October 18, 2006
Via Fax: (202) 772-9368
United States Securities and Exchange Commission
100 F Street, N.E., Stop 7010
Washington, D.C. 20549
Attention: Ms. Jill S. Davis
Branch Chief
Dear Ms. Davis:
Re: Baytex Energy Trust
Form 40-F for Fiscal Year Ended December 31, 2005
Filed March 31, 2006
File No. 001-32754
Form 40-F for the Fiscal Year ended December 31, 2005
We have received your letter dated September 12, 2006 related to the Form 40-F as referenced above (the “Form 40-F”). We thank you for you comments, and wish to advise that we have carefully considered your views in the context of our disclosure obligations. In general terms, we believe that Baytex Energy Trust (the “Trust” or “Baytex”) has materially met all of its disclosure obligations in respect of its December 31, 2005 year end Form 40-F filing. Several of your comments, specifically comments numbered 1, 2, 6, 7, 12, 13, 15, and 19 requested that we amend and re-file our Form 40-F. We have addressed each of your comments below, and propose for some of these listed items to amend our disclosures for our 2006 fiscal year and following years where such an amendment could add clarity to our filings. For other of your comments, we make note of why we believe our disclosures are appropriate, and propose that no further current or future disclosure is required. Details of our proposals are noted below. We look forward to discussing these matters with you at your convenience. If you have any questions or concerns related to the content of this letter, please do not hesitate to contact the writer at (403) 538 - 3639.
Disclosure of Reserve data, page 18
| 1. | We note your disclosure beginning on page 18 regarding your reserve information which includes the term “future net revenue.” Please discretely disclose the definition of this metric. |
We refer the Staff to page 3 of the Annual Information Form (“AIF”) included in our Form 40-F which states that “certain terms used herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings in this AIF as in NI 51-101.” The term “future net revenue” is defined in NI 51-101. However, in response to the Staff’s comment we propose to add a definition of future net revenue in our 2006 filings.
For your own information, the definition of “future net revenue” in NI51-101 is as follows:
Future net revenue
The estimated net amount to be received with respect to the development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using:
(a) constant prices and costs; or
(b) forecast prices and costs.
This net amount is computed by deducting, from estimated future revenues:
• estimated amounts of future royalty obligations;
• costs related to the development and production of reserves;
• well abandonment costs; and
• future income tax expenses, unless otherwise specified in NI 51-101, Form 51-101F1 or Form 51-101F2.
Corporate general and administrative expenses and financing costs are not deducted. Net present values of future net revenue may be calculated using a discount rate or without discount.
Audit Fees
| 2. | Please expand your disclosure to describe the nature of the services comprising all other audit fees. Refer to General Instruction B(10)(4) of Form 40-F. |
We believe that we have complied with General Instruction B(10)(4) through our disclosure on page 3 of the AIF. “All Other Fees” relates entirely to consultation services for property taxes. Such fees were pre-approved by the audit committee. The disclosure in the 2005 Form 40-F (page 3) notes that this line item “included advisory services associated with property taxes”. As the nature of the services is disclosed, we do not propose to amend the filing for 2005. If a similar situation exists for 2006, we will again disclose the nature of the “other fees”.
Managements’ Discussion and Analysis, page 1
| 3. | We note your disclosure that indicates that certain measures are not prescribed by Canadian GAAP. Please indicate whether or not these measures are prescribed by NI-51-101 and whether or not your calculations are consistent with the National Instrument. |
Cash flow from operations and cash flow per unit are two of the measures used which are not prescribed by Canadian GAAP nor by NI-51-101. They are key performance indicators and industry benchmarks included in many publications issued by companies in the oil & gas industry. CSA Staff Notice 52-306 Non-GAAP Financial Measures provides guidelines to issuers on disclosure of non-GAAP financial measures and requires issuers to:
1. state explicitly that the non-GAAP financial measure does not have any standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other issuers;
2. present with equal or greater prominence than the non-GAAP financial measure the most directly comparable measure calculated in accordance with GAAP;
3. explain why the non-GAAP financial measure provides useful information to investors and how management uses the non-GAAP financial measure;
4. provide a clear quantitative reconciliation from the non-GAAP financial measure to the most directly comparable measure calculated in accordance with GAAP, referencing to the reconciliation when the non-GAAP financial measure first appears in the disclosure document;
5. explain any changes in the composition of the non-GAAP financial measure when compared to previously disclosed measures.
We believe that we have substantially met our requirements under this Staff Notice as follows. On page 1, paragraph 2 of the MD&A, we have identified the nature and purpose of the non-GAAP measurements used, cautioning readers on the potential non-comparability to other entities. On page 25, we have also disclosed the net income and per unit information. Such information would be the most directly comparable measure calculated in accordance with GAAP. There were no changes to the composition of the non-GAAP measures. We did not include a quantitative reconciliation of cash flow from operations to net income as this information is included in our fourth quarter press release made public on a prior date. In response to the Staff’s comments we propose to include this reconciliation in our 2006 and subsequent disclosures. Investors in oil and gas income trusts are typically interested in the cash flow generation of the trust, as one of the key benefits of a trust is the periodic payment of cash distributions. Disclosure of cash flow generated per unit provides users with information on the ability of the trust to fund ongoing distributions and capital programs.
Other measures referred to in the preamble to the MD&A include the disclosures of “netbacks”. These disclosures related to netbacks are prescribed by NI 51-101 (in paragraph 5.13), and our disclosures are in accordance with that instrument.
Several other measures were referred to in the preamble to the MD&A as measures which management looks to in evaluating performance. These measures were not disclosed in the MD&A, however we have included them in the preamble and noted here whether or not they are governed by NI 51-101 for the sake of completeness. Disclosures relating to “FD&A” costs are prescribed by paragraph 5.15 of the NI 51-10, however FD&A numbers were not disclosed in this Form 40-F filing. Disclosures of “recycle ratios” are not governed by NI 51-101, and no recycle ratios were disclosed in this Form 40-F filing. Disclosures relating to “total capitalization” are not governed by NI 51-101, and no total capitalization disclosures were made in this Form 40-F filing
Quarterly Information, page 25
| 4. | Please explain why you believe it is appropriate to disclose cash flow from operations per unit. Refer to CICA 1540.53 to 55. |
CICA 1540.53 precludes disclosure of cash flow per unit in financial statements. Baytex has not disclosed cash flow per unit in its financial statements; rather it is disclosed in the MD&A. There is no prohibition against such disclosures in the MD&A.
Cash flow from operations and cash flow per unit are disclosed for reasons noted above in our response to item 3. As noted above in our response to point 3, there is Canadian guidance on disclosing non-GAAP measures, which we believe we have complied with.
Evaluation of Disclosure Controls and Procedures, page 27
| 5. | Please indicate whether or not there was any change in your internal controls. Refer to General Instruction B(6)(e) of Form 40-F. |
We believe we have complied with the disclosure requirement in General Instruction B(6)(e) through our disclosure on page 3 of the Form 40-F. For clarity we repeat that disclosure, noting that there were no changes to Baytex's internal control over financial reporting during the year covered by the report that have materially affected, or are reasonably likely to materially affect Baytex's internal control over financial reporting.
Note 2 Significant Account Policies
| 6. | We note your disclosure on page 16 of your document indicates that you allocate and distribute all of your taxable income to your unit holders. Please expand your summary of significant accounting policies to address your cash distribution policy including any limitations which preclude you from distributing all of your taxable income in any given year, such as but without limitation to, debt covenants and capital expenditure requirements. |
We believe that our cash distribution policy is not an accounting policy, but is part of our overall corporate policies. Our distribution policy deals with our decisions on how we use cash flow rather than how we record or report those uses. As such, we feel it is appropriately disclosed in the AIF and not in our accounting policies.
We also note that we have included detailed information relating to limitations which preclude us from distributing our taxable income in a given year at pages 16 and 40 of our AIF. That narrative indicates the material limitations that may preclude distributions in any given year.
Consolidation
| 7. | Please expand your consolidation accounting policy to disclose the criteria you apply in determining whether a given entity should be consolidated, including those which are not wholly owned. |
We believe that the accounting policies as disclosed adequately describe our policy with respect to consolidations. We refer the Staff to both the accounting policy on consolidation and the policy on joint interests which addresses our policy with respect to proportionate consolidation of joint venture interests. As at December 31, 2005, Baytex had investments in several other entities. These Entities are either wholly owned subsidiaries or unincorporated oil and gas joint ventures. The accounts of the wholly-owned subsidiaries are included in the consolidated results of the Trust. Investments in unincorporated joint ventures are accounted for using the proportionate consolidation method, whereby the Trust’s proportionate share of revenue and expenses, assets and liabilities are included in the accounts, as required under CICA HB 3055 and EITF 00-1.
The Trust has reported an amount for non-controlling interest in the financial statements. This relates to exchangeable shares which do not meet the criteria to be classified as equity as discussed in Note 11 of the consolidated financial statements. In response to the Staff’s comments we propose that for the 2006 fiscal year and future years we will amend our disclosure of the consolidation policy to refer to the disclosure on joint ventures contained later in the policies note.
Note 4 Corporate Acquisition
| 8. | We note your disclosures on pages 6 and 7 of your document regarding your acquisitions of interests in the West Stoddart area in Northeast British Columbia on December 22, 2004 and producing properties in the Celtic area of Saskatchewan. Please tell us how you considered the disclosure provisions of CICA Handbook Section 1581 regarding these acquisitions. |
We provide the following information supplementally to aid in the Staff’s understanding of these acquisitions. The acquisition of the properties in the West Stoddart area and Celtic area are not considered to be business combinations under paragraph 8 of CICA Handbook Section 1581 (“Section 1581”) as these were acquisitions of a group of assets that do not constitute a business. As such the disclosure provisions of Section 1581 are not applicable. Emerging Issues Committee (“EIC”) 124 defines a business as a self-sustaining integrated set of business activities and assets conducted and managed for the purpose of providing a return to investors. A business consists of (a) inputs, (b) processes applied to those inputs, and (c) resulting outputs that are used to generate revenues. For a transferred set of activities and assets to be a business it must contain all of the inputs and processes necessary for it to continue to conduct normal operations after the transferred set is separated from the transferor, which includes the ability to sustain a revenue stream by providing its outputs to customers. All three of these elements did not exist for the acquisition of the West Stoddart and Celtic areas.
The acquisitions included the long lived assets and the intangible assets (reserves). In both cases, the acquisitions were property acquisitions rather than corporate acquisitions. The vendors in both cases were operating entities which held larger portfolios of assets and which operated the assets as a part of their consolidated business plans. Land holdings acquired as part of the purchase were further developed by additional wells drilled. Several processes and inputs / outputs which would have been required to consider these as self sustaining businesses were not included as a part of these transactions. For example, production from these areas would have been sold to the customers of predecessor owners under marketing arrangements which were not transferred with the assets, commodity price volatility would have been managed by the risk management contracts of the predecessor owners which were not transferred with the assets, tangible equipment and maintenance of the properties would have been managed using the supply chain management systems and suppliers of the predecessor owners which were not sold with the assets. Senior management and certain processes (strategic and operational processes, accounting processes) were also not included with the assets. The missing elements are significant and as such the properties acquired would not on a stand-alone basis, be able to continue normal operations and sustain their revenue streams and therefore are not businesses. Therefore the West Stoddart and Celtic acquisitions are not considered to be business combinations and as such the disclosures of Section 1581 are not applicable.
Under US GAAP similar conclusions were reached under the guidance provided in Statement of Financial Accounting Standard (“SFAS”) No.141 and EITF Issue No. 98-3.
Note 8 Convertible Unsecured Debentures
| 9. | Based on your disclosure and financial statement presentation it appears that you have accounted for the embedded conversion option associated with your convertible debt as a derivative. Please describe to us the model you applied in estimating the fair value of your derivative liability. |
Upon conversion of the option the holder would have a residual interest in the Trust’s net assets. Additionally, under U.S. GAAP, the conversion option is not considered an embedded derivative under SFAS 133 (11). Contracts are not considered to be derivative instruments under SFAS 133 (11) if they are issued by the reporting entity and are both indexed to their own stock and classified as shareholders’ equity as is the case for Baytex’s convertible unsecured debentures and therefore derivative accounting has not been applied.
Note 12 Trust Unit Rights Incentive Plan
| 10. | We note your disclosure that you have applied the Black-Scholes option pricing model in determining the estimated fair value of your trust units issued in connection with your incentive compensation plan. We are not able to agree that the Black-Scholes option pricing model is an appropriate model in view of the variable terms and nature of your compensatory trust units. Please submit your valuation and analysis of your trust units using a model which considers variability of terms of the trust units, or otherwise advise us how you determined the Black-Scholes option pricing model is appropriate based on the terms of your incentive unit rights. |
For the purposes of our Canadian GAAP financial statements, the Black-Scholes option pricing model has been applied to estimate the fair value of incentive unit rights as at the grant date for the December 31, 2005 financial statements. This was deemed appropriate at the time given the limited historical data (the Trust had only 2 years and 3 months of trading history as at December 31, 2005) available on which to base our assumptions. In addition, a comparison of results obtained using the Black-Scholes model and a binomial lattice model in order to estimate compensation expense, resulted in no material differences on the consolidated financial statements. Effective January 1, 2006, the Trust commenced using the binomial lattice model to calculate the estimated fair value of the unit rights issued. No retroactive adjustment was made for this change as the difference in the results between the use of the 2 models to estimate compensation expense was not material.
Prior to January 1, 2006, under US GAAP we continued to use the intrinsic value method to calculate compensation expense related to the unit rights as allowed under APB Opinion No. 25, Accounting for Stock Issued to Employees and Statement of Financial Accounting Standards 123. For the fiscal year ending December 31, 2006, the fair value method as defined by SFAS 123R
will be adopted for our disclosure of differences between Canadian and United States Generally Accepted Accounting Principles.
We have attached a summary of the results we obtained when we compared the compensation expense computed under the Black-Scholes model, and the results obtained using a bi-nomial lattice model (both of which considered the variable terms of the incentive unit rights plan). In computing the compensation expense under both models, similar assumptions were used.
Segment Disclosures
| 11. | We note your disclosures beginning on page 3 of your Managements’ Discussion and Analysis identifying two discrete districts, namely the Heavy Oil District and the Light Oil and Natural Gas District. Based on your disclosures, it appears you identify revenues, production, personnel, and property by these districts although you do not disclose these as segments in your financial statement notes. In this regard, please explain how you considered CICA Handbook Section 1701. |
In evaluating the need for segmented disclosure, we considered both the definition of an operating segment (CICA Handbook 1701.10) and the appropriateness of aggregating operating results (pursuant to CICA Handbook 1701.18).
An operating segment is a component of an enterprise (1) that engages in business activities from which it may earn revenues and incur expenses, (2) whose operating results are regularly reviewed by the chief operating decision makers to make decisions about resources to be allocated to the segment and assess performance, and (3) for which discrete financial information is available.
The operating results of the Trust in its entirety are regularly reviewed by the chief decision makers using reports which for the most part are consolidated information. Within such reports, revenues and related royalties are tracked by the above mentioned districts using actual sales and cash payments. Total operating expenses cannot be tracked specifically as each well may produce both oil and gas. For budgeting and estimation purposes, subjective allocations of operating costs have been applied to the districts with the understanding by the chief decision makers that such costs are extremely integrated, and the segregation are subjective allocations only. No other financial information are tracked or allocated by districts.
Pursuant to CICA Handbook section 1701.18, our various business components would meet the criteria for aggregation in reporting. Our business is to produce and sell hydrocarbons. Over the long term, the price for different hydrocarbon products exhibit fairly predictable relationships to each other (i.e. over the long term, natural gas has sold at approximately 1/6th of the price of equivalent heating content for oil; heavy oil has sold for approximately 71% of light oil etc.), although there is volatility to those relationships. The costs for service to extract our products are impacted by similar forces, such that the costs structure for production of the different products move in similar fashion. Over the longer term, all of our products do exhibit similar economic characteristics, which is a requirement for aggregation under 1701.18. Further, the production processes are very similar in that all of our production is conventional production, which does use vertical or horizontal wellbores, and the class of customers we sell our products to are very similar for products across the product classes. As noted above, it is very common that heavy oil wells also produce natural gas from the same wellbore. Product distribution methods are
identical, all products being transported through oil or gas pipelines networks or delivered by truck, and the production of all hydrocarbon products is governed by the same regulatory bodies in each province where we operate. As such, we believe that, even if we did have separate operating segments, we would be entitled to aggregate the results of those segments under the criteria noted in 1701.18. As a result of the operating similarities, the revenue similarities, the cost similarities and the marketing similarities between the districts, the chief decision makers of the company view the business as one operating segment, and we believe we have met the criteria set out in CICA Handbook section 1701.18 to aggregate the results of the Trust into one segment.
Note 19 Differences Between Canadian and United States Generally Accepted Accounting Principles
| 12. | Please expand your disclosures to provide a reconciliation of your statement of cash flows prepared on a Canadian GAAP basis to that on a US GAAP basis. Refer to Item C(2) of Form 40-F referencing Item 17 of Form 20-F. |
We have not provided a reconciliation of the Trust’s statement of cash flows prepared on a Canadian GAAP basis to that on a US GAAP basis because there are no material differences in cash flows from operating, investing and financing activities.
| 13. | Please expand your disclosure regarding your full cost ceiling test for US GAAP purposes to address how you consider the cost of properties not being amortized in your analysis. Refer to Rule 40-10.4 (C). |
Under U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized cost does not exceed the sum of the present value, discounted at 10%, of the estimated unescalated future net operating revenue from proved reserves plus unimpaired unproved property costs less future development costs, related production costs and applicable taxes.
The cost of undeveloped land has been excluded from the cost of properties being amortized as allowed under Regulation S-X 210.4-10(C). These costs are brought into the depletion base over 5 years on a straight-line basis unless impairment is assessed or proved reserves can be assigned to the properties. Inclusion of the cost of the properties in the depletion base over 5 years has been selected as the land leases expire at the end of the 5 years if drilling has not commenced. Undeveloped land is evaluated annually for impairment by comparing their fair value at December 31 to the book value. Fair value is determined by assessment of recent land sale prices paid at Provincial Crown land sales for properties in the vicinity of each existing Baytex lease. Any impairment is immediately included in the costs to be amortized. As noted in the accounting policy note (Note 2) the cost of acquiring and evaluating unproved properties are excluded from costs subject to depletion. We have applied this policy in our US GAAP disclosure. We do not propose to add any additional disclosure to our Form40-F filing. In response to the Staff’s comments we propose to expand our future disclosures related the treatment of costs of properties not being amortized.
| 14. | Please describe to us how you account for natural gas and oil imbalances. Additionally, please describe to us how you apply the revenue recognition principle criteria provided in SAB Topic 13.A for US GAAP to your various sale contracts and arrangements and compare and contrast those principles with those of under Canadian GAAP. |
We understand that you are using the term “imbalances” to refer to a situation where a field or a well is owned jointly with partners, and one of the partners “lifts” or sells more product than their partnership entitlement. In our case, we do not have such occurrences, as almost all of our product is delivered into interconnected pipeline systems and ownership of produced product is taken at the wellhead. In those rare cases where we do not deliver into a pipeline system, we are trucking oil to further delivery point. Currently we are 100% owners of the properties where we are trucking, and therefore no imbalances occur. We maintain the ownership of this oil until it has been trucked to this further delivery point at which time the risks and rewards of ownership are transferred to the buyer. We do have situations where we do not sell the entire volume of product which we produce within the production month. In those cases, we record inventory at the lower of cost and net realizable value. Natural gas and oil not sold within a given month will be sold the following month.
Under SAB Topic 13.A revenue is recognized if all of the following criteria are met:
| · | Persuasive evidence of an arrangement exists, |
| · | Delivery has occurred or services have been rendered, |
| · | The seller's price to the buyer is fixed or determinable, and |
| · | Collectibility is reasonably assured. |
Under Canadian GAAP revenue is recognized when performance is regarded as having been achieved (risks and rewards of ownership have transferred or service provided), reasonable assurance exists regarding the measurement of the consideration derived from the sale of goods or service and ultimate collection is reasonably assured. The Canadian Emerging Issues Committee EIC 141 applies the same criteria as SAB Topic 13.A for determining whether performance has been achieved (persuasive evidence, delivery and determinable price).
The Trust recognizes revenue associated with crude oil, natural gas and natural gas liquids when title passes to the purchaser. At this point in time, all of the revenue recognition criteria are met under both Canadian and United States GAAP.
| · | All sales transactions are subject to a written agreement with the purchaser as such there is persuasive evidence of an arrangement; |
| · | The price is determinable as it will be stipulated in the written contract; |
| · | The risks and rewards of ownership have transferred as title has passed to the purchaser; and |
| · | Collection is reasonably assured as even though the Trust is subject to normal credit risk from its customers, the Trust’s transacts only with reputable, established counterparties. |
Recent Developments in US Accounting
| 15. | Please expand your disclosure to explicitly state whether the adoption of SFAS 155 is expected to have a material impact on your financial statements or otherwise advise. Refer to SAB Topic 11.M. |
As at December 31, 2005 the Trust has no financial instruments that would meet the definition of a hybrid financial instrument containing an embedded derivative as defined under SFAS 155. The conversion option of the Trust’s Convertible Unsecured Debentures is excluded from derivative treatment under of SFAS 133 (11) as it is indexed to the Trust’s units and is classified
as equity on the balance sheet. SFAS 155 is therefore not applicable to the conversion option as it not considered a derivative instrument. It is not anticipated at this time that the Trust will hold any additional hybrid instruments in the near future.
As required under SAB Topic 11.M we have provided a brief description of SFAS 155. We failed to identify the effective date (fiscal years beginning after September 15, 2005), our plans for adoption or explicitly state the expected impact to the Trust. However given the adoption of SFAS 155 will not have a material impact on the consolidated financial statements we do not propose to amend our Form 40-F. We will ensure future disclosure complies with SAB Topic 11.M.
Engineering Comments
Disclosure of Reserve Data and other Oil and Gas Information
| 16. | We note that you have added together reserves volumes of different classifications. As the difference in the classifications has to do with the certainty of recovery, please advise us as to the appropriateness of such disclosure. |
The addition of total proved reserves and total probable reserves in our disclosure is the required reporting practice for companies that adhere to NI 51-101 guidelines. The addition of these two reserve categories results in the total proved plus probable reserve category which is the procedure recommended in the following companion reserves handbook to NI 51-101.
Excerpt from the Canadian Oil and Gas Evaluation Handbook, Volume 1
Reserves Definitions and Evaluation Practices and Procedures
6.4 Clarification of Proved + Probable Reserve Estimates
Despite the fact that some users of reserve data require only proved reserves estimates, the SPEE (Calgary Chapter) recommends that a primary emphasis be placed on proved + probable reserves estimates. This change of emphasis is recommended for the following reasons:
| · | Proved + Probable reserves estimates represent the “P50” or median reserves estimates |
| · | Levels of confidence are easier to define and understand for proved + probable reserves estimates than for proved estimates. The result will be smaller differences between evaluators for proved + probable reserves estimates than for proved reserves. |
| · | The procedures and methods more frequently used routinely to estimate reserves typically provide a value that is closer to a median estimate than to a high certainly estimate. |
| · | Aggregation effects (arithmetic or probabilistic summations) are minimal for proved + probable reserves estimates. |
11.2.1 Report Contents
| · | Reconciliations must be included, for the current and immediately preceding year, for the company’s gross interest in reserves using forecast prices and costs, in at least the following categories: |
Proved developed producing
Total proved
Total proved plus probable
Summary of Pricing and Inflation Rate Assumptions as of December 31, 2005: Forecast Prices and Costs and Marketing - Crude Oil
| 17. | We note that you have forecasted Edmonton 40 degree API oil prices to decline materially from $70 per barrel to $54.65 per barrel in just four years. You forecast similar declines for WTI oil and natural gas prices. Please provide the basis for these large estimated declines in future energy prices. |
Commodity prices are historically volatile, as evidenced by WTI benchmark oil prices varying from an average of $15.31US in 1986 to a year to date average of $68.24 for the first 9 months of 2006. The ascent in prices is a dramatic and recent phenomena, as WTI prices averaged $26.08 in 2002, $31.04 in 2003, $41.40 in 2004 and $56.56 in 2005. In recent weeks, WTI has been below $60US. Forecasting a decline from $70 to $54.65 over 4 years represented the best estimates of management and of our reserve auditors at the time, and the rate of change is not unusual in the context of these commodities. Factors indicating a price reduction included the potential of easing geopolitical tensions in the Middle East, and increased non-OPEC supply of crude oil. Longer term trends of increasing demand from the strongly developing economies in China and India support the sustained WTI prices which are high relative to recent pricing history. The forecast of a reducing oil price at December 31, 2006 was a conservative assumption made at a time when the futures markets were predicting near term higher pricing. We believe this conservatism in assumption practice is prudent when dealing with a commodity which has historically been volatile in its pricing. Further we note that any price forecasting is inherently subjective and we believe that our disclosure of the assumptions which were made aids readers in evaluating their own assessment of the reserve evaluations which are made using those assumptions. Finally we note to the Staff that the decline in price realized thus far in 2006 is directionally consistent with our forecast.
Similar statistics can be presented for both Edmonton par pricing, and for natural gas pricing if requested.
Other Oil and Gas Information
Marketing Arrangements - Oil and Liquids
| 18. | You state that your five-year heavy oil sales contract with Frontier Refining significantly reduces the volatility of your cash flow. As the terms of the contract include a set price differential of 29% to the WTI price, please explain to us how this reduces price volatility. |
The contract with Frontier removes an element of pricing volatility on our heavy oil sales, both on an annual basis and on a seasonal basis. Heavy oil is generally seen as a lower quality product, which requires more refining to produce quality end use products, such as gasoline, than lighter oil would need. The selling price for heavy oil varies from “benchmark” pricing (such as WTI
which is a lighter oil) over the longer term as a result of a number of influences including overall worldwide supply of heavy oil and the capacity of refiners to accept additional heavy oil. Historically, the price differential from WTI to Lloyd Blend (a heavy oil benchmark price) has been a discount of 29%. However, this discount has varied greatly on an annual basis from a low of a 21% average discount in 1987 to a high of 42% in 2001.
On a shorter term basis, seasonal demand (one significant use for heavy oil is the production of asphalt which has greater summer demand than winter demand) also has a great impact on pricing volatility. For example, the monthly differential between WTI and Lloyd Blend in February of 2006 was 53%, compared to 21% in May at the start of the asphalt season.
The underlying benchmark oil price is itself variable, however by entering into the Frontier contract, Baytex eliminated the further volatility in selling price which results from producing and selling a Heavy Oil Product.
Management’s Discussion and Analysis
Property Review
Heavy Oil District
| 19. | You state that the Celtic field contains a huge resource base of 445 million barrels of original oil in place. This appears to be confusing to an investor as it does not correlate in any way to your reported proved and probable reserve estimates. Please revise your document to provide further disclosure on the relevance of this volume to the investor, who will not benefit from the monetization of the majority of this volume. |
Discussion of original oil in place (“OOIP”) is made to give readers a perspective on the size of a resource in a particular area. As technological advances are made and recovery factors improve, more and more of the OOIP can be produced. We believe that readers are advised of the best estimates of recoverable reserves in the reserve tables. At year end 2005, we had booked remaining total proved plus probable reserves of 15.1 million barrels of heavy oil and 6.2 billion cubic feet of natural gas to this property. We expect the amount of booked reserves to increase over time as extensive development efforts continue on this property. The use of the OOIP number was to illustrate the large size of the resource at Celtic and clarify why the company’s capital and manpower was being allocated to capture and produce more of this resource.
In our description of the Celtic, Saskatchewan heavy oil producing property we accurately state that the property has an original resource base of 455 million barrels of OOIP with multiple prospective producing horizons.
In cold primary, heavy oil production operations such as our Celtic property it is common to obtain a range of 5 to 15% recovery of the OOIP. Improve access to OOIP are possible through enhanced recovery schemes such as water flooding and heating of the reservoir through the addition of steam. Some of these enhanced recovery processes are appropriate to economically evaluate for potential use in Celtic in the future. Currently no such processes are being used.
In response to the Staff’s comments, in the future, if we include a reference to the OOIP for a property, we will also include the current amount of booked reserves to that property and an estimate of the current oil recovered to date and the expected ultimate recovery of oil from the pool using known technology.
In connection with our comments, we acknowledge that:
| · | Baytex Energy Trust is responsible for the adequacy and accuracy of the disclosure in the Form 40-F filing; |
| · | Securities and Exchange Commission (“SEC”) Staff comments or changes to disclosure in response to SEC Staff comments do not foreclose the SEC from taking any action with respect to the filing; |
| · | Baytex Energy Trust may not assert SEC Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
Yours truly,
BAYTEX ENERGY TRUST
[Missing Graphic Reference]
W. Derek Aylesworth, C.A.
Chief Financial Officer
cc: Mr. Jonathan Duersch, Division of Corporation Finance
Attachment enclosed
