O’Connor T C.J.:
These appeals were heard on common evidence at Calgary, Alberta on April 21, 22 and 23, 1998.
Several witnesses were heard and copious exhibits were filed.
Issues
There are three issues, namely:
1. Whether an alleged management fee of $190,000 paid or accrued by Airtex Industries Ltd. (“Airtex”) to its wholly owned U.S. subsidiary, Airtex Inc. in the 1989 taxation year was deductible.
2. Whether in 1989 the partnership in which Airtex was a partner, in calculating its resource profits for purposes of determining a resource allowance, had to deduct the amount of capital cost allowance (“CCA”) which Airtex had taken on certain assets owned by Airtex but contributed to the partnership to enable the partnership to carry out its operations of producing petroleum and natural gas and related hydrocarbons.
3. Whether in the years 1987 through 1989 for Airtex and 1989 and 1990 for both Dex Resources Ltd. (“Dex”) and Resman Oil & Gas Ltd. (“Resman”) various expenses related to the drilling and completion of petroleum and gas wells in Canada and related works qualified for income tax treatment as Canadian exploration expenses (“CEE”) or Canadian development expenses (“CDE”). The years in question, the company concerned, the amount of the expenses still in dispute and the wells in issue are shown on Appendix 1 to these reasons.
On the first issue relative to claimed management fees, Airtex Inc. was incorporated on July 28, 1988 as a wholly owned U.S. subsidiary of Airtex. Its purpose was to introduce to the American market the heating, air conditioning and ventilating (“HVAC”) equipment manufactured in Canada by Airtex or by a partnership in which Airtex was involved. The HVAC equipment is sometimes referred to as “Engineered Air product line”.
An agreement, apparently executed on July 31, 1989 (July 31 is the year end for Airtex), provided as follows:
Airtex Industries Ltd.
Management Fee - Airtex, Inc.
July 31, 1989
Airtex, Inc. has charged Airtex Industries Ltd. a consulting fee in the amount of $160,000 U.S. which is designed to recognize the following functions conducted by Airtex, Inc. on behalf of Airtex Industries Ltd.:
° Introduction of Engineered Air product line to the U.S. market place.
° Exposure of the method of Engineered Air marketing techniques to the U.S. market.
¢ Exposure of the Engineered Air method of production ie packaged custom manufactured products.
• A U.S. presence has opened market areas not previously available.
• Accumulation of information on how the U.S. market place is conducted in order that market strategies may be developed to fit the needs.
• All other corporate maters not specifically outlined above.
Airtex Industries Ltd.
Airtex, Inc.
The basis for the calculation of the fee is explained as follows:
Airtex Industries I Airtex, Inc.
Management Fee
July 31, 1989
Based on the fact that, had Airtex, Inc. not been incorporated and yet a U.S. presence was required in order to expand our market place the following amounts would have been expensed by Airtex Industries Ltd. to accomplish the functions as previously outlined:
| $ |
| Sales - (Equivalent of one full time sales rep.) | 75,000 |
| Administration (75% of $110,000) | 85,000 |
| Overhead (20% of $75,000 - | 30,000 |
| $85,000) | |
| 190,000 |
| U.S. | 160,000 |
Bruce Burnyeat, the controller of Airtex testified as to this issue and expanded on the foregoing by referring to Tabs 7, 8 and 9 of Exhibit A-2.
The efforts of Airtex Inc. in penetrating the U.S. market were overwhelmingly successful and the increased U.S. sales were obviously to the benefit of Airtex, the sole shareholder. The question is, however, were these expenses truly management fees, deductible on a current basis or should they be non-deductible because Airtex Inc. was a separate legal entity and the amount was not really a management fee but more in the nature of a capital expenditure to secure an enduring benefit.
Counsel for the Appellants submits that the $190,000 management fee was deductible in computing Airtex’s profit from its business for purposes of subsection 9(1) of the Income Tax Act (“Act’’) and was not disallowed under the general limitation in paragraph 18(1 ){a) because it was incurred by Airtex for the purpose of gaining or producing income from its manufacturing business. In short, counsel states that the $190,000 management fee paid was reasonable compensation from Airtex to Airtex Inc. for the marketing services in the U.S. provided by Airtex Inc. Subsequent to the 1988 taxation year, Airtex Inc. substantially increased its sales to U.S. customers of products manufactured by Airtex in Canada. In other words, the marketing efforts undertaken by Airtex Inc. resulted in substantial increased sales and economic benefit to Airtex, which continue to this day.
Counsel for the Respondent submits that
• a)
the characterization of the amount paid as a management fee seems to have come as an afterthought - evidenced by the agreement only signed on July 31, 1989, the year end for Airtex;
• b)
the expenses were not incurred for the direct benefit of Airtex;
• C)
Airtex Inc. was a separate legal entity;
• d)
that really what Airtex was doing was essentially making a loan or an advance which was capital in nature and made to secure an enduring benefit.
Counsel for the Respondent referred to several cases supporting her position. I refer only to Minister of National Revenue v. Stewart & Morrison Ltd. (1972), 72 D.T.C. 6049 (S.C.C.) where the Supreme Court of Canada held as follows:
The appellant private company, located in Toronto, carried on business as industrial designers and had built up a good business throughout Canada and the United States. In 1963, to improve its U.S. business, the appellant incorporated a wholly-owned U.S. subsidiary company to operate an office in New York. The subsidiary solicited clients in its own name and billed them accordingly. It had accounts and bookkeeping separate from its parent and had employees of its own. However, the New York office was “master-minded” from Toronto, and the affairs of parent and subsidiary were closely related and managed. All of the money required for the operation of the New York office was provided by the appellant by making direct advances from time to time and by guaranteeing a bank loan. The advances were treated by both companies and by their auditors as loans form the appellant. The New York office did not prosper and eventually ceased operations in 1966. At that time, the subsidiary owed the appellant $72,000 made up of money spent for operating expenses and not for capital investment. In its 1966 return, the appellant deducted the $72,000 as “advances to New York office written off’. The Minister disallowed the deduction. The Appeal Board (69 DTC 95) allowed the appellant’s appeal, but the Exchequer Court (70 DTC 6295) reversed this decision. The appellant took its case to the Supreme Court of Canada where it argued that the U.S. subsidiary was incorporated to serve as a branch of the appellant, that the New York office was its branch office, and that the $72,000 represented expenses incurred for the purpose of earning income from its own business.
Held: The appeal was dismissed. The appellant company could not deduct the $72,000 as an expense. The Exchequer Court had correctly characterized the dealings between the appellant and its U.S. subsidiary. The appellant provided working capital to its subsidiary by way of loans. The money was lost, and the losses were capital losses to the appellant, the deduction of which was prohibited by section 12(1 )(b). It was immaterial what the result would have been if the appellant had chosen to open its own branch office in New York. For reasons of its own, it did not choose to operate in this way. It financed a subsidiary and lost its money.
Although the facts giving rise to the foregoing decision can be distinguished from those in the Airtex relationship, the comments of the Supreme Court in distinguishing a branch operation from the operations of a wholly owned subsidiary are relevant. Moreover in my opinion the above submissions of counsel for the Respondent are correct. Consequently the alleged management fee of $190,000 was not a deductible expense of Airtex.
With respect to the second issue, namely how resource profits should have been calculated for purposes of determining a resource allowance, the facts are not in dispute. To background the facts and analyze the applicable legal principles, I find it useful to quote from Appellants’ counsel’s written argument as follows:
The deduction for resource allowance was determined as 25% of resource profits calculated based on the definition of “resource profits” for earned depletion purposes found in [Income Tax] Regulation 1204 after incorporating the assumptions outlined in Regulation 1210.
Regulation 1204 requires that the taxpayer compute his incomes from the sources described in paragraphs (b) and (b.l) "'in accordance with the Act’.
Included in the other deductions applicable to the determination of resources profits were
... such other deductions for the year as may reasonably be regarded as applicable to the sources of income described in paragraph (b) [the production of petroleum, natural gas or related hydrocarbons].
At issue in this case is the calculation of resource profits of the RA 1986 Partnership. The issue is whether capital cost allowance deductions claimed by Airtex in respect of depreciable property which it owned and dedicated to the Partnership for use by the Partnership in its business operations must, as asserted by Revenue Canada, be deducted by the Partnership in computing its resource profits. Revenue Canada reassessed Airtex on that basis.
The fundamental conceptual points to bear in mind are as follows.
A partnership is not a person, nor is it deemed to be a person for purposes of the Act. However, the Act provides in subsection 96(1) that the income of a partner under the Act is computed as if the partnership were a separate person resident in Canada. So, for example, deductions such as capital cost allowance on assets owned by a partnership are taken at the partnership level.
The income of a partnership under Division B is not taxed at the partnership level but is allocated to the partners according to the terms of the partnership agreement. The partners then include their share of the partnership income in their income for the year. The income that flows through to each partner retains its original character or source.
Under the old resource allowance rules applicable here (i.e., those applicable before the recent amendments), in computing the income of the partnership under subsection 96(1) the partnership was entitled to claim a resource allowance deduction under paragraph 20(1)(v.1) in respect of any resource profits it had. In other words, the resource allowance calculation in respect of resource profits of a partnership was computed entirely at the partnership level. Any available resource allowance deduction would reduce the amount of net income ... of the partnership allocated to the partners.
In this case the resource profits of the RA Partnership were computed at the partnership level as provided under subsection 96(1). Specifically, because the Partnership did not own any of the depreciable property relating to the Canadian resource properties (1.e., its producing oil and gas properties) from which it earned its resource profits, the Partnership was not entitled to deduct CCA in respect of those depreciable properties. On the other hand, Airtex as owner of those depreciable properties deducted CCA in respect of those assets in computing its income for purposes of the Act.
In computing its resource allowance under paragraph 20(l)(v.l), the RA Partnership followed the rules in Regulation 1210(1):
• Under Regulation 1210(l)(a)(i) the Partnership computed its “resource profits for the year” in accordance with the rules in Regulation 1204(1),
• Under Regulation 1204(l)(b) it included the aggregate of its incomes for the year from the production of petroleum, natural gas or related hydrocarbons from natural accumulations of petroleum or natural gas in Canada or oil and gas wells in Canada operated by the taxpayer, computed in accordance with the Act on the assumption that the Partnership during the year had no incomes or losses except from those sources and was allowed no deductions in computing its income other than those specified in paragraph (f) of Regulation 1204( 1 ) - “such other deductions for the year as may reasonably be regarded as applicable to the sources of income described in paragraph (b) or (b.1), other than a deduction under section 1201 or subsection 1202(2) or (3), 1203(1), 1207 or 1212(1).”
The only deductions that the Partnership deducted under Regulation 1204(l)(a) to (f) in computing its resource profits were deductions that it claimed which were reasonably regarded as applicable to the oil and gas production sources of income described in paragraphs (b) or (b.l) of Regulation 1204(1).
The Partnership did not deduct CCA claimed by Airtex on the oil and gas production equipment that Airtex owned because the Partnership was not entitled to claim a deduction in computing its income for purposes of subsection 96(1) for such equipment - because it was owned by Airtex and not owned by the Partnership.
The key words are ‘‘computed in accordance with the Act’. The rules in subsection 96(1) do not allow a partnership to deduct in computing its income under subsection 96(1) CCA claimed by a partner. To compute the RA Partnership’s resource profits deducting CCA that Airtex claimed, as Revenue Canada has done under the reassessments in issue, is not computing the Partnership’s resource profits “in accordance with the Act”. Those words mean that only deductions that can be claimed by the Partnership in computing its Part I income for the year can be deducted in computing its resource profits, and then only those deductions which “may reasonably be regarded as applicable” to the oil and gas production sources of income.
Accordingly, Airtex requests that the Court direct Revenue Canada to reassess the 1987, 1988 and 1989 taxation years to reflect a reduced income allocation from the RA Partnership. This results from an increased resource allowance deduction at the partnership level by increasing resource profits; eliminate the adjustment made by Revenue Canada when it subtracted Airtex’s CCA claims in computing the Partnership resource profits.
Note that paragraph 96(1 )(d) was amended by the 1992 technical bill effective for fiscal periods that begin after December 20, 1991 to add a reference to paragraph 20(l)(v.l) - that is the Partnership now computes its income or loss without taking any deduction for resource allowance under paragraph 20(l)(v.l). This is because Regulation 1210(3) now allows a partner, in computing its “adjusted resource profits”, to pick up its share of the Partnership’s adjusted resource profits. In other words, the resource allowance now is computed solely at the partner level rather than the partnership level. This means that had these new rules applied back in the years in issue, the resource allowance would not have been computed at the RA Partnership level, but rather would have been computed solely at the Airtex level. In the case, Airtex would have picked up its share of the resource profits calculated for the Partnership and the CCA deducted by Airtex in the respect of the dedicated assets would have been a deduction which was “reasonably regarded as applicable” to Airtex’s oil and gas production sources of income.
Counsel for the Respondent disagrees with the foregoing and presented oral argument. Her main assertion is that the partnership was entitled to deduct CCA pursuant to Regulation 1204(l)(/) which refers to such other deductions as may reasonably be regarded as applicable to the partnership’s income. The dedicated assets were used by the partnership to earn income and therefore the partnership was entitled to deduct CCA and should have done so in calculating resource profits.
In my opinion, the submission of counsel for the Appellants is to be accepted. The Partnership did not own the depreciable property. It remained the property of Airtex although contributed to the Partnership. This contribution did not alter title. The Partnership could not take CCA and should not be compelled to take CCA in the calculation of resource profits. Therefore, the CCA deductions made by Airtex in the 1987, 1988 and 1989 years are not to be deducted in the calculation of the Partnership’s resource profits.
With respect to the third and principal issue (CEE vs. CDE), lengthy testimony was given by Melville E. Gray, the former president of Resman Oil and Gas Ltd., the operating company with respect to the oil and gas operations of the three Appellants. Mr. Gray was not presented as an expert witness, but his “background” filed as Exhibit A-3, partly reproduced below, indicates his extensive experience in the oil and gas industry.
Melville E. Gray B.Sc. PEng.
Background
First employed in oil industry - June 1, 1955, Imperial Oil Limited - Producing Dept.
Graduated in Engineering - University of Alberta, 1959 with distinction
Schlumberger - 1959 - 1982
• Field engineer - Western Canada, Rocky Mountain area of U.S. - evaluation services on drilling wells, completions.
• Engineer in charge - Drayton Valley, Alberta 1963
• District Manager - S.E. Saskatchewan 1963 - 1966
• Division Engineer - Northern (Canada) Division 1966-1968 technical management, customer support, recruiting and training of new engineers
• Operations Staff Engineer - Houston, Texas 1968 - 1969
• International Wireline Coordinator - New York, NY 1969
• Division Manager Australia Division (Australia, N.Z., New Guinea, Fiji, etc.) 1969 - 1971
• President Schlumberger Surenco (Mexico, South America) 1971 - 1974
° President Johnston Testers, Houston, Texas 1974 - 1980 drillstem testing, pressure measurement, production testing, drilling and completion services and tools
• President Schlumberger of Canada 1980 - 1982
Resman Oil and Gas Ltd. Calgary, Alberta
• President - oil and gas exploration and producing company, in top 20 most active (drilling and exploration) companies in Canada for several years.
• Exploration plays, drilling, evaluation, completion, production, etc....
Mr. Gray presented several charts, diagrams and data concerning various wells, including the wells in issue and gave his interpretation of the distinction between CEE and CDE. The gist of his position is best summed up in Exhibit A 5 which he authored. It states as follows:
Resman Oil and Gas Ltd.
Airtex Industries Ltd.
Dex Resources Ltd.
Resman Holdings Ltd.
Classification of wells CEE vs. CDE The above listed companies have
drilled and participated in several hundred wells in Canada over the past two decades. For the purposes of Canadian Income Tax these wells have been consistently classified as development (Canadian Development Expense “CDE”) or exploration (Canadian Exploration Expense “CEE”) based on the following:
• Section 66.1 (6)(a)(ii. 1 ) Canadian Income Tax Act: Canadian Exploration Expense (CEE) includes any expense incurred in the drilling or completing an oil or gas well if the well resulted in the discovery of a natural accumulation of petroleum or natural gas ... or
• The well discovered an accumulation of oil or natural gas, which was not previously known to exist prior to the drilling of the well. The well discovered an accumulation of oil or gas, which extends the adjacent pool; such extension was not known to exist prior to the drilling of the well.
• CEE test: was the petroleum or natural gas discovered by this well known to exist with a high degree of certainty before the well was drilled?
A well can be expected to encounter an accumulation of petroleum or natural gas with a high degree of certainty only if bounded by successful wells at all points of at least a minimal (triangular) polygon, with these wells no further removed from the well in question than one drilling spacing unit. A drilling spacing unit is a maximum of one section for natural gas and a maximum of one-quarter section (160 acres) for oil, with 40 acre, 20 acre and even 10 acre spacings not uncommon.
The following sketches illustrate the distinction between a development well (CDE) and an exploration well (CEE): [The sketches are a demonstration of the application of the foregoing paragraphs].
Mr. Gray essentially stated an “accumulation” was simply a volume of oil or gas trapped in a porous space in the host rock. It is to be distinguished from a “pool” or “reservoir” which latter terms are interchangeable. He does not agree that, in considering CEE and CDE for income tax purposes, the processes of the Alberta Energy & Utilities Board (“EUB”) and the Lahee classification system discussed below are material. In reviewing the charts for the wells in issue, Mr. Gray constantly pointed out many other nearby wells which turned out to be dry holes, i.e., unsuccessful, thus demonstrating the high degree of unpredictability when drilling for oil and gas.
Mr. Gray concluded that applying his criteria, the well costs in issue are to receive CEE treatment. Further, Mr. Gray added that with respect to two wells which may have been abandoned, the abandonment issue need not be addressed because these wells qualified initially for CEE treatment because in drilling them there was no high degree of certainty of encountering oil or gas. It should be noted that the group comprising the Appellants had CDE expenses. In other words, the Appellants over the years have conceded that several wells were not discovery (CEE) wells.
The Minister called Donald Brent Fairgrave, a geologist with the EUB. His testimony was not extensive. He presented Exhibit R-7, a coloured chart which exemplifies his concept of the distinction between CEE and CDE. That concept is that there is only one discovery well for each pool. Only that one is entitled to CEE treatment. All other wells drilled into that pool receive CDE treatment. Although this chart shows the pools in the shape of lakes or ponds, Mr. Fairgrave testified that the shape could just as easily be a meandering stream. That testimony is consistent with other testimony and the definitions discussed below.
He also testified as to the procedures and methods of EUB in its operations of regulating the oil and gas industry in Alberta including the preparation of maps showing pools and estimating reserves. The EUB relies on the Lahee classification system which relates, inter alia, to the statistical possibilities of finding oil and gas. He opined that Lahee was generally accepted. He also testified on well abandonment procedures. The Lahee classification system is described in an Informational Letter of EUB filed at Tab 5 of Exhibit A-2. The following extracts are of interest:
Informational Letter IL 86-04
18 April 1986
To: All Oil and Gas Operators
Classification of Wells Drilled for Oil and Gas in Alberta
1 Description of the Well Classification System The following is a description
of the Lahee well classification system. The system has been used by the Board for over 20 years to provide a standard basis for compiling drilling statistics.
1.1 Exploratory Category
The exploratory category consists of the following four classes of wells. A well licensed under this category contains exploratory metreage from ground level to total depth except in the case of a deeper pool test which is described under clause (c).
(a) A new-field wildcat well (NFW) is a well located at a considerable distance beyond the limits of known pools and drilled in a geological environment where oil or gas has not yet been discovered.
(b) A new-pool wildcat well (NPW) is a well located at a relatively considerable distance outside the limits of known pools, or drilled in a geological environment where other pools have been found but where, in the Board’s opinion, the complexities in the geological conditions are such that searching for a new pool is hazardous. The objective of a new- pool wildcat well is the discovery of a new pool in an area known to contain oil or gas.
(c) A deeper pool test well (DPT) is a well located within the established or expected limits of a pool or pools and drilled with the objec tive of searching for undiscovered oil or gas below the deepest such pool. Only the interval from the base of the deepest established pool to total depth constitutes exploratory metreage at a deeper pool test; the remainder of the drilled interval is regarded as development metreage.
(d) An outpost well (OUT) is a well drilled with the objective of extending, by a considerable distance, a pool already partly developed. Its original objective is the producing or producible pool, although it may be completed or abandoned at a higher or lower stratigraphic horizon. It is far enough from the expected limits of the pool to make its outcome uncertain but it is not far enough to be designated as a wildcat. If it is successful in its original objective, it will add materially to the productive area of the pool. It is not the Board’s normal practice to apply the Outpost classification to a well located less than two drilling spacing units from the nearest well in the pool. Such a well is usually classified as a development well.
1.2 Development Category
The class of well licensed under this category is defined below. Such wells contain development metreage only. However, an exception may exist where a development well is re-entered and deepened. The Board will, upon the request of the licensee, determine which part, if any, of the deepened interval constitutes exploratory metreage.
A development well (DEV) is a well drilled with the objective of further exploiting the productive zone of a pool. Such a well may be inside the pool as already outlined by wells, or it may be a relatively short distance outside these limits.
On the basis of this definition, the Board normally assigns the development classification to an “edge well” located a relatively close distance (e.g. one or two drilling spacing units, depending on geological factors) beyond the nearest well in the pool. Furthermore, the development classification may be employed by the Board where the well is to be drilled slightly deeper than the target pool, especially where the strata to be penetrated have little or no hydro- carbon-bearing potential below, and in the vicinity of, the pool.
A sixth class of well, known as a “shallower pool test”, is recognized as a part of the exploratory category under the Lahee well classification system. A shallower pool test is a well located within the known or expected limits of an established pool and drilled with the objective of exploiting a pool thought to exist above the established pool. Such a well, however, is normally classified by the Board as a development well because, before the well is spudded, the existence of the target pool has usually been suspected on the basis of data available from the up-hole portion of adjacent wells.
2. Implementation of the Well Classification System - Policies and Procedures
2.1 Technical Considerations (a) When classifying a well, the Board takes into
account such considerations as the geological objectives and projected total depth of the well, the geological conditions and known existence of hydrocarbons in the area in which the well is to be drilled, and, in its judgement, the general degree of the risk of failure involved. (b) The oil- and gas-bearing portions of a pool constitute a single accumulation pursuant to both industry tradition and section 1(1)(q) of the Oil and Gas Conservation Act. Therefore, step out wells drilled to encounter the oil leg of a known gas pool are usually classified as development wells. (c) Board- designated pool orders (G orders) have no bearing on the class of well, although they do affect the well's confidential status. Such orders are disregarded for well classification purposes because they may not have been issued for nearby pools, or because their boundaries have not been updated to reflect current knowledge regarding the areal extent and continuity of the pools, (d) The outcome of a well, whether successful or unsuccessful in encountering oil or gas, has no bearing on the classification initially assigned to the well.
2.2 Administrative Considerations
(a) For practical reasons, the Board classifies a well when it is licensed. It recognizes, however, that according to established Lahee concepts, the classification of a well is intended to take into account the conditions that are known when the well is spudded.
(b) In view of (a), above, the Board may re-classify a well from the exploratory to development category if additional knowledge affecting the well’s classification was gained before the well was spudded.
(c) The assigned well classification is recorded on both the issued well licence and the daily listing of well licences, and it is published and maintained on the records associated with the well.
(d) The Board, on its own initiative, may amend the classification of a well to accommodate an amendment to the well licence, to reflect failure to comply with the intentions recorded on the well licence application, or to provide for the correction of an obvious clerical error. For example, the classification may be amended if the well does not reach the projected total depth recorded on the well licence.
(e) The Board may classify the second and subsequent wells drilled after the discovery of new pool as development wells, if they meet the meaning of the definition.
(f) When it initially classifies a well, the Board does not take into account the impact of the classification on the Exploratory Drilling Assistance Program or any other regulatory consideration. Furthermore, to ensure consistency and impartiality, the Board does not, at this stage, entertain technical representations or opinions from the licensee concerning the classification of its well.
The Minister also called James Brian Wetterberg, Manager Oil & Gas Section, Revenue Canada. He testified that until a uniform computer program was put in place at Revenue Canada in 1988, it was very difficult to distinguish CEE from CDE. The said computer program was based mainly on data supplied by EUB with respect to Alberta and had the same result, namely there was only one discovery well for a pool. It got CEE treatment. All other wells in that pool got CDE treatment.
The position of Appellants’ counsel is summarized in the following extracts from his written overview. References to tab numbers are references to Appellants’ Book of Authorities:
I. Step-out Wells
A. CEE versus CDE
The Act provides statutory deductions for pre-production expenses incurred in exploring for and developing oil and gas reserves which otherwise generally would be on account of capital and not currently deductible.
Pre-production expenses are classified as either CEE as defined in paragraph 66.1(6)(a) which go into a CCEE pool and are 100% deductible in the year, or as CDE as defined in paragraph 66.2(5)(a), which are added to the CCDE pool and are deductible at 30% per year on a declining balance basis.
Expenses for drilling or completing an oil or gas well constitute CDE per clause 66.2(5)(a)(i)(B) unless they are CEE by meeting the requirements of subparagraph 66.1 (6)(a)(ii) (for expenses incurred before April 1987) or subparagraph
66. l(6)(a)(ii. 1 ) (for expenses incurred after March 1987).
B. Definition of Canadian Exploration Expense
1. Definition Applicable in the Taxation Years in Issue
The relevant portion of the definition of CEE for expenditures incurred in drilling successful step-out wells is subparagraphs 66.1 (6)(a)(ii) and (ii.l) which read as follows for the taxation years of the three appellants in issue:
“Canadian exploration expense” of a taxpayer means any expense incurred after May 6, 1974 that is
(ii) any expense incurred before April, 1987 in drilling or completing an oil or gas well in Canada or in building a temporary access road to, or preparing a site in respect of, any such well,
(A) incurred by him in the year, or
(B) incurred by him in any previous year and included by him in computing his Canadian development expenses for a previous taxation year,
if, Within six months after the end of the year, the drilling of the well is completed and
(C) it is determined that the well is the first well capable of production in commercial quantities from an accumulation of petroleum or natural gas (other than a mineral resource) not previously known to exist, or
(11.1) any expense incurred by him after March, 1987 and in a taxation year of the taxpayer in drilling or completing an oil or gas well in Canada or in building a temporary access road to, or preparing a site in respect of, any such well if
(A) the well resulted in the discovery of a natural accumulation of petroleum or natural gas and the discovery occurred at any time before six months after the end of the year,
(B) the well is abandoned in the year or within six months after the end of the year without ever having produced otherwise than for specified purposes.
Subparagraph (11.1) is relevant for all of the well expenses of Resman Oil & Gas and Dex in issue, and also the well expenses in issue for the 1988 and 1989 taxation years of Airtex.
For the 1987 taxation year of Airtex subparagraph (ii) is relevant because Airtex incurred expenses for the two step-out wells in issue before April 1987.
For those two wells the test in subparagraph (ii) applies - the drilling of the wells must have been completed within six months after the end of the year and “it is determined that the well is the first well capable of production in commercial quantities from an accumulation of petroleum or natural gas ... not previously known to exist”.
Thus, the provision principally in issue is subparagraph (11.1). In interpreting this provision we must consider the meaning of "discovery", "natural accumulation of petroleum or natural gas" and "abandoned \
These terms are not defined in the Act.
2. Relevant Rules of Statutory Interpretation
In the absence of statutory definitions the meaning of “discovery”, “accumulation” and abandoned should be determined taking into account all of the following:
• The ordinary dictionary meanings
¢ Use of this and other terminology in the oil and gas industry
• Reading these words in the context of the other words used in the CEE definition and the use of these terms elsewhere in the Act, and the use of other comparable terminology elsewhere in the Act (1.e., the words of the Act are to be read in their entire context)
The object of the Act and the intention of Parliament
Also relevant will be the principle of implied exclusion, reviewed later.
3. Meaning of “Accumulation”
An “accumulation of petroleum or natural gas” is not a defined or technical term, as such, in the oil and gas industry. This is apparent from Mr. Gray’s testimony, a review of oil and gas terminology sources and...
Dictionary definitions of “accumulation” provide little assistance in suggesting that the term has a technical meaning in an [oil and gas] context.
the Shorter Oxford English Dictionary (tab B3) reads:
accumulation:... an accumulated mass;...
A term more familiar to the oil and gas industry could easily have been used by Parliament in defining CEE. For example, in the Manual of Oil and Gas Terms by Williams and Meyers (8th ed.) at tab 814 deposit, formation, zone, reservoir and field are all defined terms. Any one of these terms, had they been what was intended, could have been inserted in subparagraph (ii.1). ...
The term "reservoir^ also is used in several other places in the Act and ... the Regulations.
“Reservoir” and “pool” are likely the most relevant technical terms that Parliament might have used as an alternative to the more general term “accumulation”. ... The term “pool” as a noun is defined in the Manual of Oil and Gas Terms at Tab 814 as:
An underground reservoir containing or appearing to contain a common accumulation of oil and natural gas. A zone of a structure which is completely separated from any other zone in the same structure is a pool.
An underground accumulation of petroleum in a single and separate natural reservoir characterized by a single pressure system so that production of petroleum from one part of the pool affects the reservoir pressure throughout its extent.
Although the term “accumulation” is used in these definitions, it is not used in isolation but is qualified by limiting language. Therefore, accumulation cannot be used interchangeably with ‘pool”.
The Department takes the view that an “accumulation” is the same as a ‘pool” in interpreting whether there has been a discovery of a natural accumulation of petroleum or natural gas. I submit these terms have different meanings as is illustrated by the usage of “accumulation” and ^reservoir** in the definition of CEE and in other provisions of the Act.
Considering this entire context of the Act in which these terms are used, a reservoir or pool must mean something other than an accumulation. There is nothing to suggest that the use of the word “accumulation” in the CEE definition means anything more or less than the accumulated mass of petroleum or natural gas found by a particular well bore. Supportive of this conclusion are the comments of Judge Lamarre in Wheeler et al v. The Queen, 97 DTC 1157 at page 1163 where she notes:
...the terms the legislator used in the Act are neither “established reserves” nor ‘oil pool” nor “reservoir” but rather “the discovery of a natural accumulation of petroleum or natural gas”.
She went on to reject the Department’s interpretation that this means “discovery well” in the industry sense of the first well to encounter gas or oil in a pool hitherto unknown and unproductive.
It is clear by making these comparisons that the intent of subparagraph (ii.l)(A) was to define a quantity of petroleum or natural gas which is different from any technical term commonly used in the petroleum industry. If this was not the intent, a more precise term, familiar to members of the industry, would have been used.
4. Meaning of Discovery
The next issue is whether “discovery” has a technical or general meaning. This was the same issue considered by the Court in the Wheeler case. The Appellants there argued that both “discovery” and “accumulation” should be given their plain and ordinary dictionary meanings such that, at most, clause (ii.l)(A) adds a requirement that the well have the ability to produce petroleum or natural gas (irrespective of from what pool such production is attained). The Appellants there argued that a discovery would be the finding of something that was not previously known to exist and, at most, the taxpayer simply has to prove that oil or gas could be extracted from the ground and that the well is capable of production even if the well turns out not to be economically viable.
Both the dictionary and industry meanings of “discovery” are very broad.
Consider the ordinary meaning given to the words “discovery” and “discover”:
in the Shorter Oxford English Dictionary (tab BB) are:
Discovery: the action of uncovering or fact of being uncovered; the action of disclosing or divulging; the finding out or bringing to light of that which was previously unknown; making known; that which is discovered, found out, revealed, or brought to light.
Discover: to disclose to knowledge; to make known. Merriam-Webster’s New Collegiate Dictionary (1993) (tab Bd):
Discovery: the act or process of discovering Discovery - to make known or visible; to obtain sight or knowledge of for the first time
The Manual of Oil and Gas Terms (tab 814) defines “discovery” to mean:
drilling of a well to a formation capable of production of oil and/or gas.
This definition would suggest that any successful well drilled within a formation is a “discovery”. This is contrasted with the definition of a “discovery well”, which is defined as:
An exploratory well that encounters a new and previously untapped mineral deposit. A discovery well may open up a new field or may locate a new and previously unknown producing horizon in an old field.
The use of the term “discovery” rather than “discovery well” suggests that the broader interpretation was intended by Parliament.
In the definition of CEE in subparagraph (a)(11.1) the “discovery” must be of “an accumulation of petroleum or natural gas”. Since an accumulation is something less than a “pool”, it is not necessary that the well discover a new pool, but rather it discover an accumulation of petroleum or natural gas which was not known to exist prior to drilling. This discovery can be an accumulation which extends an existing pool, since the existence of that extension was not known with any degree of certainty prior to drilling the well.
The Appellant submits that the proper test to apply in determining whether costs incurred in drilling a step-out well are CEE is the following: was the petroleum and natural discovered by the step out-well known to exist with a high degree of certainty before the drilling of the well was completed?
The History of the Definition of CEE
The history of subparagraph 66.1 (6)(a)(ii.2), together with the statutory interpretation principle of implied exclusion, supports the Appellant’s position that step- out well costs qualify as CEE.
The original version of paragraph 66.1 (6)(a)( 11.2) was first introduced in 1981 (see tab A2) as follows:
any expense incurred by him after 1981 in drilling or completing an oil or gas well in Canada or in building a temporary access road to, Or preparing a site in respect of, any such well...
(B) in any area other than a prescribed frontier exploration area, except where the well is drilled for the purpose of production from, or delineating or determining the extent or quality of, an accumulation of petroleum or natural gas capable of being produced in com- mercial quantities that was known to exist at the time the drilling of the well commenced.
This proposed wording was introduced in 1980.
The implementation of this provision was deferred several times over more than 6 years and ultimately repealed and replaced by the current definition (introduced in 1987) without ever having been in force.
This proposed definition would have made it clear that the cost of a successful, non-frontier delineation well would not be treated as CEE. The express reference to “delineating” is in sharp contrast to the revised definition which is the relevant provision in these circumstances. I submit this shows a change of intention by Parliament as to the classification of such wells. By dropping the express exclusion of delineation wells, it is apparent the intent was to include such wells in recognition of the risk and uncertainty associated with such wells.
Based on Parliament’s initial proposal to expressly exclude wells for “delineating or determining the extent or quality of’ an accumulation, there is here a strong expectation of express reference if such an exclusion had been intended. There is very strong reason for anticipating an express reference to a delineation well if Parliament had clearly intended to exclude such wells from the CEE definition. Indeed, in this case the silence of Parliament could not be more telling.
C. Support for Liberal Interpretation of Incentive Legislation
The Act provides special rules for the deductibility of exploration and development costs in the oil and gas industry which are designed to encourage investment in the industry. Incentive legislation in the form of tax deductions has frequently been used to promote investment where Parliament considers it advantageous to the Canadian economy.
Counsel referred to several authorities and concluded that such legislation should be interpreted liberally so as to give effect to the intention of Parliament.
The position of counsel for the Respondent is set forth in her written overview. After reviewing the applicable provisions of the Act she states:
5 It is submitted that the expenses of drilling and completing an oil or gas well qualify as CDE unless the taxpayer can establish either that the expenses relate to a well which meets one of the tests in s. 66.l(6)(a)(ii) or (11.1) or ...
B. Post March, 1987 Expenses
6 The expenses in issue pursuant to the provisions relevant to the post-March, 1987 period include all those expenses for Airtex Industries Ltd.’s 1988 and 1989 taxation years, as well as all Resman Oil and Gas Ltd. and Dex Resources Ltd. expenses in issue. The Appellant says that these expenses are CEE by virtue of only two of the criteria in s.66.1 (6)(a) of the Act.
(i) The well resulted in a discovery of a natural accumulation of petroleum or natural gas
7 The first criteria for the inclusion of drilling and completion expenses in CEE is that ‘the well resulted in the discovery of a natural accumulation of petroleum or natural gas” in the year or within 6 months after the end of the year.
s.66.1 (6)(a)(ii.l)(A)
What is a Natural Accumulation ?
8. “Accumulation” is not defined in the Act. However, it is defined in the Shorter Oxford English Dictionary to mean “an accumulated mass”.
9. “Accumulation” also has an oil and gas industry meaning. It is defined as “the concentration or gathering of oil or gas in some form of trap”.
Glossary of Geology and Related Sciences, Tab 11, Respondent’s Book of Authorities. A Dictionary of Mining, Mineral and Related Terms, Tab 13, Respondent’s Book of Authorities.
See also Tab 16, Respondent’s Book of Authorities, for a definition of “accumulation of oil and gas”.
10. Although there appears to be no Canadian legislation which defines an “accumulation”, there are a number of Acts relating to oil and gas which use the word in defining other terms. For example, Alberta defines a pool to mean “a natural underground reservoir containing or appearing to contain an accumulation of oil or gas or both separated or appearing to be separated from any other such accumulation”. The Government of Canada, Ontario, Saskatchewan and British Columbia have identical or nearly identical definitions of “pool” in their legislation.
11. In Manitoba, “pool” does not appear to be defined, but the word “accumulation” appears in the definition of “oil” as follows:
“oil” means crude oil and all other hydrocarbons regardless of gravity, that are or can be recovered in liquid form through a well by ordinary production methods from a natural underground reservoir, containing an accumulation of oil or oil and gas.
12. Similarly, industry dictionaries and manuals define a “pool” with reference to the word “accumulation”.
See Tabs 10, 11, 13, 14, & 15, Respondent’s Book of Authorities.
13. The word “accumulation” as it applies to oil and gas refers to all that mass of oil and/or gas contained in a natural underground reservoir. There can be only one such accumulation per reservoir or pool.
14. It is submitted that, for purposes of the interpretation of the definition of CEE in the Act, a “natural accumulation” is synonymous with “pool”. What is a Discovery? •
15. “Discovery” means the finding out or bringing to light that which was previously unknown”.
16. A discovery of a natural accumulation of petroleum or natural gas is made when the first well is drilled into the accumulation or pool. It matters not that the extent of the accumulation has not been determined. There can be only one discovery for each pool.
Johnson's Asbestos Corporation v. M.N.R., 65 DTC 5089 at 5094 (Exch. Ct.), Tab 1, Respondent’s Book of Authorities.
17. It is submitted that a step-out well drilled into an already known pool does not meet the test in s. 66.1 (6)(a)(ii. 1)(A) of the Act because the well cannot be said to have resulted in a discovery. Since there can be only one discovery for each pool, the well which brought to light the existence of the pool must be the well which resulted in the discovery of the accumulation.
(ii) The well is abandoned
18. The second criterion for the inclusion of drilling and completion expenses in CEE is that “the well is abandoned in the year or within six months after the end of the year” without having produced.
66 1 (6)(a)(ii. 1)(B)
19. The term “abandoned well” is understood in the industry to be a well that is no longer in use.
See definition in Manual of Oil and Gas Terms, Tab 15, Respondent’s Book of Authorities.
20. In order to abandon a well, there are a number of physical steps which must be taken. In addition, in Alberta it is necessary to obtain EUB approval for the abandonment of a well.
Evidence of Mr. Gray and Mr. Fairgrieve.
21. Abandonment of a zone in a well is not abandonment of the well.
22. Similarly, a well which has been converted from production to a service well, has not been abandoned.
23. It is submitted that none of the wells in issue was abandoned in the year or within six months after the end of the year pursuant to s. 66. l(6)(a)(ii. 1)(B).
C. Pre-April, 1987 Expenses
25. The expenses for which s. 66.1 (6)(a)(ii) is relevant are those drilling and completion expenses incurred by Airtex Industries Ltd. in its 1987 taxation year in respect of the two wells in the Halkirk field.
(i) The well is the first well capable of production in commercial quantities from an accumulation of petroleum or natural gas not previously known to exist
26. The same reasoning as set out above in paragraphs 8 to 13 above applies to the interpretation of this provision. An accumulation as it is used here is synonymous with a pool. It cannot be said that either of the wells in issue were the first wells capable of commercial production in their pools.
D. Reasons why the Appellant’s Position is Contrary to the Words of The Act, and to Industry Understanding and Practice
28. It is submitted that the Appellant’s position is untenable because it relies on interpretations of words in the Act which are contrary to industry understanding and practice and which result in untenable interpretations inconsistent with the scheme of the resource provisions in the Act.
29. The Appellant’s test is based on the degree of risk involved in drilling the well. This is a subjective test based upon information available prior to, or at the time of drilling. This approach is inconsistent with the approach adopted by Parliament in enacting s. 66.1 (6)(a)(ii. 1). The approach set out therein relies on objective, results-oriented tests: a) did the well result in a discovery of an accumulation? b) was the well abandoned?
30. Furthermore, the Appellant’s characterization of the degree of risk appears to be inconsistent with the industry accepted Lahee methodology for assessing risk, since more than half the wells in issue were classified as “Development” under the Lahee system. There is no evidence that the Appellant’s methodology is sound.
31. The Appellant’s interpretation of “accumulation” is contrary to industry understanding:
a) it is inconsistent with the definitions in technical publications;
b) it results in there being any number of accumulations in any given pool, an interpretation which is contrary to the definitions of “pool” in the technical literature and in oil and gas legislation across the country; and
c) it results in the word “natural” being surplussage, because it projects an artificial boundary below ground.
32. The Appellant’s interpretation emasculates the word “discovery”. In effect, whenever the Appellant “encounters” hydrocarbons, he has made a “discovery”. This is inconsistent with the generally understood meaning of the word and with the sense in which it is used by the EUB. Furthermore, there is no merit to a position which suggests that where there is less risk, encountering hydrocarbons is not a discovery, but where there is more risk, encountering hydrocarbons is a discovery, even though the pool was already known to exist.
33. If the word “discovery” can be so emasculated, all wells which find oil or gas result in a discovery of an accumulation, with the result that there would be nothing left for CDE, since non-producing and abandoned wells are eligible for CEE.
34. If the determination of whether drilling and completion expenses qualify as CEE is based on the degree of risk at the time of drilling, s. 66.1(9) which permits the reclassification of expenses from CDE to CEE upon further information coming to light at a later date would be redundant, since the only information relevant is that available at the time of drilling.
E. Conclusion
35. It is submitted that the Appellant’s position is untenable and that the appeals in respect of this issue should be dismissed.
Analysis and Decision
The gist of the Appellants’ position is that a discovery of an accumulation occurs when drilling operations are undertaken and there is not a high degree of certainty that oil and gas will be encountered.
On the other hand, the Respondent equates an accumulation with a pool and therefore only the first well finding that pool is the discovery well and the only one entitled to CEE. Other wells in the same pool, no matter how distant from the discovery well, receive CDE treatment.
Mr. Gray’s credentials speak volumes about his knowledge of and experience in the oil and gas industry. His testimony was thorough in the extreme, both in examination in chief and cross-examination. The Respondent’s witnesses had certain credentials but no actual drilling/exploration experience. No expert witness was called to refute the methodology employed by Mr. Gray. In my opinion that methodology should govern and all of the costs in issue should receive CEE treatment. The following are my principal reasons:
1. Mr. Gray’s experience and testimony as mentioned above.
2. There is nothing in the wording of the relevant sections of the Act that supports the Respondent’s position that only one well qualifies. That position is based principally on the well classification procedures of the EUB. However, these procedures were not adopted in an income tax context but rather in a regulatory context related to the EUB carrying out its mandate, i.e., establishing pools, estimating reserves, issuing well licenses, and regulating the industry generally. The wording of the Act for pre-April 1987 wells mentions “the first well”, but these words are followed by “capable of production ... from an accumulation”. Thus, there was some concept of first well in that definition but that in itself does not lead to the conclusion sought by the Respondent. For post-March 1987 wells the concept of “first well” was removed entirely. Moreover, it is clear from the testimony and the definitions referred to above that oil and gas do not accumulate in the form of a lake. Rather the accumulations form in various porous crevices in the host rock. Thus, many wells can make new discoveries of different accumulations.
3. The analysis of Appellants’ counsel that parliament could have chosen more precise terms such as “pool” or “reservoir” is sound. 4. Further, his analysis of the history of CEE demonstrating that parliament enacted legislation to exclude delineation wells from CEE but never made that legislation applicable and then dropped it entirely, is a very convincing argument that delineation wells can qualify for CEE.
5. Counsel for Respondent stated one must be governed by objective considerations rather than subjective estimates of risk. However the very words of the Act refer to “and it is determined”. Someone must make the determination based mainly on objective criteria such as the proximity and location of known productive wells in relation to the well in question. Even the EUB letter cited above refers to subjective determinations based on objective criteria.
6. Where two or more interpretations are possible as to the meaning of incentive legislation a liberal approach should be followed to best ensure the intention of parliament.
7. Having arrived at the foregoing conclusion I find it unnecessary to discuss the issue of the abandonment of two of the wells in issue. They qualified for CEE treatment when drilled.
In conclusion, the appeals are allowed and the matter is referred back to the Minister of National Revenue. on the basis that
(a) The management fee of $190,000 is not an allowable expense of Airtex in the 1989 year;
(b) The CCA deductions made by Airtex in the 1987, 1988 and 1989 years are not to be deducted in the calculation of the RA 96 Partnership’s resource profits.
(c) All of the well costs still in issue as shown on Appendix 1 hereto are to be treated as CEE expenses.
As requested by counsel, the Registry of the Court will, as soon as possible and not later than July 31, 1998, contact counsel for the parties to fix a date for a conference call to hear representations as to costs.
Appeal allowed in part.
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