• our drilling operations could encounter unexpected formations or pressures that could cause damage to equipment or personal injury;
• we could experience blowouts, accidents, oil spills, fires or other damage to a well that could require us to redrill it or take other corrective action;
• we could experience equipment failure that curtails or stops production;
• our drilling and production operations, such as trucking of oil, are often interrupted by bad weather; and
• we would be unable to access our properties or conduct our operations due to surface conditions.
Any of these events could result in damage to or destruction of oil and natural gas wells, production facilities or other property, or injury to persons. In addition, any of the above events could result in environmental damage or personal injury for which we will be liable.
The occurrence of a significant event not fully insured or indemnified against could seriously harm our financial condition and operating results.
Our hedging activities could result in losses.
The nature of our operations results in exposure to fluctuations in commodity prices. We monitor and, when appropriate, utilize derivative financial instruments and physical delivery contracts to hedge our exposure to these risks. We are exposed to credit-related losses in the event of non-performance by counter-parties to the financial instruments. From time to time we enter into hedging activities in an effort to mitigate the potential impact of declines in oil and natural gas prices. You should also refer to Item 5 of this annual report entitled “Risk and Risk Management”.
If product prices increase above those levels specified in our various hedging agreements, the fixed price will limit us from receiving the full benefit of commodity price increases.
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In addition, by entering into these hedging activities, we will suffer financial loss if:
• we are unable to produce oil or natural gas to fulfill our obligations;
• we are required to pay a margin call on a hedge contract; or
• we are required to pay royalties based on a market or reference price that is higher than our fixed or ceiling price.
In 2003, we incurred $33.8 million in losses due to hedging. In 2002, we incurred $8.3 million in losses due to hedging.
Complying with environmental and other government regulations could be costly and could negatively impact our production.
Our operations are governed by numerous Canadian laws and regulations at the provincial and federal level. These laws and regulations govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues.
Under these laws and regulations, we could be liable for personal injury, clean-up costs, remedial measures and other environmental and property damages, as well as administrative, civil and criminal penalties. We do not believe that insurance coverage for the full potential liability of environmental damages is available at a reasonable cost, so we could be liable, or could be required to cease production on properties, if environmental damage occurs.
It is possible that the costs of complying with environmental laws and regulations in the future will have a material adverse effect on our financial condition or results of operations. Furthermore, future changes in environmental laws and regulations could result in materially increased costs for us, stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.
Certain factors beyond our control can affect our ability to market production. Since we cannot fully protect ourselves from these factors, the impact of them, if serious, could adversely affect our business.
Our ability to market oil and gas from our wells depends upon numerous factors beyond our control. These factors include:
• the availability of capacity to refine heavy oil;
• the availability of natural gas processing capacity;
• the availability of pipeline capacity;
• the supply of and demand for oil and natural gas;
• the availability of alternative fuel sources;
• the availability of diluent to blend with heavy oil to enable transportation;
• the effects of inclement weather;
• Canadian federal and provincial regulation of oil and natural gas marketing; and
• Canadian federal regulation of natural gas sold or transported outside of the province of Alberta.
Because of these factors, we could be unable to market all of the oil or gas we produce. In addition, we could be unable to obtain favorable prices for the oil and gas we produce.
The oil and natural gas industry is highly competitive.
We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other organizations, many of which may have greater technical and
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financial resources than we do. Some of these organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market oil and other products on a worldwide basis. As a result of these complementary activities, some of our competitors may have greater and more diverse competitive resources to draw on than we do. Given the highly competitive nature of the oil and natural gas industry, this could adversely affect the market price of our trust units and distributions to unitholders.
Our current credit facilities and any replacement credit facilities may not provide sufficient liquidity.
Baytex has credit facilities in the amount of $165 million. Variations in interest rates and scheduled principal payments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust. Although it is believed that the bank line of credit is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of Baytex or that additional funds can be obtained.
The industry in which we operate exposes us to potential liabilities that may not be covered by insurance.
Our operations are subject to all of the risks associated with the operation and development of oil and natural gas properties, including the drilling of oil and natural gas wells, and the production and transportation of oil and natural gas. These risks include encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, cratering, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires and spills. A number of these risks could result in personal injury, loss of life, or environmental and other damage to our property or the property of others. We cannot fully protect against all of these risks, nor are all of these risks insurable. We may become liable for damages arising from these events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. Any costs incurred to repair these damages or pay these liabilities would reduce funds available for distribution to unitholders.
The operation of oil and natural gas wells could subject us to environmental claims and liability.
The oil and natural gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal legislation. A breach of that legislation may result in the imposition of fines or the issuance of “clean up” orders. Legislation regulating the oil and natural gas industry may be changed to impose higher standards and potentially more costly obligations. For example, the 1997 Kyoto Protocol to the United Nation’s Framework Convention on Climate Change, known as the Kyoto Protocol, was ratified by the Canadian government in December, 2002 and will require, among other things, significant reductions in greenhouse gases. The impact of the Kyoto Protocol on us is uncertain and may result in significant additional costs (future) for our operations. Although we record a provision in our financial statements relating to our estimated future environmental and reclamation obligations, we cannot guarantee that we will be able to satisfy our actual future environmental and reclamation obligations.
We are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms.
Accordingly, our properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons. Any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of cash flow and, therefore, will reduce the amounts available for distribution to unitholders. Should we be unable to fully fund the cost of remedying an environmental problem, we might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.
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We may undertake acquisitions that could limit our ability to manage and maintain our business, result in adverse accounting treatment and are difficult to integrate into our business. Any of these events could result in a material change in our liquidity, impair our ability to pay dividends and could adversely affect the value of your investment.
A component of future growth will depend on the ability to identify, negotiate, and acquire additional companies and assets that complement or expand existing operations. However we may be unable to complete any acquisitions, or any acquisitions we may complete may not enhance our business. Any acquisitions could subject us to a number of risks, including:
• diversion of management’s attention;
• inability to retain the management, key personnel and other employees of the acquired business;
• inability to establish uniform standards, controls, procedures and policies;
• inability to retain the acquired company’s customers;
• exposure to legal claims for activities of the acquired business prior to acquisition; and inability to integrate the acquired company and its employees into our organization effectively.
Since we are a Canadian company and all of our assets and key personnel are located in Canada, you may not be able to enforce a U.S. judgment for claims you may bring against us, our assets, our key personnel or many of the experts named in this annual report. This may prevent you from receiving compensation to which you would otherwise be entitled.
We have been organized under the laws of Alberta, Canada and all of our assets are located outside the U.S. In addition, the members of our Board of Directors and our officers are residents of countries other than the U.S. As a result, it may be impossible for you to effect service of process upon us or these individuals within the U.S. or to enforce any judgments in civil and commercial matters, including judgments under U.S. federal securities laws. In addition, a Canadian court may not permit you to bring an original action in Canada or to enforce in Canada a judgment of a U.S. court based upon civil liability provisions of the U.S. federal securities laws.
Item 4. Information on the Company
A. History and Development of the Company
The head office of Baytex Energy Ltd. (“Baytex” or the “Company”) is located at Suite 2200, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 2V7, telephone (403) 269-4828 and its registered office is located at Suite 1400, 350 – 7th Avenue S.W., Calgary, Alberta T2P 3N9, telephone (403) 260-0100.
Baytex was incorporated in Canada under the Business Corporations Act (Alberta) on June 3, 1993. On August 5, 1993, Baytex filed Articles of Amendment to delete the private company restrictions thereunder. On October 13, 1993, Articles of Amendment were filed to amend Baytex’s capital structure to create Class A Shares and Class B Non-Voting Shares. On October 21, 1997, Baytex filed Articles of Amalgamation to amalgamate with its wholly-owned subsidiary, Dorset Exploration Ltd. On May 28, 1999, Baytex filed Articles of Amendment to eliminate the Class B Shares and to change the designation of the Class A Shares in the share capital of Baytex from “Class A Shares” to “common shares”.
In May 2001, Baytex acquired all of the issued and outstanding shares of OGY Petroleums Ltd. (“OGY”), a public oil and gas company, the shares of which were listed on the TSX. The total consideration paid by Baytex for OGY was $50.7 million in cash and 1.2 million Baytex common shares. The operations of OGY concentrated on light oil and natural gas in central Alberta.
13
Also in May 2001, Baytex acquired all of the issued and outstanding shares of Triumph Energy Corporation (“Triumph”), a public oil and gas company, the shares of which were listed on the TSX. The total consideration paid for Triumph was $82.3 million in cash and 4.9 million Baytex common shares. The operations of Triumph were focused on the exploration and development of natural gas in Central Alberta and light oil and natural gas in East Central and Southern Alberta.
On January 1, 2002, Baytex filed Articles of Amalgamation to amalgamate with its wholly-owned subsidiaries, OGY and Triumph.
Additional heavy oil assets were acquired in the Cold Lake, Alberta and Carruthers, Saskatchewan areas in three separate property acquisitions in 2001 and 2002 for total cash consideration of $73.4 million.
In the fourth quarter of 2001 and first quarter of 2002, Baytex executed a plan to strengthen its balance sheet with the divestiture of certain oil and natural gas assets. This plan included the sale of light oil and natural gas assets for total proceeds of $101 million. This was later augmented in the first quarter of 2003 with the completion of the sale of natural gas assets in the Ferrier/O’Chiese area for proceeds of $133.3 million. Proceeds of the asset sales were applied to reduce outstanding indebtedness.
On September 2, 2003, Baytex completed a Plan of Arrangement (the “Arrangement”) whereby holders of common shares of Baytex elected or were deemed to have elected to receive either trust units (the “Trust Units”) of Baytex Energy Trust (the “Trust”) or exchangeable shares of Baytex (the “Exchangeable Shares”) for their common shares on the basis of one Trust Unit or Exchangeable Share, respectively, for each common share held. Coincident with the Arrangement becoming effective, certain of Baytex’s exploration assets were acquired by Crew Energy Inc. (“Crew”), and the common shares of Crew were distributed to the former holders of Baytex common shares on the basis of one-third of a common share of Crew for each such share held. The estimated fair market value at September 2, 2003 of the securities issued during the reorganization was $11.76 per Trust Unit and $0.55 per one-third of a common share of Crew.
On September 2, 2003, Baytex was amalgamated with Baytex Acquisition Corp. pursuant to the Arrangement.
We are an intermediate oil and gas company engaged in the exploration, development and production of oil and natural gas. We operate substantially all of our production in two core project areas in the provinces of Alberta and Saskatchewan, Canada. We have acquired our land holdings through government land sales, freehold acquisitions, drilling on farm-in lands and property and corporate acquisitions. We focus on building our asset base through land assembly, acquisitions of seismic data and exploratory and development drilling. Our drilling efforts are concentrated on properties that we believe will provide long lived reserves that will generate cash flow in the near term. We continually look for opportunities to enhance our position in our core areas and intend to pursue strategic acquisitions that are within the operating and financial parameters that we have established. See also Item 4 “Property, Plants and Equipment”.
The Trust is the holder of the common share of Baytex. Certain former shareholders of Baytex own Exchangeable Shares in accordance with the elections made by such shareholders under the Arrangement. Baytex continues to carry on an oil and natural gas business similar to that carried on by Baytex prior to the Arrangement becoming effective. Baytex owns, directly or indirectly, all of the assets that were owned by Baytex prior to the Arrangement becoming effective, other than certain oil and gas and exploration assets that were transferred to Crew in accordance with the Arrangement.
14
Inter-Corporate Relationships
The following table provides the name, the percentage of voting securities owned by Baytex and the jurisdiction of incorporation, continuance or formation of these subsidiaries either, direct and indirect, as at the date hereof.
|
| Percentage of voting securities |
| Jurisdiction of |
|
Baytex Energy (USA) Inc. |
| 100 | % | Delaware |
|
Baytex Marketing Ltd. |
| 100 | % | Alberta |
|
D. Property, Plants and Equipment
The following is a description of Baytex’s principal oil and natural gas properties on production or under development as at January 1, 2004. The term “net”, when used to describe Baytex’s share of production, means the total of Baytex’s working interest share before deduction of royalties owned by others. Reserve amounts are stated, before deduction of royalties, at January 1, 2004, based on forecast cost and price assumptions (gross) as evaluated in the independent reserve evaluators (see “ Reserves and Present Value Summary”). Unless otherwise specified, gross and net acres and well count information are as at January 1, 2004. Information in respect of current production is average production, net to Baytex, for the year ended December 31, 2003, except where otherwise indicated. Information related to land holdings is at December 31, 2003.
The crude oil and natural gas properties in which Baytex has an interest are within two districts in Alberta and Saskatchewan. Each district constitutes a well-balanced portfolio of operated properties and development prospects with considerable upside potential.
15
Heavy Oil District
The Heavy Oil District accounts for approximately two-thirds of Baytex’s current production and approximately three-quarters of reserves. Heavy oil operations consist largely of cold conventional production from wells with multi-zone potential. Production is generated primarily from vertical, slant and horizontal wells using progressive cavity pump technology to generate large volumes of heavy oil combined with gas, water and sand. Production from these wells usually averages between 40 and 100 Bbls/d of low gravity crude ranging from 11 to 18 API. Once produced, the oil is trucked or pipelined to markets in both Canada and the United States for upgrading into lighter grades of crude or refined into petroleum products such as fuel oil, lubricants and asphalt.
During 2003, production in the Heavy Oil District averaged 25,676 Boe/d made up of 23,911 Bbls/d of heavy oil and 10.6 Mmcf/d of natural gas. Baytex drilled 174 gross (165.2 net) wells in the district, resulting in 159 gross (150.2 net) oil wells, four gas wells, four service wells, and seven dry and abandoned wells for a success rate of 96 percent.
Baytex possesses a vast inventory of development projects in the west central Saskatchewan heavy oil region and the Cold Lake, Ardmore and Seal areas of north central Alberta. The ability to generate replacement production through conventional drilling methods allows Baytex to better control the cost and timing of its capital investments.
Baytex will continue to build value through internal property development and selective acquisitions. Future heavy oil activity will focus on the development of the Seal and Ardmore Properties along with continued infill drilling at adjacent Cold Lake and throughout the Saskatchewan Properties.
Ardmore: Ardmore is one of the key heavy oil development and production areas for Baytex. Acquired in 2002, this year-round access area generated approximately 3,100 Bbls/d of oil in 2003, with current production in excess of 4,500 Bbls/d. Since acquiring this property, Baytex has applied leading-edge heavy oil drilling and production technology to improve production and reduce cost. Wells in the area are 100 percent owned and operated by Baytex and they are able to produce up to 300 Bbls/d of 11 to 13 API heavy crude oil primarily from the McLaren and Sparky formations. Baytex drilled 48 gross (47.6 net) oil wells in the area during 2003, resulting in 47 gross (46.6 net) oil wells and one service well. Baytex holds approximately 32,000 net acres of 100 percent working interest undeveloped land in this area.
Cold Lake: Baytex acquired the Cold Lake heavy oil property in 2001. This year-round drilling area is located on Cold Lake First Nations Land with heavy oil production generated largely from the Colony formation. Average production was 935 Bbls/d during 2003. Baytex drilled 15 gross (13.5 net) operated oil wells in the Cold Lake area during 2003 and holds 19,500 net acres of undeveloped land.
16
Seal: The Seal property is a highly prospective heavy oil area for Baytex. The property is located in the Peace River oilsands area of northwest Alberta. Baytex holds 100 percent working interests in approximately 58 sections of land of which 44 sections were acquired in 2003. The Seal oil deposits can be produced through horizontal wells using primary production technology without the use of capital intensive steam injection methods. Baytex completed a seven-well test program during the first quarter of 2004. A development plan for a pilot production is being designed for the second half of 2004 and the winter of 2005.
Tangleflags: Baytex acquired the Tangleflags property through the acquisition of Bellator Exploration Inc. in 2000. Tangleflags is characterized by multiple-zone reservoirs with production from the Colony, McLaren, Waseca, Sparky, General Petroleum and Lloydminster formations. Provincial government regulations generally prohibit production from more than one formation at a time. As such, this property possesses long-term development potential with a considerable number of up-hole completion opportunities. Average production during 2003 was 4,940 Bbls/d of heavy oil and 1.6 Mmcf/d of natural gas.
Carruthers: The Carruthers property was obtained by Baytex in 1997 through the merger with Dorset Exploration Ltd. The property consists of two separate pools in the Cummings formation. During 2003, average production was 3,300 Bbls/d of heavy oil and 0.6 Mmcf/d of natural gas. Baytex drilled 35 gross (29.75 net) oil wells in the Carruthers area during 2003, resulting in 33 gross (27.75 net) oil wells and 2 dry holes for an overall drilling success rate of 94 percent. Baytex has continued to develop the southern pool since 1999, with 15 to 20 locations planned for 2004.
Marsden/Silverdale: The Marsden/Silverdale area of Saskatchewan is characterized by quality oil of 13 to 18 API and production averaging 100 Bbls/d per well. The lighter gravity oil allows production to be flow-lined to treating and disposal facilities thereby reducing trucking costs. Lower trucking costs, combined with characteristically low sand production, result in lower overall operating costs. Production averaged 3,400 Bbls/d of oil and 1.1 Mmcf/d of natural gas during 2003. Baytex drilled 9 oil wells in the area during 2003, with 100 percent success. Baytex has approximately 12,000 net acres of undeveloped land in the Marsden/Silverdale area.
Conventional Oil and Gas District
The Conventional Oil and Gas District includes Properties located in Alberta producing light and medium gravity crude oil, natural gas and related liquids. Production in this district averaged 11,010 Boe/d for the year ended December 31, 2003, consisting of 2,273 Bbls/d of oil and natural gas liquids and 52.4 Mmcf/d of natural gas.
Excluding production from the Ferrier area, which was sold in March 2003, and production from the properties which were transferred to Crew pursuant to the Arrangement, production in this district averaged 1,860 Bbls/d of oil and natural gas liquids and 45.2 Mmcf/d of natural gas, or 9,400 Boe/d during 2003.
Leahurst: Baytex began operations in the Leahurst area in 1993. Production in the area is primarily natural gas from the Belly River and lower Mannville formations. Baytex holds approximately 19,000 net acres of land in the area, interests in two gas plants and a 100-km gathering system. In 2003, Baytex drilled 7.8 net successful natural gas wells. The Leahurst area has year-round access, which allows Baytex to conduct continuous development activities. Baytex’s average production for 2003 was 7.3 Mmcf/d of natural gas in this area.
Red Earth/Goodfish: Baytex commenced operations in this area through the merger with Dorset Exploration Ltd. in 1997. Production includes light oil from the Slave Point and Granite Wash formations and natural gas from the Bluesky formation. In 2003, Baytex drilled 10.2 net wells in the area resulting in 5 net oil wells and 5
17
net natural gas wells. Baytex holds approximately 58,000 net acres of undeveloped land in this area. Baytex’s average production in 2003 was 1,000 Bbls/d of light oil and 9.8 Mmcf/d of natural gas.
Nina/Darwin: Baytex began operations in the Darwin area in 1998, targeting natural gas from the Bluesky formation. Production from Nina commenced in March 2001. Baytex holds approximately 34,000 net acres of land in the area. Average production in this area in 2003 was 4.9 Mmcf/d of natural gas.
Bon Accord: The Bon Accord natural gas property was acquired by Baytex in 1997 through the merger with Dorset Exploration Ltd. Baytex utilizes 3-D seismic technology to identify gas-producing zones in the Mannville, Nisku and Sparky formations. Baytex drilled 8 wells in the Bon Accord area during 2003, resulting in 5 natural gas wells and 1 oil well. Average production was 8.4 Mmcf/d of natural gas and 360 Bbls/d of oil and natural gas liquids. Baytex has approximately 13,000 net acres of land in this area.
Hamburg/Chinchaga: Baytex constructed a natural gas processing plant in this area during 2003 with processing capacity of 8.0 Mmcf/d. Baytex’s production in the area averaged approximately 5 Mmcf/d during 2003, leaving approximately 3 Mmcf/d of plant capacity for third-party processing which is expected to be filled by the end of the first quarter of 2004. Baytex has had success targeting natural gas in the Slave Point, Bluesky and Gilwood formations. Drilling activity in 2003 resulted in two successful natural gas wells. Net landholdings in the area total 17,500 acres as at December 31, 2003.
Reserves and Present Value Summary
Baytex is required to comply with the National Instrument 51-101, (“NI 51-101”) issued by the Canadian Securities Administrators, in all its reserves related disclosures. NI 51-101 came into effect on September 30, 2003 and is applicable for financial years ended on or after December 31, 2003. The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of oil and gas activities by reporting issuers and elevate reserves reporting to a higher level of accountability. NI 51-101 brought about significant changes in which Canadian reporting issuers manage and publicly disclose information relating to their oil and gas reserves, mandates annual disclosure requirements and prescribes new reserve definitions as follows:
NI 51-101 requires a higher degree of confidence in the assignment of oil and gas reserves. Under NI 51-101, proved reserves are defined to have a 90% probability that the actual reserves recovered will equal or exceed the assigned estimates compared to the previous definition of “reasonable certainty” as stipulated by National Policy 2-B (“NP 2-B”). Also, under NI 51-101, probable reserves are defined to have a 50% probability that the actual reserves recovered will equal or exceed the assigned estimates compared to the previous definition of “likelihood of existence” in NP 2-B. Because of the more stringent requirements under NI 51-101, the industry has adopted the interpretation that the new proved plus probable (P-50) reserves represent the most “realistic” estimates of remaining recoverable reserves. The following reserves information also adopts the general industry practice of comparing the new P-50 reserves to the previous proved plus risk adjusted (50%) probable reserves, commonly referred to as “established reserves”, under NP 2-B.
In the United States, registrants [other than foreign private issuers] are required to disclose reserves using the standards contained in U.S. Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with United States Statement of Financial Accounting Standards No.69 “Disclosures About Oil and Gas Producing Activities’’ (“FAS 69’’). As a foreign private issuer, Baytex is permitted to comply with the disclosure requirements contained in NI 51-101 for the purposes of its U.S. regulatory filings. Unless otherwise indicated, all of the reserves and production information disclosure in this Form 20-F is in compliance with NI 51-101.
The primary differences between the U.S. requirements and the NI 51-101 requirements are that (i)the U.S. standards require disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves, and (ii) the U.S. standards require that the reserves and related future net revenue be
18
estimated under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made, whereas NI 51-101 requires disclosure of proved reserves and the related future net revenue estimated using constant prices and costs as at the last day of the financial year, and of proved and probable reserves and related future net revenue using forecast prices and costs. The definitions of proved reserves also differ, but according to the Canadian Oil and Gas Evaluation Handbook (the reference source for the definition of proved reserves under NI 51-101), differences in the estimated proved reserve quantities based on constant prices should not be material. Baytex believes that the definition and measurement of proved reserves under NI 51-101 will be more conservative than proved reserves under U.S. standards.
In this Form 20-F, certain natural gas volumes have been converted to barrels of oil equivalent (“BOEs’’) on the basis of six thousand cubic feet to one barrel. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent equivalency at the well head.
Reserve volumes and values at January 1, 2004 are based on Baytex’s interest in its total proved and probable reserves prior to royalties as defined in NI 51-101. Reserve volumes and values for previous years are based on “established” (proved plus 50% probable) reserves prior to deduction of royalties. Under those definitions, probable reserves were discounted by an arbitrary risk factor of 50% in reporting established reserves. Under NI 51-101 reserves definitions, estimates are prepared such that the full proved and probable reserves are estimated to be recoverable (proved plus probable reserves are effectively a “most likely case”). As such, the probable reserves now reported are already “risked”.
Baytex has its reserves evaluated by independent engineers every year. Baytex’s 2003 reserves were independently evaluated as at January 1, 2004 by Sproule Associates Limited (“Sproule”) for all its properties.
The following table shows our oil and natural gas proved reserves based on constant prices. All of the oil and natural gas proved reserves are located in Canada. Oil reserves are expressed in millions of barrels and natural gas reserves in billions of cubic feet.
|
| January 1, |
| December 31, |
| ||||||||
2002 |
| 2001 | |||||||||||
|
| Oil |
| Gas |
| Oil |
| Gas |
| Oil |
| Gas |
|
Net proved reserves |
| 56.6 |
| 66.3 |
| 95.5 |
| 120.1 |
| 95.1 |
| 105.8 |
|
Net proved developed reserves |
| 39.4 |
| 63.1 |
| 61.4 |
| 105.1 |
| 59.1 |
| 96.6 |
|
Long-term Supply Contract
In October 2002, we entered into a long-term crude oil supply contract with a third party that requires the delivery of up to 20,000 barrels per day of Lloydminster Blend crude oil at a price fixed at 71% of NYMEX WTI oil price. The contract is for an initial term of five years commencing January 1, 2003. The contract volumes increased from 9,000 barrels per day in January 2003 to 20,000 barrels per day in October 2003 and thereafter.
Production
The following table summarizes Baytex’s working interest production during the periods indicated:
|
| Years Ended December 31, |
| ||||
|
| 2003 |
| 2002 |
| 2001 |
|
Oil and NGL (bbls/d) |
| 26,184 |
| 27,121 |
| 31,685 |
|
Natural gas (mmcf/d) |
| 63.0 |
| 72.6 |
| 70.8 |
|
Total (BOE/d) |
| 36,686 |
| 39,214 |
| 43,488 |
|
19
Industry Conditions
General
The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect the operations of the Company in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Company unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.
Pricing and Marketing Oil and Natural Gas
The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends in part on oil quality, prices of competing oils, distance to market, the value of refined products and the supply/demand balance. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council.
The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than 2 years or for a term of 2 to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council.
The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve ability, transportation arrangements and market considerations.
The lack of firm pipeline capacity continues to limit the ability to produce and market natural gas production although pipeline expansions are ongoing. In addition, the prorationing of capacity on the interprovincial pipeline systems continues to limit oil exports.
The North American Free Trade Agreement
The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, United States of America and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada United States Free Trade Agreement. Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export
20
price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.
NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.
Provincial Royalties and Incentives
In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.
From time to time the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry.
In the Province of Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta royalty tax credit (“ARTC”) program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per m3 and 25% at prices at and above $210 per m3. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate will be established quarterly based on the average “par price”, as determined by the Alberta Department of Energy for the previous quarterly period.
Crude oil and natural gas royalty programs for specific wells and royalty reductions reduce the amount of Crown royalties paid by the Trust’s operating subsidiaries to the provincial governments. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties.
Land Tenure
Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms from two years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of
21
provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.
Environmental legislation in the Province of Alberta has been consolidated into the Alberta Environmental Protection and Enhancement Act (the “APEA”), which came into force on September 1, 1993. The APEA imposes stricter environmental standards, requires more stringent compliance, reporting and monitoring obligations and significantly increases penalties. The Trust is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment and will be taking such steps as required to ensure compliance with the APEA and similar legislation in other jurisdictions in which it operates. The Company believes that it is in material compliance with applicable environmental laws and regulations. The Company also believes that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.
In December 2002 the Government of Canada ratified the Kyoto Protocol. This protocol calls for Canada to reduce its greenhouse gas emissions to 6 percent below 1990 levels during the period between 2008 and 2012. The protocol will only become legally binding when it is ratified by at least 55 countries, covering at least 55 percent of the emissions addressed by the protocol. If the protocol becomes legally binding, it is expected to affect the operation of all industries in Canada, including the oil and gas industry. As details of the implementation of this protocol have yet to be announced, the effect on the Company cannot be determined at this time.
Item 5: Operating and Financial Review and Prospects
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis, dated June 29, 2004, should be read in conjunction with Baytex’ audited consolidated financial statements for the fiscal years ended December 31, 2003 and 2002. Per barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
The financial results of the Company for 2003 were impacted by the Arrangement. The net loss for the year ended December 31, 2003 included $18.9 million of costs related to the reorganization under the Arrangement. The loss for the year also included $44.8 million of costs related to redemption and exchange of notes. These items were offset by a foreign exchange gain of $52.1 million on our U.S. denominated debt.
Crude oil prices remained strong in 2003 as supply and demand fundamentals supported higher prices. Instability in the Middle East, growing demand and low inventory levels kept average WTI at US$31.04/bbl. The oil price received by Baytex averaged $26.36 per barrel for 2003. Natural gas prices received averaged $6.07 per mcf for 2003. The overall higher prices offset lower oil and gas production during 2003. Production was lower during 2003 as certain properties were transferred to Crew under the Arrangement.
The strengthening Canadian dollar relative to the U.S. dollar impacted our net income, as revenues and realized commodity prices, referenced in U.S. dollars, were lower when translated to Canadian dollars. However, we benefit as our fixed-rate debt is denominated in U.S. dollars so this debt is reduced with a strengthening Canadian dollar.
Baytex evaluates performance based on net income and cash flow from operations. Cash flow from operations is not a measure based on generally accepted accounting principles, but is a financial term commonly used in the oil and gas industry. It represents cash generated from operating activities before changes in non-cash working capital, deferred charges and other assets and deferred credits. Baytex considers it a key measure of performance as it demonstrates the ability of the Company to generate the cash flow necessary to fund future distributions to unitholders and capital investments.
Results of Operations 2003 compared to 2002
Production Baytex’s average production for fiscal 2003 decreased by six percent to 36,686 boe per day from 39,214 boe per day for fiscal 2002. This decrease was the result of property dispositions that occurred at the end of the first quarter of 2003 and the transfer of the petroleum and natural gas assets to Crew under the Plan of Arrangement effective September 2, 2003.
Light oil production decreased 28 percent to 2,273 barrels per day during 2003 from 3,154 barrels per day in 2002. Heavy oil production during 2003 was 23,911 barrels per day, consistent with production of 23,967 barrels per day during fiscal 2002. Natural gas production for 2003 decreased by 13 percent to 63.0 million cubic feet per day compared to 72.6 million cubic feet per day for the prior year.
22
Production by Area |
| Light Oil |
| Heavy Oil |
| Natural Gas |
| Barrels of Oil |
|
|
| (bbls/d) |
| (bbls/d) |
| (mmcf/d) |
| (boe/d) |
|
2003 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| — |
| 23,911 |
| 10.6 |
| 25,676 |
|
Conventional Oil and Gas District |
| 2,273 |
| — |
| 52.4 |
| 11,010 |
|
Total Production |
| 2,273 |
| 23,911 |
| 63.0 |
| 36,686 |
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| — |
| 23,967 |
| 10.5 |
| 25,710 |
|
Conventional Oil and Gas District |
| 3,154 |
| — |
| 62.1 |
| 13,504 |
|
Total Production |
| 3,154 |
| 23,967 |
| 72.6 |
| 39,214 |
|
Revenue Petroleum and natural gas sales for 2003 decreased by four percent to $351.4 million from $365.9 million for fiscal 2002. Benchmark WTI crude oil averaged US$31.04 per barrel for 2003, representing a 19 percent increase over the US$26.08 per barrel for 2002. Correspondingly, the Trust’s light oil and NGLs price increased to $39.04 per barrel from $33.86 per barrel in 2002. The heavy oil price decreased five percent to $25.12 per barrel in 2003 from $26.39 per barrel in 2002, principally due to the increase in heavy oil differentials. Natural gas prices were 54 percent higher in 2003, averaging $6.07 per thousand cubic feet compared to $3.94 per thousand cubic feet during the previous year. Overall, after accounting for financial derivative contracts, the Trust averaged $26.72 per boe for 2003, a 4 percent increase from $25.56 per boe received in the prior year. For the per-sales-unit calculations, heavy oil sales for 2003 were 650 barrels per day lower than the production for the year due to inventory in transit under the Frontier supply agreement.
For 2003, light oil revenue decreased 17 percent over 2002, as the 15 percent increase in wellhead prices were offset by a 28 percent decrease in production. Revenue from heavy oil decreased eight percent due to a five percent decrease in wellhead prices and a three percent decrease in sales volumes. Natural gas revenue increased 34 percent as the 13 percent production decreased was offset by a 54 percent increase in wellhead prices.
Gross Revenue Analysis |
| 2003 |
| 2002 |
| ||||
|
| $ thousands |
| $/Unit (1) |
| $ thousands |
| $/Unit (1) |
|
Light oil |
| 32,393 |
| 39.04 |
| 38,985 |
| 33.86 |
|
Heavy oil |
| 213,297 |
| 25.12 |
| 230,874 |
| 26.39 |
|
Derivative contract loss |
| (33,777 | ) | (3.62 | ) | (10,622 | ) | (1.07 | ) |
Total oil revenue |
| 211,913 |
| 22.74 |
| 259,237 |
| 26.19 |
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue |
| 139,491 |
| 6.07 |
| 104,284 |
| 3.94 |
|
Derivative contract gain |
| — |
| — |
| 2,339 |
| 0.09 |
|
Total natural gas revenue |
| 139,491 |
| 6.07 |
| 106,623 |
| 4.03 |
|
|
|
|
|
|
|
|
|
|
|
Total revenue (boe @ 6:1) |
| 351,404 |
| 26.72 |
| 365,860 |
| 25.56 |
|
(1) Per-unit oil revenue is in $/bbl; per unit natural gas revenue is in $/mcf.
Royalties For the year ended December 31, 2003, royalties decreased eight percent to $54.2 million from $58.9 million last year and were 15.4 percent of sales compared to 15.7 percent of sales in 2002. A portion of the royalties paid during 2003 were reimbursed by the Trust, resulting in a lower royalty rate. Before the reimbursement by the Trust, royalties for 2003 were 17.8 percent of sales for light oil, 13.8 percent for heavy
23
oil and 22.9 percent for natural gas. These rates compared to 16.7 percent, 13.9 percent and 19.5 percent, respectively, for 2002.
Operating Expenses Operating expenses for the year 2003 increased 14 percent to $86.0 million from $75.2 million for 2002. This increase is attributable to the disposition of properties with lower operating costs and a general increase in field operating costs. Operating expenses were $6.54 per boe for 2003 compared to $5.26 per boe for the prior year. Operating expenses were $8.32 per barrel of light oil, $7.34 per barrel of heavy oil and $0.73 per thousand cubic feet of natural gas for 2003 versus $5.83, $5.99 and $0.61, respectively, for 2002.
General and Administrative Expenses General and administrative expenses for 2003 were $8.9 million, compared to $6.7 million a year ago. On a sales-unit basis, these expenses increased to $0.67 per boe from $0.47 per boe. In accordance with the full-cost accounting policy, $4.4 million of expenses were capitalized in 2003, compared with $6.7 million capitalized in 2002. The amount of capitalized expenses has been reduced due to lower exploration activity since the effective date of the Arrangement.
Stock-based Compensation Baytex accounts for compensation expense based on the fair value of rights granted to its employees under the Trust’s unit-based compensation plan. As the Trust is unable to determine the fair value of the rights granted, compensation expense has been determined based on the intrinsic value of the rights at the exercise date or at the date of the consolidated financial statements for unexercised rights. Compensation expense of $0.22 million was recorded as compensation expense for all trust unit rights granted on or after January 1, 2003.
Compensation expense was also calculated on the stock options outstanding prior to the Plan of Arrangement. Compensation expense of $0.52 million was recorded as compensation expense for all stock options granted on or after January 1, 2003. All outstanding stock options were cancelled or exercised effective September 2, 2003.
Interest Expense For 2003, interest expenses on long-term debt were $23.5 million compared to $25.2 million for 2002. The decrease is due to the redemption of the senior secured term notes and the impact of the stronger Canadian dollar on U.S dollar based interest expenses. Interest on intercompany notes for 2003 was $21.5 million.
Costs on Redemption and Exchange of Notes On July 9, 2003, the Company completed an exchange offer related to its previously outstanding US$150 million 10.5 percent senior subordinated notes due 2011 (the “Old Notes”). The Company issued US$179.7 million of 9.625 percent senior subordinated notes due 2010 in exchange for US$149.8 million of the Old Notes and incurred a non-cash loss of $40.0 million on the completion of this transaction, which was recognized in income. Also recognized in income is $4.7 million of costs on the redemption of the US$57 million senior 7.23 percent secured notes.
Depletion and Depreciation Depletion and depreciation increased to $110.5 million for 2003 compared to $106.8 million last year. On a sales-unit basis, the provision for 2003 was $8.25 per boe compared to $7.46 per boe for 2002 due to the revisions in proved reserves under the new standards of disclosure for oil and gas activities, NI 51-101, as mandated by the Canadian Securities Administrators for year-ends beginning with December 31, 2003.
The ceiling test was calculated at December 31, 2003 using the proved reserves as determined under NI51-101 and at prices at year-end. No write-down was required at December 31, 2003 under this calculation.
Site Restoration Costs Site restoration costs for the year ended December 31, 2003 increased to $2.9 million from $2.8 million last year. On a sales-unit basis, the provision for 2003 was $0.22 per boe compared to $0.20 per boe for 2002 due the changes in the proved reserves used in the calculation.
24
Foreign Exchange Foreign exchange gain for 2003 was $52.1 million compared to $2.7 million in 2002. The 2003 gain is based on the translation of the Company’s U.S. dollar denominated long-term debt at 0.7737 at December 31, 2003 compared to 0.6331 at December 31, 2002. The 2002 gain is based on translation at 0.6331 at December 31, 2002 compared to 0.6279 at December 31, 2001.
Income Taxes Current tax expenses were $9.7 million for 2003 compared to $9.7 million last year. The 2003 current tax expense is comprised of $8.0 million of Saskatchewan Capital Tax and $1.7 million of Large Corporation Tax compared to $8.1 million and $1.6 million, respectively, in 2002.
The fiscal 2003 provision for future income taxes was a recovery of $11.5 million compared to $37.9 million for the prior year. The future income tax recovery for 2003 included a non-recurring adjustment resulting from a 0.5 percent decrease to the Alberta corporate income tax rate and from the federal legislation introduced to change the taxation of resource income. The federal resource tax changes include a change in the federal income tax rate, deductibility of crown royalties and elimination of the resource allowance, to be phased in over the next five years. These changes are considered substantially enacted for the purposes of GAAP and the Company’s future income tax liability has been reduced accordingly.
Capital Expenditures. Exploration and development expenditures increased to $180.1 million for 2003 compared to $136.3 million last year. Total capital expenditures for the last two years are summarized in the table below.
($ thousands) |
| 2003 |
| 2002 |
| ||
Land |
| $ | 14,138 |
| $ | 13,834 |
|
Seismic |
| 5,436 |
| 8,183 |
| ||
Drilling and completion |
| 111,772 |
| 81,862 |
| ||
Equipment |
| 42,365 |
| 24,507 |
| ||
Other |
| 6,401 |
| 7,949 |
| ||
Total exploration and development |
| 180,112 |
| 136,335 |
| ||
Property acquisitions |
| 6,644 |
| 45,713 |
| ||
Property dispositions |
| (137,493 | ) | (55,580 | ) | ||
Net capital expenditures |
| $ | 49,263 |
| $ | 126,468 |
|
Results of Operations 2002 compared to 2001
Production Baytex’s average production for fiscal 2002 decreased by 10 percent to 39,214 barrels of oil equivalent per day from 43,488 barrels of oil equivalent per day for fiscal 2001. This decrease was the result of property dispositions that occurred in the fourth quarter of 2001 and the first quarter of 2002 along with a decrease in capital spending on heavy oil in the last half of 2001.
Light oil production decreased 39 percent to 3,154 barrels per day during 2002 from 5,152 barrels per day in 2001. Heavy oil production during 2002 decreased by 10 percent to 23,967 barrels per day from 26,533 barrels per day during fiscal 2001. Natural gas production for 2002 increased by 2 percent to 72.6 million cubic feet per day compared to 70.8 million cubic feet per day for the prior year.
Production by Area |
| Conventional |
| Heavy Oil |
| Natural Gas |
| Barrels of Oil |
|
|
| (bbls/d) |
| (bbls/d) |
| (mmcf/d) |
| (boe/d) |
|
2002 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| — |
| 23,967 |
| 10.5 |
| 25,710 |
|
Plains District |
| 2,124 |
| — |
| 43.8 |
| 9,418 |
|
Northern District |
| 1,030 |
| — |
| 18.3 |
| 4,086 |
|
Total Production |
| 3,154 |
| 23,967 |
| 72.6 |
| 39,214 |
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| 368 |
| 26,533 |
| 11.5 |
| 28,813 |
|
Plains District |
| 3,721 |
| — |
| 35.5 |
| 9,192 |
|
Northern District |
| 1,063 |
| — |
| 23.8 |
| 5,483 |
|
Total Production |
| 5,152 |
| 26,533 |
| 70.8 |
| 43,488 |
|
25
Revenue Petroleum and natural gas sales for 2002 increased by 11 percent to $365.9 million from $329.7 million for fiscal 2001. Benchmark WTI crude oil averaged US$26.08 per barrel for 2002, representing a one percent increase over the US$25.90 per barrel for 2001. Correspondingly, Baytex’s light oil and NGLs price increased to $33.86 per barrel from $33.65 per barrel. The Company’s heavy oil price increased 58 percent to $26.39 per barrel from $16.69 per barrel, as heavy oil differentials decreased from 2001 with Baytex’s heavy oil receiving 66 percent of the Canadian par crude price during fiscal 2002 compared to 43 percent in 2001. Natural gas prices were 11 percent lower in 2002 averaging $3.94 per thousand cubic feet compared to $4.42 per thousand cubic feet during the previous year. Overall, after accounting for financial derivative contracts, Baytex averaged $25.56 per barrel of oil equivalent for 2002 production, a 23 percent increase from $20.77 per barrel of oil equivalent received in the prior year.
For 2002, light oil revenue decreased 38 percent over 2001, as production decreased 39 percent while wellhead prices were consistent. Revenue from heavy oil increased 43 percent as the 10 percent decreased in production was offset by the 58 percent increase in wellhead prices. Natural gas revenue decreased nine percent as production increased two percent and wellhead prices declined by 11 percent.
Gross Revenue Analysis |
| 2002 |
| 2001 |
| ||||
|
| $000s |
| $/Unit |
| $000s |
| $/Unit |
|
Oil Revenue (barrels) |
|
|
|
|
|
|
|
|
|
Light oil |
| 38,985 |
| 33.86 |
| 63,288 |
| 33.65 |
|
Heavy oil |
| 230,874 |
| 26.39 |
| 161,681 |
| 16.69 |
|
Derivative contract loss |
| (10,622 | ) | (1.07 | ) | (9,513 | ) | (0.82 | ) |
Total oil revenue |
| 259,237 |
| 26.19 |
| 215,456 |
| 18.63 |
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue (mcf) |
| 104,284 |
| 3.94 |
| 114,244 |
| 4.42 |
|
Derivative contract gain |
| 2,339 |
| 0.09 |
| — |
| — |
|
Total natural gas revenue |
| 106,623 |
| 4.03 |
| 114,244 |
| 4.42 |
|
|
|
|
|
|
|
|
|
|
|
Total revenue (boe @ 6:1) |
| 365,860 |
| 25.56 |
| 329,700 |
| 20.77 |
|
Royalties Total royalties increased two percent to $58.9 million for the year ended December 2002 from $57.8 million for the same period last year due to an increase in revenue and an increase in heavy oil royalty rates. The overall royalty rate for 2002 was 15.7 percent of sales compared to 17 percent of sales for fiscal 2001. The decrease in the overall royalty rate resulted from the sale of properties at the end of 2001 and in the first quarter of 2002 that carried a higher royalty burden. In 2002, royalties were 16.7 percent of sales for light oil (2001 – 19.1 percent), 13.9 percent for heavy oil (2001 – 10.6 percent) and 19.5 percent for natural gas (2001 – 25.1 percent).
Operating Expenses Operating expenses for 2002 decreased 10 percent to $75.2 million from $83.4 million during the previous year. This decrease is attributable to a 10 percent decrease in overall production. For 2002, operating expenses by product were $5.83 per barrel of light oil, $5.99 per barrel of heavy oil and $0.61 per thousand cubic feet of natural gas. In comparison, operating expenses by product for 2001 were
26
$6.82 per barrel of light oil, $5.59 per barrel of heavy oil and $0.64 per thousand cubic feet of natural gas. Overall operating expenses were consistent on a unit basis at $5.26 per barrel of oil equivalent during 2002 and 2001.
General and Administrative Expenses General and administrative expenses, after capitalization, increased to $6.7 million for 2002 compared to $5.3 million for 2001. On a per unit of production basis, these expenses increased during 2002 to $0.47 per barrel of oil equivalent from $0.33 per barrel of oil equivalent in 2001. This increase was due to increased staff levels associated with the Company’s 2001 corporate acquisitions. In accordance with the full cost accounting policy, $6.7 million of expenses were capitalized in 2002 compared to $5.3 million in 2001.
Interest Expense For the year ended December 31, 2002, interest expenses decreased to $25.2 million from $32.9 million for the prior year. Average debt levels decreased from $388.8 million in 2001 to $336.9 million in 2002. Interest expense was further reduced by interest rate swap agreements that the Company negotiated in December 2001. These swaps were settled during the third quarter of 2002 for total proceeds of $14.1 million, which is being amortized as a reduction of interest expense. This amortization reduces the effective interest rate of the senior secured notes from 7.23 percent to 5.7 percent until November 2004 and the senior subordinated notes form 10.5 percent to 9.2 percent until February 2006.
Depletion and Depreciation Depletion and depreciation, before ceiling test considerations, decreased to $106.8 million for 2002 compared to $132.9 million for 2001. The decrease is due to lower production and the ceiling test write-down taken at year-end 2001. On a unit of production basis, the provision for 2002 was $7.46 per barrel of oil equivalent compared to $8.37 per barrel of oil equivalent for last year.
Due to wide heavy oil differentials at year-end 2001, the Company incurred a $131.3 million ceiling test write-down (net of $103.2 million of future income taxes). This amount was recognized as additional depletion and depreciation for the year ended December 31, 2001.
Site Restoration Costs Site restoration costs for 2002 decreased to $2.8 million from $3.9 million last year due to lower production and property dispositions. On a unit of production basis, the provision for 2002 was $0.20 per barrel of oil equivalent compared to $0.25 per barrel of oil equivalent for the previous year.
Foreign Exchange The foreign exchange gain for the year ended December 31, 2002 was $2.7 million compared to a loss of $16.3 million for the last year. The 2002 gain is based on the translation of the Company’s U.S. dollar denominated long-term debt at 0.6331 at December 31, 2002 compared to 0.6279 at December 31, 2001. The 2001 loss is based on the translation of the U.S. dollar denominated senior secured notes at 0.6279 at December 31, 2001 compared to 0.6660 at December 31, 2000 along with the senior subordinated notes translated at 0.6279 at December 31, 2001 compared to 0.6582 on February 13, 2001 when the notes were issued.
Income Taxes Current tax expenses were $9.7 million for 2002 compared to $7.1 million in 2001. The current tax expenses are comprised of $8.1 million of Saskatchewan Capital Tax and $1.6 million of Large Corporation Tax, compared to $6.1 million and $1.0 million, respectively, for the prior year. Saskatchewan Capital Tax has increased as higher commodity prices have resulted in higher revenues earned in Saskatchewan.
The fiscal 2002 provision for future income taxes was $38 million compared to recovery of $107.3 million for the prior year. The increase in future income taxes was the result of higher corporate earnings in 2002 due to increased commodity prices. Future income taxes for 2001 included a $103.2 million recovery associated with the year-end ceiling test write-down.
27
Capital Expenditures
Total exploration and development expenditures for 2002 were $136.3 million, which is consistent with $135.9 million for 2001. Overall net capital expenditures decreased 66 percent to $126.5 million in 2002 from $375.9 million in 2001. Two corporate acquisitions were completed in the prior year, which accounted for $249.1 million of the 2001expenditures.
Capital Expenditures |
| 2002 |
| 2001 |
|
($ thousands) |
|
|
|
|
|
Land |
| 13,834 |
| 11,494 |
|
Seismic |
| 8,183 |
| 7,242 |
|
Drilling and completions |
| 81,862 |
| 71,928 |
|
Equipment |
| 24,507 |
| 37,206 |
|
Other |
| 7,949 |
| 8,019 |
|
Total exploration and development |
| 136,335 |
| 135,889 |
|
Corporate acquisitions |
| — |
| 249,152 |
|
Property acquisitions |
| 45,713 |
| 53,394 |
|
Dispositions |
| (55,580 | ) | (62,582 | ) |
Net capital expenditures |
| 126,468 |
| 375,853 |
|
Risk and Risk Management
The exploration for and the development, production and marketing of petroleum and natural gas involves a wide range of business and financial risks, some of which are beyond Baytex’s control. Included in these risks are the uncertainty of finding new reserves, the fluctuations of commodity prices, the volatile nature of interest and foreign exchange rates, and the possibility of changes to royalty, tax and environmental regulations. The petroleum industry is highly competitive and Baytex competes with a number of other companies, many of which have greater financial and operating resources.
The business risks facing Baytex are mitigated in a number of ways. Geological, geophysical, engineering, environmental and financial analyses are performed on new exploration prospects, development projects and potential acquisitions to ensure a balance between risk and reward. Baytex’s ability to increase its production, revenues and cash flow depends on its success not only in developing its existing properties but also in acquiring, exploring for and developing new reserves and production and managing those assets in an efficient manner.
Despite best practice analysis being conducted on all projects, there are numerous uncertainties inherent in estimating quantities of petroleum and natural gas reserves, including future oil and natural gas prices, engineering data, projected future rates of production and the timing of future expenditures. The process of estimating petroleum and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. An independent engineering firm evaluates Baytex’s properties annually to determine a fair estimate of reserves. The Reserves Evaluation Committee, consisting of qualified members of the Company’s Board, of the Board of Directors assists the Board in their annual review of the reserve estimates.
The provision for depletion and depreciation in the financial statements and the ceiling test are based on proved reserve estimates. Any future significant revisions could result in a full-cost accounting write-down or material changes to the annual rate of depletion and depreciation.
The financial risks that Baytex is exposed to as part of the normal course of its business can be managed with various financial derivative instruments, in addition to fixed-price physical delivery contracts. The use of
28
derivative instruments is governed under formal internal policies and subject to limits established by the Board of Directors. Derivative instruments are not used for speculative or trading purposes.
Baytex’s financial results can be significantly affected by the prices received for petroleum and natural gas production as commodity prices fluctuate in response to changing market forces. This pricing volatility is expected to continue. As a result, Baytex has a risk management program that may be used to protect the prices of oil and natural gas on a portion of the total expected production. The objective is to decrease exposure to market volatility and ensure Baytex’s ability to finance its distributions and capital program. Baytex recognizes gains or losses on financial derivative contracts as oil and natural gas production revenue when the associated production occurs.
In October 2002, Baytex signed a five-year crude oil supply agreement with a U.S. based refining company. This agreement calls for the delivery, beginning in January 2003, of up to 20,000 Bbls/d of Lloyd Blend oil production at a fixed differential of 29 percent of West Texas Intermediate price. This pricing arrangement effectively removes the additional pricing volatility associated with heavy oil on two-thirds of Baytex’s heavy oil production. This contract forms part of Baytex’s risk management program and should help to reduce the impact on Baytex’s cash flow from dramatic swings in commodity prices in the future.
Baytex’s financial results are also impacted by fluctuations in the exchange rate between the Canadian dollar and the US dollar. Crude oil and, to a large extent, natural gas prices are based on reference prices generally denominated in US dollars, while the majority of expenses are denominated in Canadian dollars. The exchange rate also impacts the valuation of the U.S. dollar denominated long-term debt. The related foreign exchange gains and losses are included in net income. There is no plan at this time to fix the exchange rate on any of Baytex’s long-term borrowings.
Baytex is exposed to changes in interest rates as the Company’s banking facilities are based on the lenders’ prime lending rate and short-term Bankers’ Acceptance rates.
Baytex’s current position with respect to its financial derivative contracts is detailed in note 16 of the consolidated financial statements.
CRITICAL ACCOUNTING POLICIES
The preparation of the consolidated financial statements in accordance with generally accepted accounting principles requires management to make judgments and estimates that affect the financial results of Baytex. These critical estimates are discussed below.
Oil And Gas Accounting Baytex follows the full-cost accounting guideline to account for its petroleum and natural gas operations. Under this method, all costs associated with the exploration for and development of petroleum and natural gas reserves are capitalized in one Canadian cost centre. These capitalized costs, along with estimated future development costs, are depleted and depreciated on a unit-of-production basis using estimated proved petroleum and natural gas reserves. Unit-of-production calculations are also used in the determination of the site restoration expense. By their inclusion in the unit-of-production calculation, reserve estimates are a significant component of the calculation of depletion and depreciation and site restoration expense.
Independent engineers engaged by Baytex use all available geological, reservoir, and production performance data to prepare the reserve estimates. These estimates are reviewed and revised, either upward or downward, as new information becomes available. Revisions are necessary due to changes in assumptions based on reservoir performance, prices, economic conditions, government restrictions and other relevant factors. If reserve estimates are revised downward, net income could be affected by increased depletion and depreciation and site restoration expense.
29
Impairment of Petroleum and Natural Gas Assets Companies that use the full-cost method of accounting for oil and natural gas operations are required to perform a ceiling test each quarter that calculates a limit for the net carrying cost of petroleum and natural gas assets. The ceiling test calculation utilizes and holds constant the prices and costs in effect at the end of the period. An estimate is made of the ultimate recoverable amount from future net revenues using proved reserves and period end prices, plus the net costs of major development projects and unproved properties, less future removal and site restoration costs, overhead, financing costs and income taxes. The calculation of future net revenue in the ceiling test can be significantly impacted by fluctuations in any of these estimates. An impairment loss is recognized if the amount calculated under the ceiling test is less than the carrying costs of Baytex’s petroleum and natural gas assets and can result in a significant accounting loss for a particular period.
Change in Accounting Policies and New Accounting Pronouncements
In November 2002, the Canadian Institute of Chartered Accountants (CICA) amended its accounting guideline on hedging relationships, which was originally issued in November 2001. The guideline addresses the identification, designation, documentation and effectiveness of hedging transactions for the purposes of applying hedge accounting. It also establishes conditions for applying or discontinuing hedge accounting. Under the new guideline, hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective to continue accrual accounting for positions hedged with derivatives. The new guidline is effective for fiscal years, beginning on or after July 1, 2003. As of January 1, 2004, the Company has recorded as a deferred charge the unrealized loss of $10.1 million for the mark-to-market value of the outstanding non-hedging financial derivatives. This balance is being recognized over the term of the previously designated hedged item.
Baytex has elected to prospectively adopt amendments to CICA Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments”, pursuant to the transitional provisions contained therein. Under this amended standard, Baytex is required to account for compensation expense based on the fair value of rights granted under its unit-based compensation plan. As Baytex is unable to determine the fair value of the rights granted, compensation expense has been determined based on the intrinsic value of the rights at the exercise date or at the date of the financial statements for unexercised rights. Compensation expense of $0.22 million was recorded as compensation expense for all trust unit rights granted on or after January 1, 2003, with a corresponding amount recorded as contributed surplus.
The adoption of these amendments also impacted the stock options outstanding prior to the Plan of Arrangement. Compensation expense of $0.52 million was recorded as compensation expense for all stock options granted on or after January 1, 2003, with a corresponding amount recorded as contributed surplus. For stock options granted prior to January 1, 2003, the pro forma earnings impact of related stock-based compensation expense is disclosed in note 10 of the consolidated financial statements.
In March 2003, the CICA issued Section 3110, “Asset Retirement Obligations”. This section requires recognition of a liability at discounted fair value for the future abandonment and reclamation associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The new standard is effective for all fiscal years beginning on or after January 1, 2004. The impact of the adoption of this standard is estimated to be an increase in asset retirement obligation on the balance sheet of $33 million at December 31, 2003.
In February 2003, the CICA issued Accounting Guideline 14, “Disclosure of Guarantees” (“AcG-14”). AcG-14 establishes the disclosures required for obligations under certain guarantees. The disclosure requirements are effective for interim and annual periods beginning on or after January 1, 2003 and have been made in note 17 of the consolidated financial statements.
30
In 2003, the CICA issued Accounting Guideline 16, “Oil and Gas Accounting – Full Cost” (“AcG-16”). The guideline is effective for fiscal years beginning on or after January 1, 2004. The new guideline proposes amendments to the ceiling test calculation applied by Baytex. The ceiling test was changed to a two-stage process which is to be performed at least annually. The first stage of the test is a recognition test which compares the undiscounted future cash flow from proved reserves to the net book value of the petroleum and natural gas assets to determine if the assets are impaired. An impairment loss exists when the carrying amount of the petroleum and natural gas assets exceeds such undiscounted cash flow. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the net book value of the petroleum and natural gas assets exceeds the future discounted cash flow from proved plus probable reserves. The adoption of this new guideline on January 1, 2004 is not anticipated to have an impact on the financial results of Baytex.
On November 10, 2003, the CICA issued a draft EIC (D37) on “Income Trusts - Exchangeable Units”. The EIC proposes that the retained interest of the exchangeable shareholders should be presented on the balance sheet as a non-controlling interest separate and distinct from unitholder’s equity. This draft EIC is currently under review and was not enacted in final form as of the time of release of Baytex’s consolidated financial statements.
In June 2003 the CICA issued Accounting Guideline 15 “Consolidation of Variable Interest Entities”, which deals with the consolidation of entities that are subject to control on a basis other than ownership of voting interests. This guideline is effective for annual and interim periods beginning on or after November 1, 2004. Baytex has assessed that this new guideline is not applicable based on the current structure of Baytex and therefore will have no impact on the financial statements of Baytex.
Recent Developments in U.S. Accounting
In May 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No.150 “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity”, which establishes standards for classification and measurement of certain financial instruments. The adoption of this accounting standard did not have a material impact on the Company.
In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities” (“FIN 46”). FIN 46 provides criteria for identifying variable interest entities and for determining what entity, if any, should be included in consolidated financial statements. In December 2003, the FASB issued FIN 46(R) to clarify some of the provisions of FIN 46 and to exempt certain entities from its requirements. The adoption on January 1, 2004 of this accounting standard is not anticipated to have a material impact on the Company.
In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 104 “Revenue Recognition” (“SAB 104”), which will rescind accounting guidance contained in Staff Accounting Bulletin No. 101 related to multiple element revenue arrangements. The changes noted in SAB 104 are not anticipated to have a material impact on the Company’s financial position, results of operations or cash flows.
B. Liquidity and Capital Resources
At December 31, 2003, total net debt (including working capital) was $737.0 million compared to $362.8 million at December 31, 2002. The increase in total debt at year-end 2003 compared to 2002 was the result of the notes issued under the Arrangement.
The Company’s debt structure consists of several components. The first component is the senior credit facilities. On September 3, 2003, the Company entered into a new credit agreement with a syndicate of chartered banks. The credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance rates plus applicable margins or LIBOR rates plus applicable margins. The facilities aggregating $165 million are subject to semi-annual reviews beginning in November 2003 and are secured by a floating charge over all of the Company’s assets. At December 31, 2003, there are no amounts outstanding under the bank credit facilities.
The second component is the senior subordinated notes. On February 12, 2001, the Company issued US$150 million of senior subordinated notes (“Old Notes”) bearing interest at 10.5 percent payable semi-annually with principal repayable on February 15, 2011. These notes are unsecured and are subordinate to the Company’s bank credit facilities. On July 9, 2003, the Company completed an exchange offer related to its Old Notes. The Company issued US$179.7 million ($247.1 million) of 9.625 percent senior subordinated notes due July 15, 2010 (“New Notes”) in exchange for US$149.8 million of the Old Notes and incurred a non-cash loss of $40.0 million on the completion of this transaction, which was recognized in income. The New Notes are unsecured and are subordinate to the Company’s bank credit facilities.
The Company also has two related party notes outstanding. On September 2, 2003, the Company issued $527.4 million of unsecured, subordinated promissory notes to the Trust. The notes bear interest at 12 percent payable monthly with principal repayable on September 1, 2033. These notes are unsecured and are
31
subordinate to the Company’s bank credit facilities and senior subordinated notes. Also during 2003, the Company issued a total of $9.9 million of unsecured, subordinated promissory notes to Baytex ExchangeCo Ltd. (“ExchangeCo.”). The notes bear interest at 12 percent payable monthly with principal repayable on September 1, 2033. These notes are unsecured and are subordinate to the Company’s bank credit facilities and senior subordinated notes.
Baytex believes that cash flow generated from its operations, together with existing capacity under the bank credit facilities, will be sufficient to finance current operations and planned capital expenditures for the next year. The timing of most of the capital expenditures is discretionary and there are no material long-term capital expenditure commitments.
C. Research and Development, Patents and Licenses, etc.
None
D. Trend Information
See Item 4B and Item 5A
E. Off Balance Sheet Arrangements
Baytex uses various financial derivative instruments, the fair values of which are not reflected on the consolidated balance sheet, to reduce exposure to commodity and currency fluctuations. These risks, and Baytex’s risk management policy, are discussed in “Risk and Risk Management”. Baytex’s current position with respect to its financial derivative contracts is detailed in note 16 of the consolidated financial statements.
Baytex has ongoing obligations related to abandonment and reclamation of well and facility sites which have reached the end of their economic lives. Programs to abandon and reclaim well and facility sites are undertaken regularly in accordance with applicable legislative requirements.
F. Tabular Disclosure of Contractual Obligations
Baytex has assumed various contractual obligations and commitments, as detailed in the table below, in the normal course of operations and financing activities. These obligations and commitments have been considered when assessing the cash requirements in the above discussion of future liquidity.
|
| Payments Due by Period |
|
|
|
|
|
|
| ||
Contractual Obligations |
| Total |
| Less than 1 |
| 1-3 years |
| 4-5 years |
| After 5 |
|
Long-Term Debt |
| 769,903 |
| — |
| — |
| — |
| 769,903 |
|
Operating Leases |
| 1,660 |
| 1,328 |
| 332 |
| — |
| — |
|
Transportation Agreements |
| 7,295 |
| 3,192 |
| 3,299 |
| 804 |
| — |
|
Exchangeable shares |
| 42,243 |
| — |
| — |
| — |
| 42,243 |
|
Total Contractual Obligations |
| 821,101 |
| 4,520 |
| 3,631 |
| 804 |
| 812,146 |
|
In October 2002, the Company entered into a long-term crude oil supply contract with a third party that requires the delivery of up to 20,000 barrels per day of Lloydminster Blend crude oil at a price fixed at 71% of NYMEX WTI oil price. The contract is for an initial term of five years commencing January 1, 2003. The contract volumes increased from 9,000 barrels per day in January 2003 to 20,000 barrels per day in October 2003 and thereafter.
Special Note Regarding Forward Looking Statements - See Page 4
Our annual interest obligation on long-term debt is $ 86.7 million.
32
Item 6: Directors, Senior Management and Employees
A. Directors and Senior Management
The following table sets forth the name and position of each of our directors and executive officers at December 31, 2003:
Name |
| Age |
| Position Held |
Raymond T. Chan |
| 48 |
| President, Chief Executive Officer, Director |
Daniel G. Belot |
| 41 |
| Vice President, Finance, Chief Financial Officer |
Randal J. Best |
| 47 |
| Vice President, Corporate Development |
Ralph W. Gibson |
| 46 |
| Vice President, Marketing |
Richard W. Naden |
| 44 |
| Vice President, Engineering and Operations |
Shannon M. Gangl |
| 41 |
| Secretary |
Edward Chwyl |
| 60 |
| Director, Chairman |
John A. Brussa |
| 46 |
| Director |
W.A. Blake Cassidy |
| 66 |
| Director |
Naveen Dargan |
| 46 |
| Director |
Dale O. Shwed |
| 45 |
| Director |
There are no family relationships or other arrangements pursuant to which any person referred to above was selected as a director or officer.
Raymond T. Chan. Mr. Chan joined us as Senior Vice-President, Chief Financial Officer and a director of in October 1998. Pursuant to the reorganization of Baytex Energy Ltd. in September 2003, he was appointed President and Chief Executive Officer and a director. He began his career in the Canadian oil industry in 1981 and served as Chief Financial Officer of Gane Petroleum Corporation Ltd. and American Eagle Petroleum Ltd. in the 1980’s. In 1990, Mr. Chan joined Tarragon Oil and Gas Limited as its eighth employee and, in his role of Chief Financial Officer, helped build Tarragon into a senior producer with 250 employees. Tarragon was acquired by Marathon Oil Company of Houston, Texas in the summer of 1998. Mr. Chan graduated from the University of Saskatchewan with a Bachelor of Commerce degree in 1977 and obtained his chartered accountant designation in 1979. Mr. Chan is also a director of C1 Energy Ltd. and Crew Energy Inc., both of which are TSX listed oil and gas companies.
Daniel G. Belot. Mr. Belot joined us as Vice President, Finance and Chief Financial Officer in September 2003. From 2001 to 2003 Mr. Belot was Manager, Investor Relations for Pengrowth Energy Trust and prior thereto, he held the position of Corporate and Investment Banker with Scotia Capital. Mr. Belot holds a Bachelor degree in economics from the University of Calgary.
Randal J. Best. Mr. Best joined us as Vice President, Corporate Development in September 2003. From 2000 to 2003, Mr. Best was Managing Director of Waterous & Co. in Calgary specializing in oil and gas property divestment and M&A advisory. Prior thereto, Mr. Best was President and CEO of Enercap Corporation, a private investment company. Mr. Best holds a B.A.Sc. (Honors) degree in Chemical Engineering from the University of Waterloo, Ontario and is a graduate of the Ivey Executive Program, Richard Ivey School of Business, University of Western Ontario.
Ralph G. Gibson. Mr. Gibson joined us as Vice-President, Marketing in September 2001. Prior to that Mr. Gibson was Vice-President, Crude Oil with Canpet Energy Group, a private crude oil and natural gas liquids marketing company from November 2000 to May 2001; Vice-President, Marketing with Ranger Oil Limited from September 1997 to July 2000; and Vice-President, Marketing with ELAN Energy Inc. from November 1993 to September 1997. Mr. Gibson began his career with Mobil Oil Canada in May 1980, holding various
33
finance and marketing positions, most recently Manager, Crude Oil Sales & Supply. Mr. Gibson graduated from the University of Saskatchewan with a Bachelor of Commerce degree in 1980.
Richard W. Naden. Mr. Naden joined us as Vice-President, Production in October 1997. Pursuant to the reorganization of Baytex Energy Ltd. in September 2003, he was appointed Vice-President, Engineering and Operations. Mr. Naden was Vice-President, Operations of Dorset Exploration Ltd. from November 1996 until Dorset’s merger with us in 1997. From August 1996 to November 1996, Mr. Naden was Manager, Eastern District Production with Canadian Natural Resources Limited. From April 1993 to August 1996, Mr. Naden was Manager, Operations and Manager, Exploitation Engineering of Sceptre Resources Limited prior to the completion of its plan of arrangement with Canadian Natural Resources Limited. Mr. Naden graduated from the University of Calgary in 1981 with a Bachelor of Science degree in mechanical engineering.
Shannon M. Gangl. Ms. Gangl has been our corporate secretary since May 31, 2001. She has been a partner at Burnet, Duckworth & Palmer LLP since January 1999.
John A. Brussa. Mr. Brussa has been one of our directors since October 1997. He has been a partner at Burnet, Duckworth & Palmer LLP since February 1987 and specializes in the practice of tax matters. Mr. Brussa serves on the board of directors of Capital Energy Resources Ltd., Crew Energy Inc., Crispin Energy Inc., Divestco Inc., E3 Energy Ltd. (formerly Mill City International Inc.), Endev Energy Inc. (formerly Flock Resources Ltd.), Energy Savings Income Fund, FET Resources Inc. (formerly Storm Energy Inc.), Focus Energy Trust, Galleon Energy Inc., Grand Petroleum Ltd., Harvest Operations Corp., High Point Resources Inc., Inter Pipeline Fund (formerly Koch Pipelines Canada, L.P.), NAV Energy Trust, Orleans Resources Inc., Penn West Petroleum Ltd., Petrobank Energy and Resources Ltd., Pilot Energy Ltd., Progress Energy Ltd., Rider Resources Ltd., Rio Alto Resources International Inc., Southpoint Resources Ltd., and Strategic Energy Fund (formerly NCE Strategic Energy Fund).
W. A. Blake Cassidy. Mr. Cassidy has been one of our directors since February 1994. He is a retired banker after a 38 year career at the Canadian Imperial Bank of Commerce. He has extensive experience in both energy banking and private banking.
Edward Chwyl. Mr. Chwyl joined us as a director in May 2003 and was elected Chairman of the Board of Directors pursuant to the reorganization of Baytex Energy Ltd. in September 2003. Mr. Chwyl has over 35 years of experience in the North American oil and gas industry starting with Atlantic Richfield Company in Dallas, Texas in 1968 upon graduating with his Masters degree in Petroleum Engineering from the University of Alberta. He returned to Canada in 1972 and held positions with increasing responsibilities with ARCO, Mesa, Canada Northwest Land and its predecessor companies, and Sceptre Resources Limited. He served as President and CEO of Tarragon Oil and Gas Limited from 1989 until 1998 when it was sold to Marathon Oil Company. Mr. Chwyl has since served as a director of various energy companies in Canada.
Naveen Dargan. Mr. Dargan joined us as a director in September 2003. Mr. Dargan became an independent businessman in June 2003, prior to which he worked in the investment banking business since 1983. Between 2001 and 2003, Mr. Dargan was Senior Managing Director and head of energy investment banking for Raymond James Ltd., and between 1996 and 2001, Mr. Dargan was head of energy investment banking for two predecessor companies to Raymond James Ltd. Between 1991 and 1996, Mr. Dargan worked for two major Canadian national investment banking firms, in each case as the head of investment banking in the province of Alberta. Mr. Dargan holds a Bachelor of Arts (Honours) degree in mathematics and economics from Queen’s University, as well as an MBA from York University and a Chartered Business Valuator designation (CBV). In addition to Baytex, Mr. Dargan currently serves on the Board of Directors of CCS Inc., Defiant Energy Corporation, Trinidad Drilling Ltd., and two privately held companies.
Dale O. Shwed. In June 1993, Mr. Shwed founded Baytex Energy Ltd. and served as President, Chief Executive Officer and a Director until the reorganization in September 2003. At that time, Mr. Shwed became
34
President, Chief Executive Officer and a director of Crew Energy Inc. and continued in his capacity as director of Baytex Energy Ltd. Mr. Shwed has over 20 years of experience in the Canadian oil and gas industry, working for companies such as Amoco Canada Petroleum Corporation Ltd., Westmin Resources Ltd., Inverness Petroleum Ltd., and the Canadian division of Ceja Corporation. He was also the founder of two oil and gas companies in the mid-1980’s, ELAD Resources Corporation and Tygas Industries Ltd. Mr. Shwed graduated from the University of Alberta with a Bachelor of Science degree in geology in 1980.
The following table provides a summary of compensation earned during the fiscal year ended December 31, 2003 by the current Chief Executive Officer, the former Chief Executive Officer and the four other most highly compensated executive officers or former executive officers of Baytex (collectively the “named executive officers”).
SUMMARY COMPENSATION TABLE
|
| Annual Compensation |
| Long-Term Compensation |
|
| ||||||
Name and Principal |
| Year |
| Salary ($) |
| Bonus ($) (5) |
| Other Annual Compensation |
| Securities Under Incentive |
| All Other |
Raymond T. Chan (1) President and Chief Executive Officer |
| 2003 |
| 300,000 |
| 250,000 |
| Nil |
| 350,000 Rights |
| Nil |
Dale O. Shwed (2) |
| 2003 |
| 259,684 |
| 166,667 |
| Nil |
| 30,000 Rights |
| 1,886,026 |
Richard W. Naden |
| 2003 |
| 196,667 |
| 75,000 |
| Nil |
| 175,000 Rights |
| Nil |
John G. Leach (3) |
| 2003 |
| 114,641 |
| 130,000 |
| Nil |
| Nil |
| 500,589 |
Ralph W. Gibson |
| 2003 |
| 185,000 |
| 80,000 |
| Nil |
| 175,000 Rights |
| Nil |
Garry J. Wasylycia (4) |
| 2003 |
| 144,988 |
| 33,000 |
| Nil |
| Nil |
| 639,120 |
Notes:
(1) Mr. Chan became the President and Chief Executive Officer of Baytex in September 2003 upon completion of the Arrangement. Prior thereto, he was the Senior Vice President and Chief Financial Officer.
(2) Mr. Shwed ceased to be the President and Chief Executive Officer of Baytex in September 2003 upon completion of the Arrangement. Mr. Shwed continues as a Director of Baytex subsequent to the completion of the Arrangement.
(3) Mr. Leach ceased to be the Vice President, Finance & Administration of Baytex in September 2003 upon completion of the Arrangement.
(4) Mr. Wasylycia ceased to be the Vice President, Exploration of Baytex in September 2003 upon completion of the Plan of Arrangement.
35
(5) Each of Baytex’s executive officers applied all 2002 bonuses to the acquisition of flow through common shares of Baytex. The common shares were acquired at $7.86 per common share representing a premium of 6.2% over the closing price of the Baytex common shares on the TSX the day prior to the approval of the bonuses by the Board of Directors.
(6) Perquisites and other personal benefits do not exceed the lesser of $50,000 and 10% of the total annual salary and bonus for any of the named executive officers.
(7) Payments pursuant to change of control provisions of employment agreements.
Trust Unit Rights Incentive Plan
The Trust has established a Trust Unit Rights Incentive Plan for the directors, officers and employees of Baytex. As at March 31, 2004, the Plan had 5,800,000 Trust Units reserved for issuance thereunder. As at March 31, 2004, there were incentive rights outstanding to purchase 2,864,100 Trust Units.
The aggregate number of trust unit incentive rights granted to any single holder must not exceed 1% of the issued and outstanding Trust Units (including the number of Trust Units which may be issued on the exchange of the Exchangeable Shares which may be converted into Trust Units) (collectively, the “Total Units”) and the number of trust unit incentive rights issuable pursuant to the Trust Units Rights Incentive Plan to non-management directors as a group is limited to a maximum of 1% of the Total Units. The trust unit incentive rights may be exercised during a period (the “Exercise Period”) not exceeding five (5) years from the date upon which the trust unit incentive right was granted (the “Grant Date”), and any trust unit incentive right granted shall vest pursuant to vesting schedules determined by the Board in its sole discretion. Subject to regulatory approval, the grant price (“Grant Price”) per trust unit incentive right shall be equal to the closing price of the Trust Units on the Toronto Stock Exchange on the last trading day immediately preceding the Grant Date. The exercise price (“Exercise Price”) per trust unit incentive right shall be calculated by deducting from the Grant Price the aggregate of all monthly distributions, on a per Trust Unit basis made by the Trust after the Grant Date, provided the amount of such monthly distribution represents a return of more than 0.833% of the Trust’s recorded cost of oil and natural gas properties less accumulated depreciation and depletion and any future income tax liability associated with such oil and natural gas properties at the end of each month.
The following table sets forth individual grants of trust unit incentive rights made to the named executive officers during the fiscal year ended December 31, 2003.
TRUST UNIT INCENTIVE RIGHTS GRANTS DURING THE YEAR ENDED DECEMBER 31, 2003
Name |
| Securities Under |
| % of Total |
| Exercise Price |
| Market Value of |
| Expiration Date |
Raymond T. Chan |
| 350,000 |
| 11.8% |
| 10.23 |
| 10.80 |
| September 9, 2008 |
Dale O. Shwed |
| 30,000 |
| 1.0% |
| 10.23 |
| 10.80 |
| September 9, 2008 |
Richard W. Naden |
| 175,000 |
| 5.9% |
| 10.23 |
| 10.80 |
| September 9, 2008 |
John G. Leach |
| Nil |
| N/A |
| N/A |
| N/A |
| N/A |
Ralph W. Gibson |
| 175,000 |
| 5.9% |
| 10.23 |
| 10.80 |
| September 9, 2008 |
Garry J. Wasylycia |
| Nil |
| N/A |
| N/A |
| N/A |
| N/A |
The Arrangement became effective September 2, 2003. Prior to the completion of the Arrangement, the named executive officers did not receive stock options grants during 2003 to acquire common shares of Baytex.
36
Pursuant to the Arrangement, holders of stock options were entitled to participate in the Arrangement by exercising their stock options and receiving the same consideration under the Arrangement as the other shareholders of Baytex. All of the issued and outstanding stock options of Baytex, including those held by the named executive officers, were exercised prior to the Arrangement becoming effective on September 2, 2003.
The following table sets forth information with respect to the exercise of trust unit incentive rights during the fiscal year ended December 31, 2003 by the named executive officers and with respect to all incentive rights held by the named executive officers and still outstanding on December 31, 2003.
AGGREGATED TRUST UNIT INCENTIVE RIGHTS EXERCISED DURING THE YEAR ENDED
DECEMBER 31, 2003 AND YEAR-END TRUST UNIT INCENTIVE RIGHTS VALUES
|
| Securities |
| Aggregate Value |
| Unexercised Trust Unit |
| Value of Unexercised In-the- |
| ||||
Name |
| (#) |
| ($) |
| Vested |
| Not Vested |
| Vested |
| Not Vested |
|
Raymond T. Chan |
| Nil |
| Nil |
| Nil |
| 350,000 |
| Nil |
| 217,000 |
|
Dale O. Shwed |
| Nil |
| Nil |
| Nil |
| 30,000 |
| Nil |
| 18,600 |
|
Richard W. Naden |
| Nil |
| Nil |
| Nil |
| 175,000 |
| Nil |
| 108,500 |
|
John G. Leach |
| Nil |
| Nil |
| Nil |
| Nil |
| Nil |
| Nil |
|
Ralph W. Gibson |
| Nil |
| Nil |
| Nil |
| 175,000 |
| Nil |
| 108,500 |
|
Garry J. Wasylycia |
| Nil |
| Nil |
| Nil |
| Nil |
| Nil |
| Nil |
|
Note:
(1) Based on the December 31, 2003 closing price per Trust Unit on the TSX of $10.85.
The following table sets forth information with respect to the exercise of stock options during the fiscal year ended December 31, 2003 by the named executive officers and with respect to all stock options held by the named executive officers and still outstanding on December 31, 2002.
AGGREGATED STOCK OPTIONS EXERCISED DURING THE YEAR ENDED
DECEMBER 31, 2003 AND YEAR-END STOCK OPTION VALUES
|
| Securities |
| Aggregate Value |
| Unexercised Stock |
| Value of Unexercised In-the- |
| ||||
Name |
| (#) |
| ($) |
| Vested |
| Not Vested |
| Vested |
| Not Vested |
|
Raymond T. Chan |
| 830,000 |
| 3,360,900 |
| Nil |
| Nil |
| Nil |
| Nil |
|
Dale O. Shwed |
| 1,380,000 |
| 5,842,900 |
| Nil |
| Nil |
| Nil |
| Nil |
|
Richard W. Naden |
| 231,300 |
| 832,198 |
| Nil |
| Nil |
| Nil |
| Nil |
|
John G. Leach |
| 137,000 |
| 554,810 |
| Nil |
| Nil |
| Nil |
| Nil |
|
Ralph W. Gibson |
| 160,000 |
| 807,250 |
| Nil |
| Nil |
| Nil |
| Nil |
|
Garry J. Wasylycia |
| 217,667 |
| 875,098 |
| Nil |
| Nil |
| Nil |
| Nil |
|
37
Retirement Plans
Baytex has no retirement plans for its employees.
Employment Agreement and Change of Control Agreements
Baytex has entered into an employment agreement with Mr. Chan which provides that in the event that the executive’s employment with Baytex is terminated without cause or upon a change of control of Baytex as defined in the agreement, and subject to certain conditions being met, Mr. Chan may receive a payment equal to 30 months salary, a bonus consideration and other employment benefits. Baytex has also entered into change of control agreements with other officers. The agreements provide that in the event of a change of control of Baytex as defined, and subject to certain conditions being met, the officers may receive payments equal to 24 months salary, a bonus consideration and other employment benefits.
In addition, the employment agreements and change of control agreements allow for the acceleration of un-vested and unexercised trust unit incentive rights. These rights may be exercised for a period of 30 days following the date of termination of employment.
Compensation of Directors
Prior to the Arrangement, unrelated directors of Baytex were paid an annual retainer of $10,000 plus a fee of $500 per meeting attended. Subsequent to the Arrangement, fees to unrelated directors, other than the Chairman, were increased to an annual retainer of $15,000 plus a fee of $1,000 per meeting attended. The Chairman receives an annual retainer of $25,000 plus a fee of $1,000 per meeting attended. Director fees are paid on a quarterly basis.
During 2003, the unrelated directors were also granted trust unit incentive rights as follows: Mr. Brussa - 30,000 trust unit incentive rights; Mr. Shwed - 30,000 trust unit incentive rights; Mr. Cassidy - 30,000 trust unit incentive rights; Mr. Chwyl - 45,000 trust unit incentive rights; and Mr. Dargan - 30,000 trust unit incentive rights.
Liability Insurance of Directors and Officers
Baytex maintains directors’ and officers’ liability insurance coverage for losses to Baytex if it is required to reimburse directors and officers, where permitted, and for direct indemnity of directors and officers where corporate reimbursement is not permitted by law. The insurance protects Baytex against liability (including costs), subject to standard policy exclusions, which may be incurred by directors and/or officers acting in such capacity for Baytex. All directors and officers of Baytex are covered by the policy and the amount of insurance applies collectively to all. The cost of this insurance is $202,000 per annum.
Directors are elected at each annual meeting to hold office for a term expiring at the close of the next annual meeting of shareholders. No specific term of office is applicable to executive officers; however, they are normally re-appointed annually. The last annual meeting was held May 17, 2004.
The members of Baytex’s audit committee are Naveen Dargan, Dale O. Shwed and, W. A. Blake Cassidy. The audit committee, consisting of a majority of outside directors, reviews the Consolidated Financial Statements, assessing the accounting principles, risks, adequacy and internal effectiveness of internal controls and recommends the Consolidated Financial Statements to the Board for approval. The audit committee also meets with management and external auditors to discuss internal controls and significant accounting and reporting issues as well as recommending the engagement or reappointment of the Company’s external auditors.
38
The compensation committee is comprised of Edward Chwyl, John A. Brussa and Naveen Dargan, all of whom are independent, non-employee directors of the Company. During 2003, no such member was a current or former officer or employee of the Company or any of its subsidiaries. The compensation committee of the board of directors is responsible for, among other matters, reviewing the performance objectives and compensation package for the President and Chief Executive Officer, recommending compensation and benefits packages for the Company’s leadership team and reviewing and approving fees paid to members of the board of directors.
As at December 31, 2003, Baytex employed 95 head office employees and 17 field office employees. None of our employees are represented by a union. We do not have a significant number of temporary employees.
At April 12, 2004, the Trust owned the common share of Baytex. The following table contains information provided to us by our shareholders with respect to beneficial ownership of our exchangeable shares:
|
| Exchangeable |
| ||
Name |
| Number |
| % |
|
Dale O. Shwed |
| 605,129 |
| 16.2 |
|
Item 7. Major Shareholders and Related Party Transactions
The following table sets for the information, as of April 12, 2004, regarding beneficial ownership of the common shares and exchangeable shares.
Title of Class |
| Identity of Group |
| Amount Owned |
| Percent of Class |
|
Common |
| Baytex Energy Trust |
| 1 |
| 100 |
|
Exchangeable |
| Officers and Directors |
| 605,129 |
| 16.2 |
|
The voting rights attached to each class of share are as described below.
There has been no change in beneficial ownership during the past three years other than that brought about by the Arrangement.
Related party transactions entered into by the Company in the last 3 years that are currently in effect are as follows:
On September 2, 2003, the Company issued $527.4 million of unsecured, subordinated promissory notes to the Trust. The notes bear interest at 12 percent payable monthly with principal repayable on September 1, 2033. These notes are unsecured and are subordinate to the Company’s bank credit facilities and senior subordinated notes.
During 2003, the Company issued a total of $9.9 million of unsecured, subordinated promissory notes to ExchangeCo. The notes bear interest at 12 percent payable monthly with principal repayable on September 1,
39
2033. These notes are unsecured and are subordinate to the Company’s bank credit facilities and senior subordinated notes.
On September 2, 2003, Baytex completed the Arrangement whereby holders of common shares of Baytex elected or were deemed to have elected to receive either Trust Units of the Trust or Exchangeable Shares of Baytex for their common shares on the basis of one Trust Unit or Exchangeable Share, respectively, for each common share held. Coincident with the Arrangement becoming effective, certain of Baytex’s exploration assets were acquired by Crew, and the common shares of Crew were distributed to the former holders of Baytex common shares on the basis of one-third of a common share of Crew for each such share held.
C. Interests of Experts and Counsel
Not Applicable
Item 8. Financial Information
A. Consolidated Financial Statements and Other Financial Information
See Item 17.
None
Item 9. The Offer and Listing
Price Range of Common Stock and Trading Markets
On September 2, 2003 the business of Baytex was reorganized. In conjunction with this reorganization, the shareholders of Baytex. common stock received one trust unit for each share of common stock held or non-registered exchangeable shares convertible into an equal number of trust units. Subsequent to this reorganization, Baytex became a subsidiary of the Trust. The common shares of Baytex are not listed on a stock exchange subsequent to the reorganization. The last day of trading on the Toronto Stock Exchange for Baytex was September 5, 2003.
|
|
|
| High |
| Low |
|
1999 |
|
|
| 11.30 |
| 2.90 |
|
2000 |
|
|
| 16.70 |
| 8.25 |
|
2001 |
| First Quarter |
| 14.84 |
| 9.00 |
|
|
| Second Quarter |
| 13.55 |
| 9.60 |
|
|
| Third Quarter |
| 11.50 |
| 4.64 |
|
|
| Fourth Quarter |
| 5.25 |
| 3.00 |
|
2002 |
| First Quarter |
| 6.89 |
| 3.95 |
|
|
| Second Quarter |
| 8.45 |
| 6.35 |
|
|
| Third Quarter |
| 8.40 |
| 5.65 |
|
|
| Fourth Quarter |
| 8.92 |
| 6.65 |
|
2003 |
| January |
| 9.24 |
| 8.10 |
|
|
| February |
| 9.70 |
| 8.50 |
|
|
| March |
| 10.20 |
| 8.75 |
|
|
| April |
| 10.65 |
| 8.75 |
|
|
| May |
| 11.10 |
| 9.82 |
|
|
| June |
| 12.03 |
| 10.75 |
|
|
| July |
| 11.90 |
| 11.30 |
|
|
| August |
| 12.74 |
| 11.91 |
|
|
| September |
| 12.40 |
| 12.01 |
|
40
Not Applicable
Not Applicable
Not Applicable
Not Applicable
Not Applicable
Item 10. Additional Information
Common Shares
The Company is authorized to issue an unlimited number of common shares. Each Baytex common share entitles its holder to receive notice of and to attend all meetings of the shareholders of Baytex and to one vote at such meetings. The holders of common shares will be, at the discretion of the Board of Directors of Baytex and subject to applicable legal restrictions, and subject to certain preferences of holders of Exchangeable Shares, entitled to receive any dividends declared by the Board of Directors on the common shares to the exclusion of the holders of Exchangeable Shares, subject to the proviso that no dividends shall be paid on the common shares unless all declared dividends on the outstanding Exchangeable Shares have been paid in full. The holders of common shares are entitled to share equally in any distribution of the assets of Baytex upon the liquidation, dissolution, bankruptcy or winding-up of Baytex or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to the Exchangeable Shares and any other shares having priority over the common shares. At December 31, 2003, the common share of Baytex is owned by the Trust.
Exchangeable Shares
The Company is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares can be converted (at the option of the holder) into Trust Units at any time up to September 2, 2013. Up to 1.9 million exchangeable shares may be redeemed annually by the Company for either cash or the issue of Trust Units. The number of trust units issued upon conversion is based upon the exchange ratio in effect at the conversion date. The exchange ratio is calculated monthly based on the cash distribution paid divided by the
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weighted average trust unit price of the five-day trading period ending on the record date. The exchange ratio at December 31, 2003 was 1.04530 Trust Units per exchangeable share. Cash distributions are not paid on the exchangeable shares. The exchangeable shares are not publicly traded.
The following is a summary description of the material provisions of the Exchangeable Shares and the related ancillary and indirect rights of holders of Exchangeable Shares under the terms of the Voting and Exchange Trust Agreement and the Support Agreement.
Each Exchangeable Share has economic rights (including the right to have the Exchange Ratio adjusted to account for distributions paid to unitholders) and voting attributes (through the benefit of the Special Voting Units granted to the Voting and Exchange Trust Agreement Trustee, as defined below) equivalent to those of the Trust Units into which they are exchangeable from time to time. In addition, holders of Exchangeable Shares have the right to receive Trust Units at any time in exchange for their Exchangeable Shares, on the basis of the Exchange Ratio in effect at the time of the exchange. Fractional Trust Units will not be delivered on any exchange of Exchangeable Shares. In the event that the Exchange Ratio in effect at the time of an exchange would otherwise entitle a holder of Exchangeable Shares to a fractional Trust Unit, the number of Trust Units to be delivered are rounded down to the nearest whole number of Trust Units. Holders of Exchangeable Shares will not receive cash distributions from the Trust or Baytex. Rather, the Exchange Ratio will be adjusted to account for distributions paid to unitholders.
Ranking
The Exchangeable Shares rank rateably with shares of any other series of exchangeable shares of Baytex and prior to any common shares and any other shares ranking junior to the Exchangeable Shares with respect to the payment of dividends, if any, that have been declared and the distribution of assets in the event of the liquidation, dissolution or winding-up of Baytex.
Dividends
Holders of Exchangeable Shares are entitled to receive cash dividends if, as and when declared by the Board of Directors of Baytex. Baytex anticipates that it may from time to time declare dividends on the Exchangeable Shares up to but not exceeding any cash distributions on the Trust Units into which such Exchangeable Shares are exchangeable. In the event that any such dividends are paid, the Exchange Ratio will be correspondingly reduced to reflect such dividends.
Certain Restrictions
Baytex will not, without obtaining the approval of the holders of the Exchangeable Shares as set forth below under the subheading “Amendment and Approval”:
• pay any dividend on the common shares or any other shares ranking junior to the common shares, other than stock dividends payable in common shares or any other shares ranking junior to the Exchangeable Shares;
• redeem, purchase or make any capital distribution in respect of the common shares of Baytex or any other shares ranking junior to the Exchangeable Shares;
• redeem or purchase any other shares of Baytex ranking equally with the Exchangeable Shares with respect to the payment of dividends or on any liquidation distribution; or
• issue any shares, other than Exchangeable Shares or common shares, which rank superior to the Exchangeable Shares with respect to the payment of dividends or on any liquidation distribution.
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The above restrictions shall not apply if all declared dividends on the outstanding Exchangeable Shares have been paid in full.
Liquidation or Insolvency of Baytex
In the event of the liquidation, dissolution or winding-up of Baytex or any other proposed distribution of the assets of Baytex among its shareholders for the purpose of winding up its affairs, a holder of Exchangeable Shares will be entitled to receive from Baytex, in respect of each such Exchangeable Share, that number of Trust Units equal to the Exchange Ratio as at the effective date of such event.
Upon the occurrence of such an event, the Trust and ExchangeCo will each have the overriding right to purchase all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by the Trust or any subsidiary of the Trust) at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time and, upon the exercise of this right, the holders thereof will be obligated to sell such Exchangeable Shares to the Trust or ExchangeCo, as applicable. This right may be exercised by either the Trust or ExchangeCo.
Automatic Exchange Right on Liquidation of the Trust
The Voting and Exchange Trust Agreement provides that in the event of a Trust liquidation event, as described below, the Trust or ExchangeCo will be deemed to have purchased all outstanding Exchangeable Shares and each holder of Exchangeable Shares will be deemed to have sold their Exchangeable Shares immediately prior to such Trust liquidation event at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time. “Trust liquidation event” means:
• any determination by the Trust to institute voluntary liquidation, dissolution or winding-up proceedings in respect of the Trust or to effect any other distribution of assets of the Trust among the unitholders for the purpose of winding up its affairs; or
• the earlier of, the Trust’s receiving notice of and the Trust’s otherwise becoming aware of, any threatened or instituted claim, suit, petition or other proceedings with respect to the involuntary liquidation, dissolution or winding up of the Trust or to effect any other distribution of assets of the Trust among the unitholders for the purpose of winding up its affairs in each case where the Trust has failed to contest in good faith such proceeding within 30 days of becoming aware thereof.
Retraction of Exchangeable Shares by Holders and Retraction Call Right
Subject to the Retraction Call Right of the Trust and ExchangeCo as defined below, a holder of Exchangeable Shares will be entitled at any time to require Baytex to redeem any or all of the Exchangeable Shares held by such holder for a retraction price (the “Retraction Price”) per Exchangeable Share equal to the value of that number of Trust Units equal to the Exchange Ratio as at the date of redemption (the “Retraction Date”), to be satisfied by the delivery of such number of Trust Units. Fractional Trust Units will not be delivered. Any amount payable on account of the Retraction Price that includes a fractional Trust Unit will be rounded down to the nearest whole number of Trust Units. Holders of the Exchangeable Shares may request redemption by presenting to Baytex or the transfer agent for the Exchangeable Shares a certificate or certificates representing the number of Exchangeable Shares the holder desires to have redeemed, together with a duly executed retraction request and such other documents as may be reasonably required to effect the redemption of the Exchangeable Shares. The redemption will become effective on the Retraction Date, which will be three Business Days after the date on which Baytex or the transfer agent receives the retraction notice.
When a holder requests Baytex to redeem the Exchangeable Shares, the Trust and ExchangeCo will have an overriding right (the “Retraction Call Right”) to purchase on the Retraction Date all but not less than all of the Exchangeable Shares that the holder has requested Baytex to redeem at a purchase price per Exchangeable
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Share equal to the Retraction Price, to be satisfied by the delivery of that number of Trust Units equal to the Exchange Ratio at such time. At the time of a Retraction Request by a holder of Exchangeable Shares, Baytex will immediately notify the Trust and ExchangeCo. The Trust or ExchangeCo must then advise Baytex within two business days as to whether the Retraction Call Right will be exercised. A holder may revoke his or her Retraction Request at any time prior to the close of business on the last business day immediately preceding the Retraction Date, in which case the holder’s Exchangeable Shares will neither be purchased by the Trust or ExchangeCo nor be redeemed by Baytex. If the holder does not revoke his or her Retraction Request, the Exchangeable Shares that the holder has requested Baytex to redeem will on the Retraction Date be purchased by the Trust or ExchangeCo or redeemed by Baytex, as the case may be, in each case at a purchase price per Exchangeable Share equal to the Retraction Price. In addition, a holder of Exchangeable Shares may elect to instruct the Voting and Exchange Trust Agreement Trustee, as defined below, to exercise the optional exchange right (the “Optional Exchange Right”) to require the Trust or ExchangeCo to acquire such holder’s Exchangeable Shares in circumstances where neither the Trust nor ExchangeCo have exercised the Retraction Call Right. See “Voting and Exchange Trust Agreement - Optional Exchange Right”.
The Retraction Call Right may be exercised by either the Trust or ExchangeCo. If, as a result of solvency provisions of applicable law, Baytex is not permitted to redeem all Exchangeable Shares tendered by a retracting holder, Baytex will redeem only those Exchangeable Shares tendered by the holder as would not be contrary to such provisions of applicable law. The holder of any Exchangeable Shares not redeemed by Baytex will be deemed to have required the Trust to purchase such unretracted Exchangeable Shares in exchange for Trust Units on the Retraction Date pursuant to the Optional Exchange Right. See “Voting and Exchange Trust Agreement - Optional Exchange Right”.
Redemption of Exchangeable Shares
Subject to applicable law and the Redemption Call Right of the Trust and ExchangeCo, Baytex:
will, on the tenth anniversary of the Effective Date, subject to extension of such date by the Board of Directors of Baytex (the “Automatic Redemption Date”), redeem all but not less than all of the then outstanding Exchangeable Shares for a redemption price per Exchangeable Share equal to the value of that number of Trust Units equal to the Exchange Ratio as at the last Business Day prior to that Redemption Date (as that term is defined below) (the “Redemption Price”), to be satisfied by the delivery of such number of Trust Units;
may, on the second anniversary of the Effective Date (the “Optional Redemption Date”), redeem all but not less than all outstanding Exchangeable Shares for the Redemption Price per Exchangeable Share at the last Business Day prior to that Redemption Date (as that term is defined below), to be satisfied by the delivery of Trust Units;
may, on any date that is within the first 90 days of any calendar year commencing in 2004 (the “Annual Redemption Date”), redeem up that number of Exchangeable Shares equal to 40% of the Exchangeable Shares outstanding on the Effective Date for the Redemption Price per Exchangeable Share at the last Business Day prior to that Redemption Date (as that term is defined below), to be satisfied by the delivery of Trust Units; and
may, at any time when the aggregate number of issued and outstanding Exchangeable Shares is less than 1 million (other than Exchangeable Shares held by the Trust and its subsidiaries and as such shares may be adjusted from time to time) (the “De Minimus Redemption Date” and, collectively with the Automatic Redemption Date, optional Redemption Date and Annual Redemption Date, a “Redemption Date”), redeem all but not less than all of the then outstanding Exchangeable Shares for the Redemption Price per Exchangeable Share (unless contested in good faith by the Trust).
Baytex will, at least 90 days prior to any Redemption Date, provide the registered holders of the Exchangeable Shares with written notice of the prospective redemption of the Exchangeable Shares by Baytex.
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The Trust and ExchangeCo have the right (the “Redemption Call Right”), notwithstanding a proposed redemption of the Exchangeable Shares by Baytex on the applicable Redemption Date, pursuant to the Exchangeable Share Provisions, to purchase on any Redemption Date all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by the Trust or its subsidiaries) in exchange for the Redemption Price per Exchangeable Share and, upon the exercise of the Redemption Call Right, the holders of all of the then outstanding Exchangeable Shares will be obliged to sell all such shares to the Trust or ExchangeCo, as applicable. If either the Trust or ExchangeCo exercises the Redemption Call Right, then Baytex’s right to redeem the Exchangeable Shares on the applicable Redemption Date will terminate. The Redemption Call Right may be exercised by either the Trust or ExchangeCo.
Voting Rights
Except as required by applicable law, the holders of the Exchangeable Shares are not entitled as such to receive notice of or attend any meeting of the shareholders of Baytex or to vote at any such meeting. Holders of Exchangeable Shares have the notice and voting rights respecting meetings of the Trust that are provided in the Voting and Exchange Trust Agreement. See “Voting and Exchange Trust Agreement - Voting Rights”.
Amendment and Approval
The rights, privileges, restrictions and conditions attaching to the Exchangeable Shares may be changed only with the approval of the holders thereof. Any such approval or any other approval or consent to be given by the holders of the Exchangeable Shares will be sufficiently given if given in accordance with applicable law and subject to a minimum requirement that such approval or consent be evidenced by a resolution passed by not less than two-thirds of the votes cast thereon (other than shares beneficially owned by the Trust, or any of its subsidiaries and other affiliates) at a meeting of the holders of the Exchangeable Shares duly called and held at which holders of at least 10% of the then outstanding Exchangeable Shares are present in person or represented by proxy. In the event that no such quorum is present at such meeting within one-half hour after the time appointed therefor, then the meeting will be adjourned to such place and time (not less than ten days later) as may be determined at the original meeting and the holders of Exchangeable Shares present in person or represented by proxy at the adjourned meeting will constitute a quorum thereat and may transact the business for which the meeting was originally called. At the adjourned meeting, a resolution passed by the affirmative vote of not less than two-thirds of the votes cast thereon (other than shares beneficially owned by the Trust or any of its subsidiaries and other affiliates) will constitute the approval or consent of the holders of the Exchangeable Shares.
Actions by the Trust Under the Support Agreement and the Voting and Exchange Trust Agreement
Under the Exchangeable Share Provisions, Baytex has agreed to take all such actions and do all such things as are necessary or advisable to perform and comply with its obligations under, and to ensure the performance and compliance by the Trust and ExchangeCo with their obligations under, the Support Agreement and the Voting and Exchange Trust Agreement.
Non-Resident and Tax-Exempt Holders
The obligation of Baytex, the Trust or ExchangeCo to deliver Trust Units to a Non-Resident holder in respect of the exchange of such holder’s Exchangeable Shares may be satisfied by delivering such Trust Units to the transfer agent who shall sell such Trust Units on the stock exchange on which they are listed and deliver the proceeds of sale to the Non-Resident holder.
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VOTING AND EXCHANGE TRUST AGREEMENT
Voting Rights
In accordance with the Voting and Exchange Trust Agreement, the Trust has issued one (1) special voting right (“Special Voting Right”) to Valiant Trust Company, the Voting and Exchange Trust Agreement trustee (the “Trustee”), for the benefit of the holders (other than the Trust and ExchangeCo) of the Exchangeable Shares. The Special Voting Right carries a number of votes, exercisable at any meeting at which Trust unitholders are entitled to vote, equal to one vote for each Exchangeable Share outstanding. With respect to any written consent sought from the Trust unitholders, each vote attached to the Special Voting Right will be exercisable in the same manner as set forth above.
Each holder of an Exchangeable Share on the record date for any meeting at which Trust unitholders are entitled to vote will be entitled to instruct the Trustee to exercise that number of votes attached to the Special Voting Right which relate to the Exchangeable Shares held by such holder. The Trustee will exercise each vote attached to the Special Voting Right only as directed by the relevant holder and, in the absence of instructions from a holder as to voting, will not exercise such votes.
The Trustee is required to send to the holders of the Exchangeable Shares the notice of each meeting at which the Trust unitholders are entitled to vote, together with the related meeting materials and a statement as to the manner in which the holder may instruct the Trustee to exercise the votes attaching to the Special Voting Right, at the same time as the Trust sends such notice and materials to the Trust unitholders. The Trustee is also required to send to the holders copies of all information statements, interim and annual financial statements, reports and other materials sent by the Trust to the Trust unitholders at the same time as such materials are sent to the Trust unitholders. To the extent such materials are provided to the Trustee by the Trust, the Trustee will also send to the holders all materials sent by third parties to Trust unitholders, including dissident proxy circulars and tender and exchange offer circulars, as soon as possible after such materials are first sent to Trust unitholders.
All rights of a holder of Exchangeable Shares to exercise votes attached to the Special Voting Right will cease upon the exchange of all such holder’s Exchangeable Shares for Trust Units. With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of the Exchangeable Shares, making necessary amendments or curing ambiguities or clerical errors (in each case provided that the Board of Directors of ExchangeCo and Baytex are of the opinion that such amendments are not prejudicial to the interests of the holders of the Exchangeable Shares), the Voting and Exchange Trust Agreement may not be amended without the approval of the holders of the Exchangeable Shares.
Optional Exchange Right
Upon the occurrence and during the continuance of:
(a) an insolvency event; or
(b) circumstances in which the Trust or ExchangeCo may exercise a Retraction Call Right, but elect not to exercise such Retraction Call Right,
a holder of Exchangeable Shares will be entitled to instruct the Trustee to exercise the Optional Exchange Right with respect to any or all of the Exchangeable Shares held by such holder, thereby requiring the Trust or ExchangeCo to purchase such Exchangeable Shares from the holder. Immediately upon the occurrence of (i) an insolvency event, (ii) any event which will, with the passage of time or the giving of notice, become an insolvency event, or (iii) the election by the Trust and ExchangeCo not to exercise a Retraction Call Right which is then exercisable by the Trust and ExchangeCo, Baytex, the Trust or ExchangeCo will give notice thereof to the Trustee. As soon as practicable thereafter, the Trustee will then notify each affected holder of
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Exchangeable Shares (who has not already provided instructions respecting the exercise of the Optional Exchange Right) of such event or potential event and will advise such holder of its rights with respect to the Optional Exchange Right.
The purchase price payable by the Trust or ExchangeCo for each Exchangeable Share to be purchased under the Optional Exchange Right will be satisfied by the issuance of that number of Trust Units equal to the Exchange Ratio as at the last business day prior to the day of closing of the purchase and sale of such Exchangeable Share under the Exchange Right (the “Exchange Price”).
If, as a result of solvency provisions of applicable law, Baytex is unable to redeem all of a holder’s Exchangeable Shares which such holder is entitled to have redeemed in accordance with the Exchangeable Share provisions, the holder will be deemed to have exercised the Optional Exchange Right with respect to the unredeemed Exchangeable Shares and the Trust or ExchangeCo will be required to purchase such shares from the holder in the manner set forth above.
B. Memorandum and Articles of Association
The Company was incorporated in Canada under the Business Corporations Act (Alberta) on June 3, 1993. On August 5, 1993, the Company filed Articles of Amendment to delete the private company restrictions. On October 13, 1993, Articles of Amendment were filed to amend the Company’s capital structure to create Class A Shares and Class B Non-Voting Shares. On October 21, 1997, the Company filed Articles of Amalgamation to amalgamate with its wholly-owned subsidiary, Dorset Exploration Ltd. On May 28, 1999, the Company filed Articles of Amendment to eliminate the Class B Shares and to change the designation of the Class A Shares in the share capital of the Company from “Class A Shares” to “common shares”. On January 1, 2002, the Company filed Articles of Amalgamation to amalgamate with its wholly-owned subsidiaries, OGY Petroleums Ltd. and Triumph Energy Corporation. On September 2, 2003, the Company was amalgamated with Baytex Acquisition Corp. pursuant to the Arrangement.
The Articles of the Company place no restrictions on businesses the Company may carry on.
The Articles of the Company and By-Law No. 1 of the Company may be viewed at the Company’s registered office which is 1400, 350 – 7th Avenue S.W., Calgary, Alberta T2P 3N9.
Directors
Directors need not hold shares in the Company to qualify and be appointed as a director of the Company. The Articles of the Company provide that the minimum number of directors of the Company shall be 3 and the maximum number of directors of the Company shall be 11.
Pursuant to the Business Corporations Act (Alberta), except in certain prescribed circumstances the directors of the Company are required to disclose to the board of the directors of the Company any personal interest that they may have in any material contract prior to the approval of such contract and are required to abstain from voting as a director for the approval of such contract. Directors are permitted to vote on their own compensation. Material credit arrangements with lenders must be approved by ordinary resolution of the board of directors.
Every director of the Company is entitled to be indemnified out of the assets of the Company against all costs, charges and expenses, including any amount paid to settle an action or satisfy a judgment, reasonably incurred by him in respect of any civil, criminal or administrative action or proceeding to which he is made a party by reason of being or having been a director of the Company.
The Company has imposed no mandatory retirement age for its Directors.
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Shareholders Rights
The Company is authorized to issue an unlimited number of common shares and an unlimited number of exchangeable shares.
The holders of any common shares are entitled to dividends if, as and when declared by the directors, to one vote per share at meetings of the holders of common shares of the Company and, upon liquidation, to receive such assets of the Company as are distributable to the holders of the common shares.
Except as required by applicable law, the holders of the Exchangeable Shares are not entitled as such to receive notice of or attend any meeting of the shareholders of the Company or to vote at any such meeting. See Item 10 – Exchangeable Shares.
Fundamental amendments to the rights of the shareholders of the Company can only be effected by alteration of the Articles of the Company, which requires a special resolution of the shareholders of the Company. There are no limitations on the rights to own securities of the Company other than pursuant to the Investment Canada Act (Canada) described elsewhere in this Form 20-F.
Shareholders Meetings
The requirements to hold meetings of the shareholders of Company are described by the Business Corporations Act (Alberta) and By-Law No. 1 of the Company and the Articles of the Company. Shareholders’ meetings may be held at any place within the Province of Alberta or at any of the following cities: Vancouver, British Columbia; Victoria, British Columbia; Winnipeg, Manitoba; Toronto, Ontario; Ottawa, Ontario; Montreal, Quebec; or Halifax, Nova Scotia. The time and place of shareholders meetings is determined by a resolution of the board of directors.
In certain circumstances, and subject to the provisions of the Business Corporations Act (Alberta), shareholders may requisition a meeting of the shareholders without a resolution of the board of directors of the Company.
The calling of shareholder meetings is also subject to securities legislation in Canada, which prescribes the process by which the Company must send proxy materials to its shareholders. Under such securities legislation, proxy materials will generally be mailed to shareholders not less than 21 days before the date of the shareholders meeting.
The proxy materials relating to any shareholders meeting will include a notice of the meeting setting out the time and place of the meeting and the nature of the business to be transacted at the meeting, a form of proxy and management proxy circular containing, together with certain other prescribed information, sufficient description of the matters to be considered at the meeting such that the shareholder can form a reasoned judgment concerning such matters.
Change of Control
Neither the Articles nor By-Laws of the Company restrict the transfer of shares. Therefore, any change of control of the Company or merger, acquisition or corporate restructuring involving the Company would only be subject to generally applicable laws.
NOTES
Pursuant to the Arrangement, Notes were issued to the Trust in return for Trust Units. The Notes are unsecured, payable on demand and bear interest from the date of issue at an interest rate equal to 12% per annum, payable monthly. Baytex is permitted to make payments against the principal amount of the Notes outstanding from time to time without notice or bonus. Unless the Note is called, Baytex is not required to make any payment in respect of principal until December 31, 2033, subject to extension in the limited
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circumstances provided in the Note Indenture. Principal and interest on the Notes are payable in lawful money of Canada directly to the holders of Notes. The Trust is the holder of all of the issued and outstanding Notes. The Notes are unsecured debt obligations of Baytex and rank pari passu with all other unsecured indebtedness of Baytex, but subordinate to all secured debt.
NPI AGREEMENT
Coincident with the Arrangement becoming effective, Baytex and the Trust entered into a Net Profits Intersts Agreement, pursuant to which Baytex granted and set over to the Trust the right to receive certain payments (the “NPI”) on petroleum and natural gas properties held by Baytex.
Pursuant to the terms of the NPI Agreement, the Trust is entitled to a payment from Baytex for each month equal to the amount by which ninety-nine percent of the gross proceeds from the sale of production attributable to the properties for such month (the “NPI Revenues”) exceed ninety-nine percent of certain deductible costs for such period. Baytex may acquire and fund additional properties from residual revenues, borrowings or from its working capital.
If Baytex wishes to dispose of any properties which will result in proceeds in excess of a threshold amount, the Board of Directors of Baytex shall approve such disposition; however, if the asset value (calculated in accordance with the terms of the NPI Agreement) of any interests included in such disposition is greater than a threshold percentage of the asset value of all the Property Interests held by Baytex, such disposition must be approved by a Special Resolution of the unitholders. The term of the NPI Agreement will be for so long as there are petroleum and natural gas rights to which the NPI applies.
The Investment Canada Act generally prohibits implementation of a reviewable investment by an individual, government or agency thereof, corporation, partnership, trust or joint venture that is not a “Canadian” as defined in the Investment Canada Act (a “non-Canadian”), unless after review, the minister responsible for the Investment Canada Act is satisfied that the investment is likely to be of net benefit to Canada. An investment in common shares of the Company by a non-Canadian (other than a “WTO investor” as defined in the Investment Canada Act) would be reviewable under the Investment Canada Act if it was an investment to acquire direct control of the Company and the value of the assets of the Company was $5,000,000 or more.
With regard to an investment in common shares of the Company by a WTO Investor, it would be reviewable under the Investment Canada Act if it was an investment to acquire direct control of the Company and the value of the assets of the Company equals or exceeds a specified amount (the “Review Threshold”), which is
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revised every year. The Review Threshold is $237 million for investments completed in 2004 and is indexed as of the first of January every year.
A non-Canadian, whether a WTO Investor or otherwise, would acquire control of the Company for the purposes of the Investment Canada Act if he acquired a majority of the common shares of the Company. The acquisition of less than a majority but one-third or more of the common shares of the Company would be presumed to be an acquisition of control of the Company unless it could be established the Company was not controlled in fact by the acquirer through the ownership of common shares.
Certain transactions in relation to the common shares of the Company would be exempt from the Investment Act, including:
• an acquisition of common shares of the Company by a person in the ordinary course of that person’s business as a trader or dealer in securities;
• an acquisition of control of the Company in connection with the realization of a security interest granted for a loan or other financial assistance and not for any purpose related to the provision of the Investment Canada Act; and
• an acquisition of control of the Company by reason of an amalgamation, merger, consolidation or corporate reorganization following which the ultimate direct or indirect control in fact of the Company, though the ownership of voting interests, remains unchanged.
The Company’s ability to declare and pay dividends is governed by the covenants in the indentures governing its Senior Secured Notes and in the documentation relating to its credit facilities.
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The following paragraphs set forth material Canadian federal income tax considerations with the purchase, ownership and disposition of the senior secured notes. The discussion is restricted to non-residents of Canada who are residents of the United States and who hold such senior secured notes as capital property. The tax considerations set forth below are based upon the provisions of the Income Tax Act (Canada) (the “ITA”), and on the Convention between Canada and the United States of America with Respect to Taxes on Income and on Capital, as well as regulations, rulings, judicial decisions and administrative practices now in effect in Canada.
Tax Consequences for Non-Resident Holders
A “Non-Resident Holder” of initial notes or exchange notes is someone who, for the purposes of the ITA at all relevant times, is not, and is not deemed to be, resident in Canada, does not use or hold and is not deemed to use or hold the senior secured notes in carrying on a business in Canada, deals at arm’s length with Baytex, is not an authorized foreign bank and is not an insurer that carries on an insurance business in Canada or elsewhere.
Pursuant to the ITA, interest paid or credited or deemed to be paid or credited by Baytex on the senior secured notes, to a Non-Resident Holder will be exempt from Canadian withholding tax. No other taxes on income (including taxable capital gains) will be payable pursuant to the ITA by a Non-Resident Holder in respect of the acquisition, ownership or disposition of the initial notes or exchange notes including exchange of the exchange notes for the initial notes.
F. Dividends and Paying Agents
Not Applicable
Not Applicable
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We file reports and other information with the Securities Exchange Commission (the “SEC”). You may read and copy any reports, statements or other information on file at the SEC’s public reference room at 450 Fifth Street, NW, Washington, D.C. 20549. You can request copies of those documents upon payment of a duplicating fee to the SEC. You may also review a copy of those documents at the SEC’s regional offices in New York, New York. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference rooms. You can review our SEC filings by accessing the EDGAR system through the SEC’s Internet site at www.sec.gov.
You may also access our disclosure documents and any reports, statements or other information that we file with the Canadian provincial securities commissions or other similar regulatory authorities through the Internet on the Canadian System for Electronic Document Analysis and Retrieval, which is commonly known by the acronym SEDAR, and which may be accessed at www.sedar.com.
In addition, you may request a copy of any of these filings, including the documents incorporated by reference in this annual report, at no cost, by writing or telephoning us at the following address or telephone number:
Baytex Energy Ltd.
Suite 2200, Bow Valley Square II
205 - 5th Avenue S.W.
Calgary, Alberta, Canada T2P 2V7
Telephone: (403) 269-4282
Attention: Investor Relations
This document contains summaries of the terms of certain agreements that we believe to be accurate in all material respects. However, we refer you to the actual agreements for complete information relating to those agreements. All summaries are qualified in their entirety by this reference. We will make copies of those documents available to you upon your request to us.
Not Applicable
Item 11. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to all of the normal risks inherent within the oil and gas sector, including commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We manage our operations in a manner intended to minimize our exposure, as described the section in Item 5 entitled “Risk and Risk Management”.
Credit Risk
Credit risk is the risk of loss resulting from non-performance of contractual obligations by a customer or joint venture partner. A substantial portion of our accounts receivable are with customers in the energy industry and are subject to normal industry credit risk. We assess the financial strength of our customers and joint venture partners through regular credit reviews in order to minimize the risk of non-payment.
Foreign Exchange Risk
Baytex’s financial results are impacted by fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar. Crude oil and, to a large extent, natural gas prices are based on reference prices generally denominated in U.S. dollars, while the majority of our expenses are denominated in Canadian dollars. The
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exchange rate also impacts the valuation of our U.S. dollar denominated long-term debt. Changes to the exchange rate between U.S. and Canadian dollars can adversely affect us. When the value of the U.S. dollar increases, we receive higher revenue and when the value of the U.S. dollar declines, we receive lower revenue on the same amount of production sold at the same prices. When the value of the U.S. dollar increases, our U.S. increases and we incur a foreign exchange loss. When the value of the U.S. dollar declines, our U.S. dollar denominated long-term debt decreases and we have a foreign exchange gain. A change of $0.01 in the U.S. to CDN dollar would impact Baytex’s income by approximately $4,790,000 and its cash flow by $3,730,000.
Commodity Price Risk
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. If the WTI oil price were to change by US$1.00 per bbl, the impact on Baytex’s income would be approximately $830,000 and the impact on Baytex’s cash flow would be approximately $1,300,000. If natural gas prices were to change by US$0.50 per mcf, the impact on Baytex’s income would be approximately $6,100,000 and the impact on cash flow would be approximately $9,900,000.
We periodically use hedges with respect to a portion of our oil and natural gas production to mitigate our exposure to price changes. While the use of these derivative arrangements limits the downside risk of price declines, such use may also limit any benefits which may be derived from price increases.
Interest Rate Risk
Interest rate risk exists principally with respect to our indebtedness that bears interest at floating rates. At December 31, 2003, we had no outstanding debt at floating rates. If interest rate were to change by on full percentage point, the net impact on Baytex’s income would be approximately $190,000 and the net impact on Baytex’s cash flow would be approximately $310,000.
Summarized below are Baytex’s sensitivities to various risks, based on its 2003 operations:
|
| Estimated 2003 impact on: |
| ||||
Sensitivities |
| Net Income |
| Cash Flow |
| ||
Crude oil – US$1.00/bbl change in WTI |
| $ | 830,000 |
| $ | 1,300,000 |
|
|
|
|
|
|
| ||
Natural Gas – US$0.50/mcf change |
| $ | 6,100,000 |
| $ | 9,900,000 |
|
|
|
|
|
|
| ||
Foreign Exchange - $0.01 change in U.S. to CDN dollar |
| $ | 4,791,000 |
| $ | 3,730,000 |
|
|
|
|
|
|
| ||
Interest rate – 1% change |
| $ | 190,000 |
| $ | 310,000 |
|
53
Item 12. Description of Securities Other than Equity Securities
Not Applicable
Item 13. Defaults, Dividend Arrearages and Delinquencies
A. Indebtedness
There has been no material default in the payment or principal or interest on our outstanding indebtedness since the date of filing our last annual report on Form 40-F.
B. Preferred Shares
We currently have no preferred shares outstanding.
Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
Not Applicable
Item 15. Controls and Procedures
(a) Evaluation of disclosure controls and procedures.
The Company’s Chief Executive Officer and Chief Financial Officer (its principal executive officer and principal financial officer, respectively) have concluded, based on their evaluation as of the end of the period covered by this annual report (the “evaluation date”), that the Registrant’s and the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by it in reports filed or submitted by it under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by it in such reports is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
(b) Changes in internal controls.
There have been no significant changes to the Company’s internal control over financial reporting or in other factors that could significantly affect internal control over financial reporting subsequent to the evaluation date and prior to the filing date of this annual report.
Item 16 [Reserved]
Item 16A. Audit Committee Financial Expert
The Board of Directors has determined that Mr. Naveen Dargan, an individual serving on the audit committee of the Company’s Board of Directors, is an audit committee financial expert, as that term is defined in Item 401(h)(2) of Regulation S-X under the Securities Exchange Act of 1934, as amended. The Board of Directors has also determined that Mr. Dargan is independent.
54
Item 16B. Code of Ethics
The Company’s code of ethics, which is applicable to its principal executive officer and senior financial officers, is posted on its website at www.baytex.ab.ca. In the event that the Company:
(i) amends any provision of its Code of Ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of the code of ethics definition enumerated in Item 16 B of Form 20-F, or
(ii) grants a waiver, including an implicit waiver, from a provision of its Code of Ethics to any of the Company’s principal executive officer, principal financial officer, principal accounting officer, or controller or persons performing similar functions that relates to any element of the code of ethics definition as enumerated in Item 16B of Form 20-F,
the Company will disclose on its website any amendment to, or waiver of, a provision of its Code of Ethics within five business days following the date of any such amendment or waiver, and will, in the case of a waiver, name the persons to whom the waiver was granted.
Item 16C. Principal Accountant Fees and Services
The following table provides information about the fees billed to Baytex for professional services rendered by Deloitte & Touche LLP, the Registrant’s principal accountant, during fiscal 2003 and 2002:
|
| Aggregate fees billed by the |
| ||
|
| 2003 |
| 2002 |
|
|
| ($thousands) |
| ||
Audit and Audit-related fees |
| 315 |
| 159 |
|
Tax fees |
| 157 |
| 112 |
|
Total |
| 472 |
| 271 |
|
Audit and Audit-Related Fees. Audit and audit-related fees consist of fees for the audit of the Registant’s annual financial statements, services that are normally provided in connection with statutory and regulatory filings or engagements, or audit of certain subsidiaries and financial aspects of the Registrant.
Tax Fees. Tax fees included tax planning and various taxation matters.
The Company’s Audit Committee has the sole authority to review in advance, and grant any appropriate pre-approvals, of all audit and non-audit services to be provided by the independent auditors and, in connection therewith, to approval all fees and other terms of engagement.
55
Item 16D. Exemptions from Listing Standards for Audit Committees
Not Applicable
Item 16 E. Purchase of Equity Securities by the Issuer and Affiliated Purchasers
Not Applicable
Item 17. Financial Statements
Audited Annual Financial Statements:
| |
| |
| |
| |
|
Not Applicable
Number Exhibit
4.1 Articles of Amalgamation of the Registrant
4.2 By-laws of the Registrant
4.3 Arragement Agreement
10.1 Note Indenture dated September 2, 2003 for the issue of 12% Unsecured, Subordinated Promissory Notes
10.2 Net Profits Interests Agreement dated September 2, 2003
10.3 Note Indenture dated July 9, 2003 between the Registrant and The Bank of Nova Scotia Trust Company of New York providing for the issuance of 9 5/8 % Senior Subordinated Notes due 2010
31.1 Certifications of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certifications of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32.1 Certifications of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act
Signature
The registrant hereby certifies that it meets all the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
| Baytex Energy Ltd. | ||
|
| ||
|
| ||
| By: /s/ Daniel G. Belot |
| |
| Name: | Daniel G. Belot | |
| Title: | Vice President, Finance and | |
Dated: July 14, 2004
56
Report of Independent Registered Chartered Accountants
To the Board of Directors of Baytex Energy Ltd.
We have audited the consolidated balance sheets of Baytex Energy Ltd. (the “Company”) as at December 31, 2003 and 2002 and the consolidated statements of operations and deficit and of cash flows for each of the years in the three year period ended December 31, 2003. These financial statements are the responsibility of the management of the Company. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003 in accordance with Canadian generally accepted accounting principles.
|
| (signed) /s/ Deloitte & Touche LLP |
Calgary, Alberta, Canada |
| Registered Chartered Accountants |
June 29, 2004 |
|
|
COMMENT BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES
To the Board of Directors of Baytex Energy Ltd.
The standards of the Public Company Accounting Oversight Board (United States) for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have a material effect on the comparability of the financial statements. As discussed in Note 3 to the consolidated financial statements of Baytex Energy Ltd. (the “Company”), in 2003, the Company adopted recommendations with respect to determining stock-based compensation to conform to new recommendations of Section 3870 of the Canadian Institute of Chartered Accountants and in 2002, the Company changed its method for accounting for foreign currency translation to conform to new recommendations of Section 1650 of the Canadian Institute of Chartered Accountants. Our report to the board of directors of Baytex Energy Ltd. dated June 29, 2004 is expressed in accordance with Canadian auditing standards, which do not require a reference to such changes in accounting principles in the auditors’ report when the changes are properly accounted for and adequately disclosed in the financial statements.
|
| (signed) /s/ Deloitte & Touche LLP |
Calgary, Alberta, Canada |
| Registered Chartered Accountants |
June 29, 2004 |
|
|
F-1
Baytex Energy Ltd.
As at December 31, 2003 and 2002
(thousands of Canadian dollars)
|
| 2003 |
| 2002 |
| ||
Assets |
|
|
|
|
| ||
Current assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 53,731 |
| $ | 4,098 |
|
Accounts receivable |
| 48,608 |
| 52,667 |
| ||
Crude oil inventory |
| 5,900 |
| — |
| ||
|
| 108,239 |
| 56,765 |
| ||
|
|
|
|
|
| ||
Deferred charges and other assets |
| 7,764 |
| 8,679 |
| ||
Petroleum and natural gas properties (note 5) |
| 748,988 |
| 932,316 |
| ||
|
| $ | 864,991 |
| $ | 997,760 |
|
|
|
|
|
|
| ||
Liabilities |
|
|
|
|
| ||
Current liabilities |
|
|
|
|
| ||
Accounts payable and accrued liabilities |
| $ | 80,360 |
| $ | 92,563 |
|
Due to Baytex Energy Trust |
| 61,032 |
| — |
| ||
|
| 141,392 |
| 92,563 |
| ||
|
|
|
|
|
| ||
Long-term debt (note 7) |
| 769,903 |
| 326,977 |
| ||
Exchangeable shares (note 9) |
| 42,243 |
| — |
| ||
Deferred credits (note 8) |
| — |
| 12,181 |
| ||
Provision for future site restoration costs |
| 23,483 |
| 21,950 |
| ||
Future income taxes (note 13) |
| 176,516 |
| 184,402 |
| ||
|
| 1,153,537 |
| 638,073 |
| ||
Commitments and contingencies (note 17) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Shareholders’ Equity |
|
|
|
|
| ||
Common shares (note 10) |
| — |
| 398,176 |
| ||
Contributed surplus (note 11) |
| 224 |
| — |
| ||
Deficit |
| (288,770 | ) | (38,489 | ) | ||
|
| (288,546 | ) | 359,687 |
| ||
|
| $ | 864,991 |
| $ | 997,760 |
|
See accompanying notes to the consolidated financial statements.
On behalf of the Board
Naveen Dargan |
| W. A. Blake Cassidy |
Director |
| Director |
F-2
Baytex Energy Ltd.
Consolidated Statements of Operations and Deficit
Years Ended December 31, 2003, 2002 and 2001
(thousands of Canadian dollars, except per share data)
|
| 2003 |
| 2002 |
| 2001 |
| |||
Revenue |
|
|
|
|
|
|
| |||
Petroleum and natural gas sales |
| $ | 351,404 |
| $ | 365,860 |
| $ | 329,700 |
|
Royalties |
| (54,244 | ) | (58,922 | ) | (57,805 | ) | |||
|
| 297,160 |
| 306,938 |
| 271,895 |
| |||
Expenses |
|
|
|
|
|
|
| |||
Operating |
| 86,034 |
| 75,228 |
| 83,439 |
| |||
General and administrative |
| 8,927 |
| 6,743 |
| 5,262 |
| |||
Stock-based compensation (note 11) |
| 739 |
| — |
| — |
| |||
Net profits interest (note 18) |
| 15,398 |
| — |
| — |
| |||
Interest (note 7) |
| 45,079 |
| 25,217 |
| 32,942 |
| |||
Costs on redemption and exchange of notes (note 7) |
| 44,771 |
| — |
| — |
| |||
Foreign exchange (gain) loss (note 7) |
| (52,101 | ) | (2,691 | ) | 16,262 |
| |||
Gain on exchangeable shares |
| (3,513 | ) | — |
| — |
| |||
Depletion and depreciation |
| 110,463 |
| 106,834 |
| 367,384 |
| |||
Site restoration costs |
| 2,973 |
| 2,799 |
| 3,912 |
| |||
Reorganization costs (note 4) |
| 18,851 |
| — |
| — |
| |||
|
| 277,621 |
| 214,130 |
| 509,201 |
| |||
|
|
|
|
|
|
|
| |||
Income (loss) before income taxes |
| 19,539 |
| 92,808 |
| (237,306 | ) | |||
|
|
|
|
|
|
|
| |||
Income taxes (recovery) (note 13) |
|
|
|
|
|
|
| |||
Current |
| 9,663 |
| 9,716 |
| 7,128 |
| |||
Future |
| (11,500 | ) | 37,956 |
| (107,327 | ) | |||
|
| (1,837 | ) | 47,672 |
| (100,199 | ) | |||
|
|
|
|
|
|
|
| |||
Net income (loss) |
| 21,376 |
| 45,136 |
| (137,107 | ) | |||
|
|
|
|
|
|
|
| |||
Retained earnings (deficit), beginning of year, as previously reported |
| (38,489 | ) | (75,954 | ) | 52,555 |
| |||
|
|
|
|
|
|
|
| |||
Reorganization of share capital (note 4) |
| (271,657 | ) | — |
| — |
| |||
|
|
|
|
|
|
|
| |||
Accounting policy change for foreign exchange (note 3) |
| — |
| (7,671 | ) | 927 |
| |||
|
|
|
|
|
|
|
| |||
Deficit, beginning of year, as restated |
| (38,489 | ) | (83,625 | ) | 53,482 |
| |||
|
|
|
|
|
|
|
| |||
Deficit, end of year |
| $ | (288,770 | ) | $ | (38,489 | ) | $ | (83,625 | ) |
|
|
|
|
|
|
|
| |||
Net income (loss) per share (note 12) |
|
|
|
|
|
|
| |||
Basic |
| $ | 0.60 |
| $ | 0.86 |
| $ | (2.77 | ) |
Diluted |
| $ | 0.60 |
| $ | 0.85 |
| $ | (2.77 | ) |
See accompanying notes to the consolidated financial statements.
F-3
Baytex Energy Ltd.
Consolidated Statements of Cash Flows
Years Ended December 31, 2003, 2002 and 2001
(thousands of Canadian dollars)
|
| 2003 |
| 2002 |
| 2001 |
| |||
Cash provided by (used in): |
|
|
|
|
|
|
| |||
Operating activities |
|
|
|
|
|
|
| |||
Net income (loss) |
| $ | 21,376 |
| $ | 45,136 |
| $ | (137,107 | ) |
Items not affecting cash: |
|
|
|
|
|
|
| |||
Stock based compensation (note 11) |
| 739 |
| — |
| — |
| |||
Amortization of deferred charges |
| 1,027 |
| 1,052 |
| 946 |
| |||
Gain on exchangeable shares |
| (3,513 | ) | — |
| — |
| |||
Costs on redemption and exchange of notes (note 7) |
| 44,771 |
| — |
| — |
| |||
Foreign exchange (gain) loss |
| (52,101 | ) | (2,691 | ) | 16,262 |
| |||
Depletion and depreciation |
| 110,463 |
| 106,834 |
| 367,384 |
| |||
Site restoration costs |
| 2,973 |
| 2,799 |
| 3,912 |
| |||
Future income taxes (recovery) |
| (11,500 | ) | 37,956 |
| (107,327 | ) | |||
|
| 114,235 |
| 191,086 |
| 144,070 |
| |||
Change in non-cash working capital (note 14) |
| (7,828 | ) | 1,272 |
| 5,682 |
| |||
(Increase) decrease in deferred charges and other assets |
| 211 |
| (1,057 | ) | — |
| |||
Decrease in deferred credits |
| (2,213 | ) | (18,694 | ) | 18,694 |
| |||
|
| 104,405 |
| 172,607 |
| 168,446 |
| |||
Financing activities |
|
|
|
|
|
|
| |||
Issue of senior subordinated term notes |
| — |
| — |
| 227,895 |
| |||
Redemption of senior secured notes (note 7) |
| (89,950 | ) | — |
| — |
| |||
Decrease in bank loan and other debt |
| — |
| (76,254 | ) | (88,474 | ) | |||
Increase in deferred charges and other assets |
| (7,425 | ) | — |
| (9,037 | ) | |||
Increase in deferred credits |
| — |
| 12,181 |
| — |
| |||
Issue of common shares (note 10) |
| 37,049 |
| 3,497 |
| 1,444 |
| |||
Repurchase of common shares |
| — |
| (55 | ) | (860 | ) | |||
Change in non-cash working capital |
| 61,032 |
| — |
| — |
| |||
|
| 706 |
| (60,631 | ) | 130,968 |
| |||
Investing activities |
|
|
|
|
|
|
| |||
Corporate acquisitions (note 19) |
| — |
| — |
| (249,152 | ) | |||
Items not affecting cash: |
|
|
|
|
|
|
| |||
Shares issued on acquisition |
| — |
| — |
| 68,104 |
| |||
Assumption of long-term debt |
| — |
| — |
| 36,356 |
| |||
Assumption of working capital |
| — |
| — |
| (2,734 | ) | |||
|
| — |
| — |
| (147,426 | ) | |||
Petroleum and natural gas property expenditures |
| (186,756 | ) | (182,048 | ) | (189,283 | ) | |||
Disposal of petroleum and natural gas properties |
| 137,493 |
| 55,580 |
| 62,582 |
| |||
Properties held for sale |
| — |
| (46,895 | ) | 46,895 |
| |||
Change in non-cash working capital (note 14) |
| (6,215 | ) | 65,485 |
| (72,182 | ) | |||
|
| (55,478 | ) | (107,878 | ) | (299,414 | ) | |||
Change in cash and cash equivalents during the year |
| 49,633 |
| 4,098 |
| — |
| |||
Cash and cash equivalents, beginning of year |
| 4,098 |
| — |
| — |
| |||
Cash and cash equivalents, end of year |
| $ | 53,731 |
| $ | 4,098 |
| $ | — |
|
See accompanying notes to the consolidated financial statements.
F-4
Baytex Energy Ltd.
Notes to the Consolidated Financial Statements
Years Ended December 31, 2003, 2002 and 2001
(all tabular amounts in thousands of Canadian dollars, except per share amounts)
1. BASIS OF PRESENTATION
On September 2, 2003, Baytex Energy Ltd. (the “Company” or “Baytex”) completed a Plan of Arrangement (the “Arrangement”) involving Baytex, Baytex Energy Trust (the “Trust”), and Crew Energy Inc. (“Crew”). Holders of common shares of Baytex elected or were deemed to have elected to receive either Trust Units or Exchangeable Shares of Baytex for their common shares on the basis of one Trust Unit or Exchangeable Share, respectively, for each common share held. Coincident with the Arrangement becoming effective, certain of Baytex’s exploration assets were acquired by Crew, and the common shares of Crew were distributed to the former holders of Baytex common shares on the basis of one-third of a common share of Crew for each common share of Baytex held. Subsequent to the Arrangement, the Company is a subsidiary of the Trust.
Prior to the Arrangement, the consolidated financial statements included the accounts of the Company and its subsidiaries and partnership. After giving effect to the Arrangement, the consolidated financial statements include the accounts of the Company and its subsidiaries and have been prepared by management in accordance with Canadian generally accepted accounting principles as described in Note 2. The reconciliation of the financial statements to United States generally accepted accounting principles is contained in Note 20.
2. SIGNIFICANT ACCOUNTING POLICIES
Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries from the respective dates of acquisition of the subsidiary companies. Inter-company transactions and balances are eliminated upon consolidation.
Measurement Uncertainty
The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results can differ from those estimates.
In particular, amounts recorded for depreciation and depletion and amounts used for ceiling test calculations are based on estimates of petroleum and natural gas reserves and future costs required to develop those reserves. The Company’s reserve estimates are evaluated annually by an independent engineering firm. By their nature, these estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact on the consolidated financial statements of future periods could be material.
Cash and Cash Equivalents
Cash and cash equivalents include monies on deposit and short-term investments, accounted for at cost, which have an initial maturity date of not more than 90 days.
Crude Oil Inventory
Crude oil inventory, consisting of production in transit in pipelines at the balance sheet date pursuant to a long-term crude oil supply agreement, is valued at the lower of cost or net realizable value.
F-5
Petroleum and Natural Gas Operations
The Company follows the full cost method of accounting for its petroleum and natural gas operations whereby all costs relating to the exploration for and development of petroleum and natural gas reserves are capitalized in one Canadian cost centre and charged against income, as set out below. Such costs include land acquisition, drilling of productive and non-productive wells, geological and geophysical, production facilities, carrying costs directly related to unproved properties and corporate expenses directly related to acquisition, exploration and development activities and do not include any costs related to production or general overhead expenses. These costs along with estimated future capital costs that are based on current costs and that are incurred in developing proved reserves are depleted and depreciated on a unit of production basis using estimated gross proved petroleum and natural gas reserves. For purposes of this calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of gas equates to one barrel of oil. Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether proved reserves are attributable to the properties or impairment occurs. Unproved properties are evaluated for impairment on an annual basis.
Gains or losses on the disposition of petroleum and natural gas properties are recognized only when crediting the proceeds to costs would result in a change of 20 percent or more in the depletion rate.
The net amount at which petroleum and natural gas properties are carried is subject to a cost recovery test (the “ceiling test”). Under this test, an estimate is made of the ultimate recoverable amount from future net revenues using proved reserves plus the net costs of major development projects and unproved properties, less future removal and site restoration costs, overhead, financing costs and income taxes, using period end prices and costs. If the net carrying costs exceed the ultimate recoverable amount, additional depletion and depreciation is provided.
Provision for Future Site Restoration Costs
Estimates are made of the future site restoration costs relating to the Company’s petroleum and natural gas properties at the end of their economic life, based on year end values, in accordance with current legislative requirements and industry practice. Annual charges are provided on a unit of production method. Actual expenditures incurred are applied against the provision for future site restoration costs.
Joint Interests
A portion of the Company’s exploration, development and production activities is conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Foreign Currency Translation
Foreign currency denominated monetary items are translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Exchange gains and losses on long-term monetary items that do not qualify for hedge accounting are recognized in income.
Revenue and expenses are translated at the monthly average rate of exchange. Translation gains and losses are included in net income.
F-6
Deferred Charges and Other Assets
Financing costs related to the exchange of the senior subordinated notes have been deferred and are amortized over the term of the notes on a straight-line basis.
Financial Instruments
The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The risk management policies include the permitted use of derivative financial instruments, including swaps and collars, used to manage these fluctuations. All transactions of this nature entered into by the Company are related to an underlying financial instrument or to future petroleum and natural gas production. The Company does not use derivative financial instruments for trading or speculative purposes. Gains and losses on derivative contracts are recognized in income based on the underlying financial instrument or the future petroleum and natural gas production in same period that the transactions are settled. The fair values of derivative instruments are not recorded in the consolidated balance sheet.
Gains and losses related to derivative financial instruments that have been closed prior to the end of the term are deferred and recognized in the consolidated statement of operations over the original term of the instrument.
Future Income Taxes
The Company is subject to corporate income taxes and follows the liability method of accounting for income taxes. Income taxes are accounted for under the liability method of tax allocation, which determines future income taxes based on the differences between assets and liabilities reported for financial accounting purposes and those reported for tax purposes. Future income taxes are calculated using tax rates anticipated to apply in periods that temporary differences are expected to reverse.
Flow-through Shares
The Company had financed a portion of its exploration and development activities through the issue of flow-through shares. Under the terms of the flow-through share agreements, the tax attributes of the related expenditures are renounced to the subscribers. Accordingly, the carrying value of the expenditures incurred and the shares issued are recorded net of tax benefits renounced to the subscribers. The Company records the gross carrying value of the expenditures and records a future tax liability for the tax benefits renounced to subscribers.
Stock-based Compensation
Employees of Baytex have the right to participate in the Trust Unit Rights Incentive Plan (the “Plan”), which is described in note 10. The exercise price of the rights granted under the Plan may be reduced in future periods in accordance with the terms of the Plan. Therefore, it is not possible to determine a fair value for the rights granted under the Plan using a traditional option pricing model and compensation expense has been determined based on the intrinsic value of the rights at the date of exercise or at the date of the consolidated financial statements for unexercised rights.
F-7
Compensation expense associated with rights granted under the plan is recognized in earnings over the vesting period of the Plan with a corresponding increase or decrease in contributed surplus. Changes in the intrinsic value of unexercised rights after the vesting period are recognized in income in the period of change with a corresponding increase or decrease in contributed surplus. The exercise of trust unit rights are recorded as an increase in trust units with a corresponding reduction in contributed surplus.
This method of determining compensation expense may result in large fluctuations, even recoveries, in compensation expense due to changes in the underlying trust unit price. Recoveries of compensation expense will only be recognized to the extent of previously recorded cumulative compensation expense associated with rights outstanding at the date of the financial statements.
Per-share Amounts
Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding during the year. Diluted per share amounts reflect the potential dilution that could occur if outstanding stock options were exercised. The treasury stock method is used to determine the dilutive effect of stock options, whereby any proceeds from the exercise of stock options or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period.
3. CHANGES IN ACCOUNTING POLICIES
Stock-based Compensation Plan
The Company has elected to prospectively adopt amendments to Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments” pursuant to the transitional provisions contained therein. Under this amended standard, the Company must account for compensation expense based on the fair value of rights granted to its employees under the Trust Unit Rights Incentive Plan. As the Company is unable to determine the fair value of the rights granted, compensation expense has been determined based on the intrinsic value of the rights at the exercise date or at the date of the consolidated financial statements for unexercised rights. Compensation expense of $0.22 million was recorded as non cash expense for all the unit rights granted during 2003, with a corresponding amount recorded as contributed surplus.
The adoption of these amendments also impacted the stock options of the Company outstanding prior to the Plan of Arrangement. Compensation expense of $0.52 million was recorded for all stock options granted on or after January 1, 2003, with a corresponding amount recorded as contributed surplus. For stock options granted prior to January 1, 2003, the pro forma earnings impact of related stock-based compensation expense is disclosed (see Note 11).
Foreign Currency
Effective January 1, 2002, the Company retroactively adopted the CICA amended accounting standard with respect to accounting for foreign currency translation. As a result of the amendments, all exchange gains and losses on long-term monetary items that do not qualify for hedge accounting are recognized in income. Previously, these exchange gains and losses were deferred and amortized over the remaining life of the monetary item. The impact of the amended standard on the year ended December 31, 2002 was to increase net income by $1.8 million. The effect of this change on the December 31, 2001 consolidated balance sheet is an elimination of the unrealized foreign exchange loss of $13.7 million, a decrease in future income taxes of $6.0 million, and an increase in the deficit of $7.7 million.
F-8
4. TRANSFER OF ASSETS AND LIABILITIES PURSUANT TO PLAN OF ARRANGEMENT
Under the Plan of Arrangement (note 1), the Company transferred to Crew a portion of the Company’s producing and exploratory petroleum and natural gas assets. As this was a related party transaction, assets and liabilities were transferred at carrying value as follows:
Petroleum and natural gas assets and equipment |
| $ | 21,244 |
|
Future income tax asset |
| 3,278 |
| |
Total assets transferred |
| 24,522 |
| |
Provision for future site restoration |
| (559 | ) | |
Net assets transferred and reduction in share capital (note 10) |
| $ | 23,963 |
|
Under the Plan of Arrangement, the share capital of the Company was reorganized and the holders of old common shares of Baytex elected or were deemed to have elected to receive either Trust Units or Exchangeable Shares of Baytex for their old common shares. This reorganization of share capital resulted in a charge of $271.6 million to the deficit.
Reorganization costs of $18.9 million were expensed in the consolidated statements of operations as a result of the Plan of Arrangement.
5. PETROLEUM AND NATURAL GAS PROPERTIES
|
| As at December 31, |
| ||||
|
| 2003 |
| 2002 |
| ||
Petroleum and natural gas properties |
| $ | 1,916,378 |
| $ | 1,989,246 |
|
Accumulated depletion and depreciation |
| (1,167,390 | ) | (1,056,930 | ) | ||
|
| $ | 748,988 |
| $ | 932,316 |
|
During 2003, $4.4 million (2002 - $6.7 million) of corporate expenses relating to exploration and development activities were capitalized. No corporate expenses have been capitalized since the effective date of the Plan of Arrangement on September 2, 2003. In calculating the depletion and depreciation provision for 2003, $51.1 million (2002 - $80.3 million) of costs relating to undeveloped properties and materials and supplies of $4.0 million (2002- $5.5 million) were excluded from costs subject to depletion and depreciation.
As a result of the ceiling test performed at December 31, 2001, the Company recorded additional depletion and depreciation on its petroleum and natural gas properties of $234.5 million ($131.3 million net of income tax).
6. BANK CREDIT FACILITIES
On September 3, 2003, the Company entered into a new credit agreement with a syndicate of chartered banks. The credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance rates plus applicable margins or LIBOR rates plus applicable margins. The facilities aggregating $165 million are subject to semi-annual review beginning in November 2003 and are secured by a floating charge over all of the Company’s assets. At December 31, 2003, there were no amounts outstanding under the bank credit facilities.
F-9
7. LONG-TERM DEBT
|
| As at December 31, |
| ||||
|
| 2003 |
| 2002 |
| ||
Senior secured notes (2002 US$57,000,000) |
| $ | — |
| $ | 90,037 |
|
10.5% senior subordinated notes (2003 - US$247,000; 2002 – US$150,000,000) |
| 319 |
| 236,940 |
| ||
9.625% senior subordinated notes (2003 -US$179,699,000) |
| 232,243 |
| — |
| ||
12% unsecured, subordinated promissory note |
| 527,398 |
| — |
| ||
12% unsecured, subordinated promissory note |
| 9,943 |
| — |
| ||
|
| $ | 769,903 |
| $ | 326,977 |
|
Senior Secured Notes
On November 13, 1998, the Company issued US$57 million of senior secured notes, bearing interest at 7.23 percent payable quarterly with principal repayable on November 13, 2004. In May 2003, the Company redeemed the outstanding senior secured notes for a total cash payment of $90 million, resulting in a cost of $4.7 million on the redemption. Foreign exchange gains were included in income until the redemption of the notes.
Senior Subordinated Notes
On February 12, 2001, the Company issued US$150 million of senior subordinated notes (“Old Notes”) bearing interest at 10.5 percent payable semi-annually with principal repayable on February 15, 2011. These notes are unsecured and are subordinate to the Company’s bank credit facilities.
On July 9, 2003, the Company completed an exchange offer related to its Old Notes. The Company issued US$179.7 million of 9.625 percent senior subordinated notes due July 15, 2010 (“New Notes”) in exchange for US$149.8 million of the Old Notes and incurred a non-cash loss of $40.0 million on the completion of this transaction, which was recognized in income. The New Notes are unsecured and are subordinate to the Company’s bank credit facilities.
Unsecured, subordinated promissory note
On September 2, 2003, the Company issued $627.4 million of unsecured, subordinated promissory notes to the Trust. A total of $100.0 million of the unsecured, subordinated promissory notes were cancelled on the grant to the Trust of a net profits interest in certain petroleum and natural gas properties. The notes bear interest at 12 percent payable monthly with principal repayable on September 1, 2033. These notes are unsecured and are subordinate to the Company’s bank credit facilities and senior subordinated notes.
Unsecured, subordinated promissory note
During 2003, the Company issued a total of $9.9 million of unsecured, subordinated promissory notes to ExchangeCo. The notes bear interest at 12 percent payable monthly with principal repayable on September 1, 2033. These notes are unsecured and are subordinate to the Company’s bank credit facilities and senior subordinated notes.
F-10
Interest Expense
The Company has incurred interest expense on its outstanding debt as follows:
|
| 2003 |
| 2002 |
| 2001 |
| |||
Bank loan |
| $ | 675 |
| $ | 760 |
| $ | 4,620 |
|
Amortization of deferred charges |
| 1,027 |
| 1,052 |
| 946 |
| |||
Senior subordinated notes |
| 21,846 |
| 23,405 |
| 27,376 |
| |||
Unsecured, subordinated promissory notes |
| 21,531 |
| — |
| — |
| |||
Total interest |
| $ | 45,079 |
| $ | 25,217 |
| $ | 32,942 |
|
The total interest expense on the Company’s long-term debt during 2003 was $43.4 million (2002 - $23.4 million; 2001 - $27.4 million).
8. DEFERRED CREDITS
|
| As at December 31, |
| ||||
|
| 2003 |
| 2002 |
| ||
Deferred interest swap settlement |
| $ | — |
| $ | 12,181 |
|
In August 2002, the Company terminated all outstanding interest rate swap agreements for total proceeds of $14.1 million. This amount was deferred and was being amortized as a reduction of interest expense over the original terms of the agreements. The amortization was terminated when the senior secured notes were redeemed and when the exchange offer related to the Old Notes was concluded (note 7). The residual balance was included in the cost on redemption and exchange of notes.
During 2001, the Company renegotiated certain derivative contracts related to 2002 commodity prices and received a net payment of $18.7 million. This amount was recognized in income during 2002.
9. EXCHANGEABLE SHARES
Exchangeable Shares
The Company is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares can be converted (at the option of the holder) into trust units at any time up to September 2, 2013. The exchangeable shares are automatically redeemable at September 2, 2013. Up to 1.9 million exchangeable shares may be redeemed annually by the Company for either cash or the issue of trust units purchased from the Trust. The number of trust units issued upon conversion is based upon the exchange ratio in effect at the conversion date. The exchange ratio is calculated monthly based on the cash distribution paid by the Trust divided by the weighted average trust unit price of the five-day trading period ending on the record date. The exchange ratio at December 31, 2003 was 1.04530 trust units per exchangeable share. Cash distributions are not paid on the exchangeable shares. The exchangeable shares are not publicly traded. Because the exchangeable shares may be redeemed for cash, or by the issue of trust units purchased from the Trust, the exchangeable shares are considered a liability. The cash required to redeem the exchangeable shares or to purchase trust units is based on the fair value of the trust units.
Exchangeable Shares |
| Number of |
| Amount |
| |
Issued September 2, 2003 pursuant to the Arrangement |
| 4,732 |
| $ | 55,699 |
|
Exchanged for trust units of the Trust |
| (1,007 | ) | (9,943 | ) | |
Adjustment to fair value |
| — |
| (3,513 | ) | |
Balance December 31, 2003 |
| 3,725 |
| $ | 42,243 |
|
10. SHAREHOLDERS’ CAPITAL
Common Shares
The Company is authorized to issue an unlimited number of common shares. Under the Arrangement, the Company’s former issued and outstanding common shares were exchanged for Trust units or exchangeable shares. One new common share was issued to the Trust, under the Arrangement, for one dollar.
F-11
Under the Plan of Arrangement, former shareholders of the Company received one unit of the Trust or one exchangeable share and one-third of a share of Crew for each former common share held.
Former common shares of Baytex Energy Ltd. |
| Number of |
| Amount |
| |
Balance December 31, 2000 |
| 45,797 |
| $ | 326,727 |
|
Issued for corporate acquisitions (note 18) |
| 6,119 |
| 68,104 |
| |
Stock options exercise |
| 314 |
| 1,444 |
| |
Normal course issuer bid |
| (222 | ) | (860 | ) | |
Future tax related to flow-through shares |
| — |
| (721 | ) | |
Balance December 31, 2001 |
| 52,008 |
| 394,734 |
| |
Exercise of stock options |
| 820 |
| 3,497 |
| |
Normal course issuer bid |
| (9 | ) | (55 | ) | |
Balance December 31, 2002 |
| 52,819 |
| 398,176 |
| |
Flow-through shares issued |
| 103 |
| 810 |
| |
Future tax related to flow-through shares |
| — |
| (336 | ) | |
Exercise of stock options (note 11) |
| 5,115 |
| 36,239 |
| |
Transfer of assets under Plan of Arrangement (note 4) |
| — |
| (23,963 | ) | |
Balance September 2, 2003 prior to Plan of Arrangement |
| 58,037 |
| 410,926 |
| |
Trust units issued |
| (53,305 | ) | (377,419 | ) | |
Exchangeable shares issued |
| (4,732 | ) | (33,507 | ) | |
Balance December 31, 2003 |
| — |
| $ | — |
|
Flow-through shares
In accordance with the terms of flow-through share offerings entered into by the Company and pursuant to certain provisions of the Income Tax Act (Canada), the Company fulfilled its commitment to renounce for income tax purposes exploration expenditures of $0.8 million in 2003 to the subscribers of the flow-through shares.
Normal course issuer bid
During the year ended December 31, 2002, the Company acquired 9,200 (2001 – 222,400) of its common shares through a normal course issuer bid program at an average cost of $6.03 per share (2001 - $3.87 per share). The shares purchased under the normal course issuer bid were cancelled. In January 2003, the Company renewed the normal course issuer bid to purchase up to 5.2 million common shares of the Company during the 12-month period beginning January 7, 2003. The normal course issuer bid was terminated on September 2, 2003, with no shares purchased.
11. STOCK-BASED COMPENSATION
Effective September 2, 2003, the Trust established a Trust Unit Rights Incentive Plan to replace the stock option plan of the Company. The Company’s employees are entitled to participate in the Trust Unit Rights Incentive Plan. A total of 5,800,000 Trust Unit Rights are reserved for issue under the Plan. Trust Unit Rights
F-12
are granted at the market price of the trust units at the time of the grant, vest over three years and have a term of five years.
The Trust Unit Rights Incentive Plan allows for the exercise price of the rights to be reduced in future periods by a portion of the future distributions provided a certain threshold return on assets is met. The Company has determined that the amount of the reduction cannot be reasonably estimated, as it is dependent upon a number of factors including, but not limited to, future trust unit prices, production of oil and natural gas, determination of amounts to be withheld from future distributions to fund capital expenditures, and the purchase and sale of oil and natural gas assets. Therefore, it is not possible to determine a fair value for the rights granted under the plan.
Compensation expense is therefore determined based on the amount that the market price of the trust unit exceeds the exercise price for rights issued as at the date of the consolidated financial statements and is recognized in income over the vesting period of the plan. The adoption of the amendments related to accounting for unit-based compensation results in compensation expense for year ended December 31, 2003 was $0.22 million (note 3).
The number of unit rights issued and exercise prices are detailed below:
|
| Number of |
| Weighted average |
| |
Initial grant September 9, 2003 |
| 2,593 |
| $ | 10.23 |
|
Granted |
| 380 |
| $ | 9.60 |
|
Cancelled |
| (118 | ) | $ | 10.23 |
|
Balance December 31, 2003 |
| 2,855 |
| $ | 10.15 |
|
(1) Exercise price reflects grant price less reduction in exercise price as discussed above.
The following table summarizes information about the unit rights outstanding at December 31, 2003:
|
| Number |
| Weighted |
| Weighted |
| Number |
| Weighted |
| |
|
|
|
| (years) |
|
|
|
|
|
|
| |
Balance December 31, 2003 |
| 2,855 |
| 4.7 |
| $ | 10.15 |
| — |
| — |
|
The Company had a stock option plan prior to the Plan of Arrangement. The outstanding stock options of the Company were exercised or cancelled as follows:
F-13
|
| Number of |
| Weighted average |
| |
Balance December 31, 2001 |
| 4,468 |
| $ | 6.19 |
|
Granted |
| 1,682 |
| $ | 7.61 |
|
Exercised |
| (820 | ) | $ | 4.27 |
|
Cancelled |
| (204 | ) | $ | 5.78 |
|
Balance December 31, 2002 |
| 5,126 |
| $ | 6.98 |
|
Granted |
| 121 |
| $ | 9.28 |
|
Exercised |
| (5,115 | ) | $ | 7.07 |
|
Cancelled |
| (132 | ) | $ | 5.44 |
|
Balance December 31, 2003 |
| — |
| — |
|
The adoption of the amendments related to accounting for unit-based compensation also impacted the accounting for stock options granted by the Company to employees before the implementation of the Plan of Arrangement. Compensation expense of $0.52 million was recorded for all stock options granted by the Company on or after January 1, 2003, with a corresponding amount recorded as trust units on exercise of the options, with expenses in the first and second quarters increased by $0.32 million and $0.20 million, respectively. Accordingly, quarterly net income in such quarters previously reported as $32.9 million and $41.8 million would be revised to $32.6 million and $41.6 million, respectively. There were no changes to the expenses or the net loss of the third quarter of 2003.
Compensation expense for options granted during 2003 was based on the estimated fair values at the time of the grant and the expense was recognized over the vesting period of the option. For options granted prior to January 1, 2003, the pro forma income impact of related stock-based compensation expense is as follows:
|
| Year Ended December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
Net income as reported |
| $ | 21,376 |
| $ | 45,136 |
|
Stock-based compensation expense |
| (5,522 | ) | (612 | ) | ||
Pro forma |
| $ | 15,854 |
| $ | 44,524 |
|
|
|
|
|
|
| ||
Net income per share: |
|
|
|
|
| ||
Basic as reported |
| $ | 0.60 |
| $ | 0.86 |
|
Pro forma |
| $ | 0.44 |
| $ | 0.85 |
|
Diluted as reported |
| $ | 0.60 |
| $ | 0.85 |
|
Pro forma |
| $ | 0.44 |
| $ | 0.83 |
|
The weighted average fair market value of options granted during the year ended December 31, 2003 was $4.21 per option (2002 - $3.65 per option). The fair value of the stock options granted was estimated on the grant date based on the Black-Scholes option-pricing model using the following assumptions:
|
| Year Ended December 31 |
| ||
|
| 2003 |
| 2002 |
|
Risk-free interest rate |
| 4.5 |
| 4.0 |
|
Volatility in the price of the Company’s common shares |
| 52 |
| 57 |
|
Expected life (years) |
| 4 |
| 4 |
|
Dividends paid |
| Nil |
| Nil |
|
F-14
The Company had granted stock appreciation rights (“Rights”) to certain employees. Holders of the Rights were entitled to receive incentive payments based on the difference between market price of the Company’s common shares and exercise price of the Rights. The exercise price of the Rights was determined based on the market price of the Company’s common shares at the time the Rights were granted. The Rights vested over three years and had a term of four years. During 2002, all 202,334 remaining Rights (2001 – 6,666) were exercised. The related compensation expense has been included in general and administrative expenses.
12. NET INCOME PER SHARE
The Company applies the treasury stock method to assess the dilutive effect of outstanding stock options on net income per share. The number of shares used in the calculation of diluted net income per share is determined as follows:
|
| 2003 |
| 2002 |
| 2001 |
|
Weighted average number of shares outstanding, basic |
| 35,765 |
| 52,298 |
| 49,503 |
|
Dilutive effect of stock options |
| — |
| 939 |
| 701 |
|
Weighted average number of shares outstanding, diluted |
| 35,765 |
| 53,237 |
| 50,204 |
|
At December 31, 2003, there were no dilutive instruments outstanding. The dilutive effect of stock options above did not include in 2002 2.8 million stock options and in 2001 1.3 million stock options because the respective exercise prices exceeded the average market price of the common shares during the year.
13. INCOME TAXES (RECOVERY)
The provision for (recovery of) income taxes has been computed as follows:
|
| 2003 |
| 2002 |
| 2001 |
| |||
Income (loss) before income taxes |
| $ | 19,539 |
| $ | 92,808 |
| $ | (237,306 | ) |
Expected income taxes at the statutory rate of 42.5% (2002 – 43.9%; 2001 – 44.0%) |
| $ | 8,304 |
| $ | 40,743 |
| $ | (104,415 | ) |
Increase (decrease) in taxes resulting from: |
|
|
|
|
|
|
| |||
Crown royalties |
| 15,954 |
| 21,153 |
| 19,870 |
| |||
Resource allowance |
| (18,334 | ) | (26,308 | ) | (22,560 | ) | |||
Alberta royalty tax credit |
| (213 | ) | (219 | ) | (224 | ) | |||
Non-taxable portion of foreign exchange gain |
| (11,074 | ) | — |
| — |
| |||
Rate change |
| (5,064 | ) | (138 | ) | 183 |
| |||
Stock-based compensation |
| 314 |
| — |
| — |
| |||
Other |
| (1,387 | ) | 2,725 |
| (181 | ) | |||
Large corporation tax and provincial capital tax |
| 9,663 |
| 9,716 |
| 7,128 |
| |||
Provision for (recovery of) income taxes |
| $ | (1,837 | ) | $ | 47,672 |
| $ | (100,199 | ) |
F-15
The components of future income taxes are as follows:
|
| As at December 31, |
| ||||
|
| 2003 |
| 2002 |
| ||
Future income tax liabilities: |
|
|
|
|
| ||
Capital assets |
| $ | 202,657 |
| $ | 202,429 |
|
Other |
| 2,560 |
| — |
| ||
Future income tax assets: |
|
|
|
|
| ||
Provision for future site restoration |
| (8,907 | ) | (9,638 | ) | ||
Reorganization costs |
| (19,794 | ) | (2,833 | ) | ||
Loss carry-forward |
| — |
| (323 | ) | ||
Other |
| — |
| (5,233 | ) | ||
Future income taxes |
| $ | 176,516 |
| $ | 184,402 |
|
14. CASH FLOW INFORMATION
Increase (Decrease) in Non-Cash Working Capital Items
|
| 2003 |
| 2002 |
| 2001 |
| |||
Current assets |
| $ | (1,840 | ) | $ | 38,528 |
| $ | (23,440 | ) |
Current liabilities |
| 48,829 |
| 28,229 |
| (43,060 | ) | |||
|
| $ | 46,989 |
| $ | 66,757 |
| $ | (66,500 | ) |
|
| 2003 |
| 2002 |
| 2001 |
| |||
Changes in non cash working capital related to: |
|
|
|
|
|
|
| |||
Operating activities |
| $ | (7,828 | ) | $ | 1,272 |
| $ | 5,682 |
|
Financing activities |
| 61,032 |
| — |
| — |
| |||
Investing activities |
| (6,215 | ) | 65,485 |
| (72,182 | ) | |||
|
| $ | 46,989 |
| $ | 66,757 |
| $ | (66,500 | ) |
During the year the Company made the following cash outlays in respect of interest expense and current income taxes.
|
| 2003 |
| 2002 |
| 2001 |
| |||
Interest |
| $ | 24,449 |
| $ | 25,482 |
| $ | 22,889 |
|
Current income taxes (refund) |
| $ | 12,557 |
| $ | (3,298 | ) | $ | (15,459 | ) |
15. FINANCIAL INSTRUMENTS
The Company’s financial instruments recognized in the consolidated balance sheet consist of cash and cash equivalents accounts receivable, current liabilities and long-term borrowings, and exchangeable shares. The estimated fair values of the financial instruments have been determined based on the Company’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction.
The fair values of financial instruments other than long-term borrowings approximate their carrying amounts due to the short-term maturity of these instruments. At December 31, 2003, the trading value of the Company’s senior subordinated term notes was 105 percent in relation to par (2002- 105 percent).
F-16
16. DERIVATIVE CONTRACTS
The nature of the Company’s operations results in exposure to fluctuations in commodity prices, exchange rates and interest rates. The Company monitors and, when appropriate, utilizes derivative contracts to manage its exposure to these risks. The Company is exposed to credit-related losses in the event of non-performance by counter-parties to these contracts. In 2003, petroleum and natural gas sales were reduced by $33.8 million (2002 - $8.3 million; 2001 - $9.5 million) due to derivative contracts.
At December 31, 2003, the Company had derivative contracts for the following:
|
| Period |
| Volume |
| Price |
| Index |
|
Oil |
|
|
|
|
|
|
|
|
|
Price collar |
| Calendar 2004 |
| 5,000 bbls/d |
| US$24.00 – $28.60 |
| WTI |
|
Price collar |
| Calendar 2004 |
| 1,500 bbls/d |
| US$24.00 – $29.05 |
| WTI |
|
Price collar |
| Calendar 2004 |
| 1,500 bbls/d |
| US$24.00 – $29.08 |
| WTI |
|
Price collar |
| Calendar 2004 |
| 1,000 bbls/d |
| US$24.00 – $29.38 |
| WTI |
|
Price collar |
| Calendar 2004 |
| 1,000 bbls/d |
| US$24.00 – $29.48 |
| WTI |
|
Price collar |
| Calendar 2004 |
| 2,000 bbls/d |
| US$24.00 – $30.55 |
| WTI |
|
Price collar |
| Calendar 2004 |
| 3,000 bbls/d |
| US$24.00 – $32.05 |
| WTI |
|
The fair value of the oil derivative contracts at December 31, 2003 is an unrecognized liability of $13.8 million.
|
|
|
|
|
| Exchange Rate |
| ||
|
| Period |
| Amount |
| Floor |
| Cap |
|
Foreign currency |
|
|
|
|
|
|
|
|
|
Collar |
| Calendar 2004 |
| US$3,000,000 per month |
| CAD/USD $1.3100 |
| CAD/USD $1.3400 |
|
Collar |
| Calendar 2004 |
| US$3,000,000 per month |
| CAD/USD $1.3280 |
| CAD/USD $1.3560 |
|
Collar |
| Calendar 2004 |
| US$3,000,000 per month |
| CAD/USD $1.3160 |
| CAD/USD $1.3365 |
|
Collar |
| Calendar 2004 |
| US$3,000,000 per month |
| CAD/USD $1.3400 |
| CAD/USD $1.3665 |
|
The fair value of the foreign currency contracts at December 31, 2003 is an unrecognized asset of $3.7 million.
|
| Period |
| Principal |
| Rate |
|
Interest rate swap |
|
|
|
|
|
|
|
|
| November 2003 to July 2010 |
| US$179,699,000 |
| 3-month LIBOR plus 5.2% |
|
The fair value of the interest rate swap at December 31, 2003 is an unrecognized asset of $3.9 million.
17. COMMITMENTS AND CONTINGENCIES
In October 2002, the Company entered into a long-term crude oil supply contract with a third party that requires the delivery of up to 20,000 barrels per day of Lloydminster Blend crude oil at a price fixed at 71% of NYMEX WTI oil price. The contract is for an initial term of five years commencing January 1, 2003. The contract volumes increased from 9,000 barrels per day in January 2003 to 20,000 barrels per day in October 2003 and thereafter.
For the period November 2003 to March 2004, the Company has entered into natural gas physical sales contracts with third parties for a total of 9.5 mmcf per day for prices collared between $5.28 and $8.57 per
F-17
mcf. For the period April 2004 to October 2004, the Company has entered into natural gas physical sales contracts with third parties for a total of 9.5 mmcf per day for prices collared between $4.75 and $6.75 per mcf.
The Company is engaged in litigation and claims arising in the normal course of operations, none of which could reasonably be expected to materially affect the Company’s financial position or reported results of operations.
Under the Net Profits Interests Agreement between the Company and the Trust, the Company will establish in 2004 a reclamation fund to fund the payment of environmental and site restoration costs.
18. RELATED PARTY TRANSACTIONS
On September 2, 2003, the Company issued $527.4 million of unsecured, subordinated promissory notes to Baytex Energy Trust. The notes bear interest at 12 percent payable monthly with principal repayable on September 1, 2033. These notes are unsecured and are subordinate to the Company’s bank credit facilities and senior subordinated notes.
During 2003, the Company issued a total of $9.9 million of unsecured, subordinated promissory notes to ExchangeCo. The notes bear interest at 12 percent payable monthly with principal repayable on September 1, 2033. These notes are unsecured and are subordinate to the Company’s bank credit facilities and senior subordinated notes.
On September 2, 2003, Baytex completed the Arrangement whereby holders of common shares of Baytex elected or were deemed to have elected to receive either Trust Units of the Trust or Exchangeable Shares of Baytex for their common shares on the basis of one Trust Unit or Exchangeable Share, respectively, for each common share held. Coincident with the Arrangement becoming effective, certain of Baytex’s exploration assets were acquired by Crew, and the common shares of Crew were distributed to the former holders of Baytex common shares on the basis of one-third of a common share of Crew for each such share held.
Coincident with the Arrangement becoming effective, Baytex and the Trust entered into a Net Profits Interests Agreement, pursuant to which Baytex granted and set over to the Trust the right to receive certain payments (the “NPI”) on petroleum and natural gas properties held by Baytex.
Pursuant to the terms of the NPI Agreement, the Trust is entitled to a payment from Baytex for each month equal to the amount by which ninety-nine percent of the gross proceeds from the sale of production attributable to the properties for such month exceed ninety-nine percent of certain deductible costs for such period. Baytex may acquire and fund additional properties from residual revenues, borrowings or from its working capital.
If Baytex wishes to dispose of any properties which will result in proceeds in excess of a threshold amount, the Board of Directors of Baytex shall approve such disposition; however, if the asset value (calculated in accordance with the terms of the NPI Agreement) of any interests included in such disposition is greater than a threshold percentage of the asset value of all the Property Interests held by Baytex, such disposition must be approved by a Special Resolution of the unitholders. The term of the NPI Agreement will be for so long as there are petroleum and natural gas rights to which the NPI applies.
F-18
19. CORPORATE ACQUISITIONS
Effective May 1, 2001, the Company acquired all of the issued and outstanding shares of OGY Petroleums Ltd. (“OGY”), a public company involved in the exploration, development and production of oil and natural gas in Western Canada. The acquisition has been accounted for by the purchase method of accounting as follows:
Consideration |
|
|
| |
Cash |
| $ | 50,683 |
|
Transaction costs |
| 3,100 |
| |
|
| 53,783 |
| |
Issue of 1,169,481 common shares |
| 14,057 |
| |
|
| $ | 67,840 |
|
Net Assets Acquired |
|
|
| |
Petroleum and natural gas properties |
| $ | 116,607 |
|
Future income taxes |
| (36,127 | ) | |
Future site restoration costs |
| (1,844 | ) | |
|
| 78,636 |
| |
Working capital deficiency |
| (4,809 | ) | |
Long-term debt |
| (5,987 | ) | |
|
| $ | 67,840 |
|
Effective June 1, 2001, the Company acquired all of the issued and outstanding shares of Triumph Energy Corporation (“Triumph”), a public company involved in the exploration, development and production of oil and natural gas in Western Canada. The acquisition has been accounted for by the purchase method of accounting as follows:
Consideration |
|
|
| |
Cash |
| $ | 82,337 |
|
Transaction costs |
| 11,306 |
| |
|
| 93,643 |
| |
Issue of 4,949,245 common shares |
| 54,047 |
| |
|
| $ | 147,690 |
|
Net Assets Acquired |
|
|
| |
Petroleum and natural gas properties |
| $ | 248,480 |
|
Future income taxes |
| (77,751 | ) | |
Future site restoration costs |
| (213 | ) | |
|
| 170,516 |
| |
Working capital |
| 7,543 |
| |
Long-term debt |
| (30,369 | ) | |
|
| $ | 147,690 |
|
F-19
20. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”), which in most respects, conform to generally accepted accounting principles in the United States of America (“U.S. GAAP”). The significant differences in those principles, as they apply to the Company, are as follows:
(a) Under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at 10 percent, (based on prices and costs at the balance sheet date) plus the lower of cost or fair value of unproven properties (“ceiling test”). Under Canadian GAAP, this ceiling test is calculated without application of a discount factor, but interest and general and administrative expenses are deducted.
As a result of applying the U.S. GAAP ceiling test in prior years, the Company recorded additional depletion of $340.7 million before income tax. At December 31, 2001, the application of the full cost ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $234.6 million ($131.4 million after tax). Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion and depreciation will differ in subsequent years resulting in U.S. to Canadian GAAP differences.
(b) The Financial Accounting Standards Board (“FASB”) has issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”). FAS 143 was adopted prospectively on January 1, 2003 and requires liability recognition for retirement obligations associated with tangible long-lived assets. The initial measurement of the asset retirement obligation is required to be at fair value. The asset retirement cost equal to the fair value of the retirement obligation is to be capitalized as part of the cost of the related long-lived asset and amortized to expense over the useful life of the asset. The liability accretes until the expected settlement of the retirement obligation.
This change in accounting policy has been accounted for as a cumulative effect adjustment in the consolidated statement of operations as a loss of $7.1 million, net of income taxes of $5.6 million.
The change in the asset retirement obligation since January 1, 2003 is as follows:
Asset retirement obligation January 1, 2003 |
| $ | 52,244 |
|
Increase in retirement obligations |
| 4,010 |
| |
Abandonment expenditures |
| (880 | ) | |
Property disposition |
| (3,335 | ) | |
Accretion |
| 3,957 |
| |
Asset retirement obligation December 31, 2003 |
| $ | 55,996 |
|
Prior to January 1, 2003, under U.S. GAAP, the provision for future site restoration costs is recorded as a reduction of capital assets. Under Canadian GAAP, effective January 1, 2004, the Company will adopt new Canadian accounting standards for accounting for asset retirement obligations which are expected to eliminate this difference in future years.
(c) FASB has issued Statement of Financial Accounting Standards No. 123, “Accounting for Stock-based Compensation” (“FAS 123”) which establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire
F-20
goods or services from non-employees. As permitted by the FAS 123, the Company elected to follow the intrinsic value method of accounting for stock-based compensation arrangements, as provided for in Accounting Principles Board Opinion 25 (“APB 25”), for all stock options issued by the Company to employees before the effective date of the Plan of Arrangement. Since all stock options were granted with exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income at the time of the option grants. Had compensation cost for the Company’s stock options been determined based on the fair market value at the grant dates of the awards consistent with methodology prescribed by FAS 123, the net income (loss) and net income (loss) per unit for years ended December 31, 2003 and 2002 would have been the pro forma amounts indicated below:
|
| Year Ended December 31 |
| |||||||
|
| 2003 |
| 2002 |
| 2001 |
| |||
Net income (loss) as reported under U.S. GAAP |
| $ | (26,154 | ) | $ | 22,889 |
| $ | (124,963 | ) |
Stock based compensation expense |
| (5,522 | ) | (612 | ) | (398 | ) | |||
Pro forma |
| $ | (31,676 | ) | $ | 22,277 |
| $ | (125,361 | ) |
|
|
|
|
|
|
|
| |||
Net income (loss) per unit: |
|
|
|
|
|
|
| |||
Basic as reported |
| $ | (0.73 | ) | $ | 0.44 |
| $ | (2.52 | ) |
Pro forma |
| $ | (0.88 | ) | $ | 0.43 |
| $ | (2.53 | ) |
|
|
|
|
|
|
|
| |||
Diluted as reported |
| $ | (0.73 | ) | $ | 0.43 |
| $ | (2.52 | ) |
Pro forma |
| $ | (0.88 | ) | $ | 0.42 |
| $ | (2.52 | ) |
The weighted average fair market value of stock options granted by the Company (before the effective date of the Plan of Arrangement) in 2003 was $4.21 per stock option (2002 - $3.65; 2001 - $2.46). The fair value of the stock options granted was estimated on the grant date based on the Black-Scholes option-pricing model using the following weighted average assumptions:
|
| Year Ended December 31 |
| ||||
|
| 2003 |
| 2002 |
| 2001 |
|
Risk-free interest rate |
| 4.5 |
| 4.0 |
| 5.0 |
|
Volatility in the price of the Company’s common shares |
| 52 |
| 57 |
| 61 |
|
Expected life (years) |
| 4 |
| 4 |
| 4 |
|
Dividends paid |
| Nil |
| Nil |
| nil |
|
APB 25 also requires recognition of compensation cost with respect to changes in intrinsic value for variable employee stock compensation plans. As the stock options granted by the Company were modified as part of the Plan of Arrangement, and in prior years certain stock options were repriced, the modified stock options are subject to variable plan accounting, which results in an increase of compensation cost of $12.0 million for the year ended December 31, 2003 (2002 – increase in compensation costs of $0.8 million; 2003 – reduction on compensation costs of $0.8 million) for U.S. GAAP purposes.
After the effective date of the Plan of Arrangement, the Trust established a Trust Unit Incentive Right Plan to replace the stock option plan of the Company. The Company’s employees are entitled to participate in the Trust Unit Rights Incentive Plan. As the exercise price of the unit rights granted under the plan is subject to downward revisions from time to time, the unit rights plan is a variable compensation plan under U.S. GAAP. Accordingly, compensation expense is determined as the excess of the market price over the exercise price at the end of each reporting period and is recognized in income over the vesting period of the rights. The
F-21
accounting for compensation expense for the unit rights plan does not result in a difference between Canadian and U.S. GAAP.
(d) The Company adopted the liability method of accounting for income taxes in 2000 retroactively without restatement. The liability method of accounting for income taxes is similar to Statement of Financial Accounting Standards No. 109, which requires the use of the asset and liability method. The Canadian GAAP liability method requires the measurement of future income tax liabilities and assets using income tax rates that reflect enacted income tax rate reductions provided it is more likely than not that the Company will be eligible for such rate reductions in the period of reversal. U.S. GAAP allows recording of such reductions only when claimed.
(e) Statement of Financial Accounting Standards No. 133, “Accounting for Derivative instruments and Hedging Activities” (FAS 133), as modified by Statement No. 138 “Accounting for Certain Derivative Instruments and Certain Hedging Activities”, establishes accounting and reporting standards requiring that every derivative instrument be recorded in the consolidated balance sheet as either an asset or liability measured at its fair value, and that change in the fair value be recognized currently in income unless specific hedge accounting criteria are met. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspects of the hedge. Those methods must be consistent with the entity’s approach to managing risk. As hedge accounting was not applied to the financial derivative contracts, at December 31, 2003, the Company’s financial derivative instruments would be recorded as a liability on the consolidated balance sheet at their fair value of $6.2 million (2002 – $14.3 million; 2001 – an asset on the balance sheet of $12.9 million). FAS 133 also requires that gain and losses on financial derivative instruments be included in the statement of operations when terminated prior to the completion of the contract. As a result, $12.2 million realized on the termination of interest rate swap derivative contracts would be included as an increase of the net income for December 31, 2002. The net loss under U.S. GAAP for the year ended December 31, 2001 was reduced by $18.7 million for the amount realized on renegotiation of financial derivative contracts
(f) The income tax effect of the items noted in (a) through (e) for the year ended December 31, 2003 is a decrease in income taxes of $21.0 million (2002 – decrease of $15.9 million).
(g) Prior to January 1, 2000, the Company recorded the renouncement of tax deductions resulting from the issuance of flow through shares by reducing petroleum and natural gas properties and shareholders’ equity by the estimated cost of the tax deductions renounced. U.S. GAAP requires that flow-though shares be recorded at their fair value without any adjustment for the renouncement of tax deductions and that the estimated costs for the tax deductions be recorded as a future income tax liability rather than a reduction of petroleum and natural gas properties. Subsequent to January 1, 2000, no differences arose in the accounting treatment of flowthrough shares under Canadian GAAP and U.S. GAAP.
(h) Effective January 1, 2002, the Company retroactively adopted the Canadian Institute of Chartered Accountants (CICA) amended accounting standard with respect to accounting for foreign currency translation. As a result of the amendments, all exchange gains and losses on long-term monetary items that do not qualify for hedge accounting are recognized in income. Previously under Canadian GAAP, these exchange gains and losses were deferred and amortized over the remaining life of the monetary item. The effect of this change is to make the accounting for exchange gains and losses on foreign denominated long-term monetary items consistent under both Canadian GAAP and U.S. GAAP. The U.S. GAAP reconciliation for the years presented have been retroactively restated as there is no longer a difference in accounting principles.
F-22
(i) Statement of Financial Accounting Standards No. 130 “Comprehensive Income” requires the reporting of comprehensive income in addition to net income. Comprehensive income includes net income plus other comprehensive income. Management believes that it has no other comprehensive income; accordingly comprehensive income is equivalent to net income.
Consolidated Statements of Operations
The application of U.S. GAAP would have the following effect on net income as reported:
|
| Years Ended December 31 |
| |||||||
|
| 2003 |
| 2002 |
| 2001 |
| |||
Net income (loss) for the year – Canadian GAAP |
| $ | 21,376 |
| $ | 45,136 |
| $ | (137,107 | ) |
Adjustments: |
|
|
|
|
|
|
| |||
Depletion (a) |
| (41,386 | ) | (2,613 | ) | (11,041 | ) | |||
Ceiling test write-down (a) |
| — |
| — |
| (266 | ) | |||
Accretion (b) |
| (3,957 | ) | — |
| — |
| |||
Compensation cost (c) |
| (11,972 | ) | (1,873 | ) | 787 |
| |||
Deferred revenue (e) |
| — |
| (18,694 | ) | 18,694 |
| |||
Interest rate swaps (e) |
| (12,181 | ) | 12,181 |
| — |
| |||
Financial derivative instruments (e) |
| 8,109 |
| (27,193 | ) | 12,893 |
| |||
Income taxes (f) |
| 21,006 |
| 15,945 |
| (8,923 | ) | |||
Net income (loss) from continuing operations before cumulative effect of change in accounting policy for asset retirement obligations |
| (19,005 | ) | 22,889 |
| (124,963 | ) | |||
Cumulative effect of change in accounting policy for asset retirement obligations (b) |
| (7,149 | ) | — |
| — |
| |||
Net income (loss) for the year – U.S. GAAP |
| $ | (26,154 | ) | $ | 22,889 |
| $ | (124,963 | ) |
Net income (loss) from continuing operations before cumulative effect of change in accounting policy for asset retirement obligations per share |
|
|
|
|
|
|
| |||
Basic |
| $ | (0.53 | ) | $ | 0.44 |
| $ | (2.52 | ) |
Diluted |
| $ | (0.53 | ) | $ | 0.43 |
| $ | (2.52 | ) |
|
|
|
|
|
|
|
| |||
Net income (loss) per share – U.S. GAAP |
|
|
|
|
|
|
| |||
Basic |
| $ | (0.73 | ) | $ | 0.44 |
| $ | (2.52 | ) |
Diluted |
| $ | (0.73 | ) | $ | 0.43 |
| $ | (2.52 | ) |
F-23
Consolidated Balance Sheets
The application of U.S. GAAP would have the following effect on the consolidated balance sheets as reported:
|
| December 31, 2003 |
| |||||||
|
| As |
| Increase |
| U.S. |
| |||
Assets: |
|
|
|
|
|
|
| |||
Capital assets (a) |
| $ | 748,988 |
| $ | (161,477 | ) | $ | 603,075 |
|
(b) |
|
|
| 15,564 |
|
|
| |||
|
|
|
|
|
|
|
| |||
Liabilities: |
|
|
|
|
|
|
| |||
Asset retirement obligations (b) |
| — |
| 55,996 |
| 55,996 |
| |||
Provision for site restoration costs (b) |
| 23,483 |
| (23,483 | ) | — |
| |||
Financial derivative instruments (e) |
| — |
| 6,191 |
| 6,191 |
| |||
Future income taxes (f) |
| 176,516 |
| (70,961 | ) | 105,555 |
| |||
|
|
|
|
|
|
|
| |||
Shareholders’ equity: |
|
|
|
|
|
|
| |||
Deficit – see below |
| (288,770 | ) | (148,972 | ) | (437,742 | ) | |||
|
| December 31, 2002 |
| |||||||
|
| As |
| Increase |
| U.S. |
| |||
Assets: |
|
|
|
|
|
|
| |||
Capital assets (a) |
| $ | 932,316 |
| $ | (120,091 | ) | $ | 790,275 |
|
(b) |
|
|
| (21,950 | ) |
|
| |||
|
|
|
|
|
|
|
| |||
Liabilities: |
|
|
|
|
|
|
| |||
Provision for site restoration costs (b) |
| 21,950 |
| (21,950 | ) | — |
| |||
Financial derivative instruments (e) |
| — |
| 14,300 |
| 14,300 |
| |||
Future income taxes (f) |
| 184,402 |
| (57,398 | ) | 127,004 |
| |||
Deferred credits (e) |
| 12,181 |
| (12,181 | ) | — |
| |||
|
|
|
|
|
|
|
| |||
Shareholders’ equity: |
|
|
|
|
|
|
| |||
Shareholders’ capital (g) |
| 398,176 |
| 13,942 |
| 412,118 |
| |||
Deficit – see below |
| (38,489 | ) | (87,500 | ) | (125,989 | ) | |||
F-24
|
| December 31, |
| ||||
|
| 2003 |
| 2002 |
| ||
Deficit - Canadian GAAP |
| $ | (288,770 | ) | $ | (38,489 | ) |
Adjustments to depletion (a) |
| (169,549 | ) | (128,163 | ) | ||
Flow through share differences (g) |
| (13,942 | ) | (13,942 | ) | ||
Accretion expense (b) |
| (3,957 | ) | — |
| ||
Compensation expense (c) |
| (13,845 | ) | (1,873 | ) | ||
Financial derivative instruments (e) |
| (6,191 | ) | (14,300 | ) | ||
Deferred credits (e) |
| — |
| 12,181 |
| ||
Adjustments to future income taxes (f) |
| 79,603 |
| 58,597 |
| ||
Shareholders’ Capital (g) |
| (13,942 | ) | — |
| ||
Cumulative effect of change in accounting policy for asset retirement obligation (b) |
| (7,149 | ) | — |
| ||
Deficit - U.S. GAAP |
| $ | (437,742 | ) | $ | (125,989 | ) |
Consolidated Statements of Cash Flow
The application of U.S. GAAP would have the following effect on the operating activities of the consolidated statement of cash flow:
|
| Years Ended December 31 |
| |||||||
|
| 2003 |
| 2002 |
| 2001 |
| |||
Operating activities |
|
|
|
|
|
|
| |||
Cash provided by (used in) operating activities – Canadian GAAP |
| $ | 104,405 |
| $ | 172,607 |
| $ | 168,446 |
|
Adjustments: |
|
|
|
|
|
|
| |||
Deferred revenue (e) |
| — |
| (18,694 | ) | 18,694 |
| |||
Interest rate swaps (e) |
| (12,181 | ) | 12,181 |
| — |
| |||
Cash provided by (used in) operating activities – U.S. GAAP |
| $ | 92,224 |
| $ | 166,094 |
| $ | 187,140 |
|
Consolidated Statements of Cash Flows
The consolidated statements of cash flows includes, under investing activities, items not affecting cash, related to the non-cash elements of corporate acquisitions. This disclosure is provided in order to disclose the aggregate costs related to such activities and to then deduct the related non-cash amounts to arrive at cash amounts. This presentation is not permitted under U.S. GAAP.
F-25
Recent Developments in U.S. Accounting
In May 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No.150 “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity”, which establishes standards for classification and measurement of certain financial instruments. The adoption of this accounting standard did not have a material impact on the Company.
In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities” (“FIN 46”). FIN 46 provides criteria for identifying variable interest entities and for determining what entity, if any, should be included in consolidated financial statements. In December 2003, the FASB issued FIN 46(R) to clarify some of the provisions of FIN 46 and to exempt certain entities from its requirements. The adoption on January 1, 2004 of this accounting standard is not anticipated to have a material impact on the Company.
In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 104 “Revenue Recognition” (“SAB 104”), which will rescind accounting guidance contained in Staff Accounting Bulletin No. 101 related to multiple element revenue arrangements. The changes noted in SAB 104 are not anticipated to have a material impact on the Company’s financial position, results of operations or cash flows.
21. RECENT DEVELOPMENTS IN CANADIAN ACCOUNTING
In November 2002, the Canadian Institute of Chartered Accountants (CICA) amended its accounting guideline on hedging relationships, which was originally issued in November 2001. The guideline addresses the identification, designation, documentation and effectiveness of hedging transactions for the purposes of applying hedge accounting. It also establishes conditions for applying or discontinuing hedge accounting. Under the new guideline, hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective to continue accrual accounting for positions hedged with derivatives. The new guidline is effective for fiscal years, beginning on or after July 1, 2003. As of January 1, 2004, the company has recorded as a deferred charge the unrealized loss of $10.1 million for the mark-to-market value of the outstanding non-hedging financial derivatives. This balance is being recognized over the term of the previously designated hedged item.
Baytex has elected to prospectively adopt amendments to CICA Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments”, pursuant to the transitional provisions contained therein. Under this amended standard, Baytex is required to account for compensation expense based on the fair value of rights granted under its unit-based compensation plan. As Baytex is unable to determine the fair value of the rights granted, compensation expense has been determined based on the intrinsic value of the rights at the exercise date or at the date of the financial statements for unexercised rights. Compensation expense of $0.22 million was recorded as compensation expense for all trust unit rights granted on or after January 1, 2003, with a corresponding amount recorded as contributed surplus.
The adoption of these amendments also impacted the stock options outstanding prior to the Plan of Arrangement. Compensation expense of $0.52 million was recorded as compensation expense for all stock options granted on or after January 1, 2003, with a corresponding amount recorded as contributed surplus. For stock options granted prior to January 1, 2003, the pro forma earnings impact of related stock-based compensation expense is disclosed in note 11 of the consolidated financial statements.
In March 2003, the CICA issued Section 3110, “Asset Retirement Obligations”. This section requires recognition of a liability at discounted fair value for the future abandonment and reclamation associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The new standard is effective for all fiscal years beginning on or after January 1, 2004. The impact of the adoption of this standard is estimated to be an increase in asset retirement obligation on the balance sheet of $33 million at December 31, 2003.
In February 2003, the CICA issued Accounting Guideline 14, “Disclosure of Guarantees” (“AcG-14”). AcG-14 establishes the disclosures required for obligations under certain guarantees. The disclosure requirements are effective for interim and annual periods beginning on or after January 1, 2003 and have been made in note 17 of the consolidated financial statements.
In 2003, the CICA issued Accounting Guideline 16, “Oil and Gas Accounting – Full Cost” (“AcG-16”). The guideline is effective for fiscal years beginning on or after January 1, 2004. The new guideline proposes amendments to the ceiling test calculation applied by Baytex. The ceiling test was changed to a two-stage process which is to be performed at least annually. The first stage of the test is a recognition test which compares the undiscounted future cash flow from proved reserves to the net book value of the petroleum and natural gas assets to determine if the assets are impaired. An impairment loss exists when the carrying amount of the petroleum and natural gas assets exceeds such undiscounted cash flow. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the net book value of the petroleum and natural gas assets exceeds the future discounted cash flow from proved plus probable reserves. The adoption of this new guideline on January 1, 2004 is not anticipated to have an impact on the financial results of Baytex.
On November 10, 2003, the CICA issued a draft EIC (D37) on “Income Trusts - Exchangeable Units”. The EIC proposes that the retained interest of the exchangeable shareholders should be presented on the balance sheet as a non-controlling interest separate and distinct from unitholder’s equity. This draft EIC is currently under review and was not enacted in final form as of the time of release of Baytex’s consolidated financial statements.
In June 2003 the CICA issued Accounting Guideline 15 “Consolidation of Variable Interest Entities”, which deals with the consolidation of entities that are subject to control on a basis other than ownership of voting interests. This guideline is effective for annual and interim periods beginning on or after November 1, 2004. Baytex has assessed that this new guideline is not applicable based on the current structure of Baytex and therefore will have no impact on the financial statements of Baytex.
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