Bp Canada Energy Resources Company v. The Queen, docket 2000-5160-IT-G

2000-5160(IT)G

BETWEEN:

BP CANADA ENERGY RESOURCES COMPANY

AS SUCCESSOR TO AMOCO CANADA RESOURCES LTD.,

Appellant,

and

HER MAJESTY THE QUEEN,

Respondent.

Appeal heard on June 17, 18, 19 and 20, 2002 at Calgary, Alberta, by

The Honourable D.G.H. Bowman, Associate Chief Judge

Appearances

Counsel for the Appellant:          Al Meghji, Esq.

                                                Gerald A. Grenon, Esq.

                                                Catherine E. Bradley

Counsel for the Respondent:      William L. Softley, Esq.

R. Scott McDougall, Esq.

JUDGMENT

          It is ordered that the appeal from the assessment made under the Income Tax Act for the 1993 taxation year be allowed with costs and the assessment be referred back to the Minister of National Revenue for reconsideration and reassessment on the basis that the amounts received from A & S and PGT represent proceeds of disposition of capital assets and are therefore receipts on capital account.

Signed at Toronto, Canada, this 16th day of October 2002.

"D.G.H. Bowman"

A.C.J.

Date: 20021016

Docket: 2000-5160(IT)G

BETWEEN:

BP CANADA ENERGY RESOURCES COMPANY

AS SUCCESSOR TO AMOCO CANADA RESOURCES LTD.,

Appellant,

and

HER MAJESTY THE QUEEN,

Respondent.

REASONS FOR JUDGMENT

Bowman, A.C.J.

[1]      In 1993 the appellant, which was then known as Amoco Canada Resources Ltd., received $9,598,478 and $1,066,498 from the Alberta and Southern Gas Co. Ltd. ("A & S") and the Pacific Gas Transmission Company ("PGT") respectively. The Minister of National Revenue treated these amounts as income. The appellant says they are capital. The question is slightly more complex than it was in the multitude of classic capital versus income cases that have occupied courts in Canada and the United Kingdom over the past century. Originally the appellant's primary position was that the amount received was a tax-free capital receipt - in effect a windfall. Its alternative position was that the receipt was proceeds of disposition of a capital asset giving rise to a capital gain. At trial counsel for the appellant reversed these two positions and advanced as his primary argument that the amount was the proceeds of the disposition of a capital asset and argued in the alternative that if the Crown succeeded in contending that there was no disposition I should deal with the question whether the amount was a tax-free capital receipt. The Crown's position throughout is that the amounts received were on income account but that they were not resource income because they did not result from production but from refraining to produce. The appellant says that if the receipt is income it represents resource income and qualifies for the resource allowance.

[2]      The amounts were received as part of a "decontracting" arrangement between the appellant and A & S and PGT. The term "decontract" is not found in most dictionaries and certainly not in the sense in which it is used in this case. The only dictionary that I have found that recognizes the word is The Oxford English Dictionary (unabridged) which treats it as "obsolete and rare", and defines it as "to contract further" in the sense of abridge, shrink or reduce. I mention this at the outset because the word permeates the negotiations that led up to the payments. It seems to have been made up for the purposes of the transactions in question as a replacement for an earlier "restructuring plan" which was not accepted. Decontracting as used in this case carries with it both the implication of restructuring in the earlier plan as well as the sense of extricating the parties from their contractual arrangements.

[3]      The appellant prior to and during the year in question carried on the business of exploring for and producing oil and gas. The way in which the appellant and other Canadian producers had access to customers in California was by selling to A & S, a Canadian subsidiary of Pacific Gas and Electric Company ("PG & E"), a United States public utility that provided natural gas to consumers in California. A & S sold the natural gas to PGT, a United States subsidiary of PG & E, and PGT resold the gas to PG & E.

[4]      In the 1950s PG & E wanted to have a pipeline built that would carry gas from Alberta to California. Prior to the completion of the pipeline A & S had entered into long term natural gas supply contracts with Canadian producers. One such producer was Hudson's Bay Oil and Gas Company Limited, a predecessor of the appellant. After the pipeline was completed A & S continued to enter into long term contracts with Canadian producers to obtain natural gas for the California market. As of September 22, 1993 approximately 190 producers had long term natural gas supply contracts with A & S. The appellant was one of the larger suppliers.

[5]      On September 22, 1993 the appellant had 31 natural gas contracts with A & S. Of these seven were due to expire on specific dates in the future ranging from October 31, 1993 to June 30, 2010. The remaining 24 had no expiry date. They extended over the entire life of the field to which they related.

[6]      The parties have agreed that three supply contracts are representative of the appellant's 31 natural gas supply contracts with A & S. The Whitecourt Area contract ran from November 28, 1958 and expired, after one extension, on October 31, 1993. Under it the appellant dedicated 417 billion cubic feet of reserves under the appellant's lands in the Whitecourt Area.

[7]      The Fir Field contract ran from July 31, 1974 for the life of the field. Under it, the appellant dedicated exclusively to the performance of the contract all of its reserves as determined from time to time in the lands covered by the contract. The daily contract quantity was determined by dividing the reserves as determined from time to time by 7,300 (the number of days in 20 years). This contract was initially set at 25 years and the term was adjusted to permit the delivery of all the reserves on the land.

[8]      The Garrington Field supply contract was entered into on September 25, 1974 for 25 years or such longer period as was necessary to exhaust the field.

[9]      The reserves from a particular field were dedicated by the appellant to the performance of its obligations under the contract relating to that field. Under the contract the appellant had to sell all its gas from a particular field to A & S and A & S had to buy it. Title passed at the appellant's facilities.

[10]     The price paid by A & S to the appellant under the contracts, called a "netback price", was based on what A & S received from PGT which in turn was dependent on the price received by PG & E in California.

[11]     The appellant (then known as Amoco Canada Resources Ltd.) and a related company (Amoco Canada Petroleum Company Ltd.) in 1993 prior to November 1, 1993 sold about 130 million cubic feet of natural gas per day or approximately 13% of their daily sales.

[12]     I come now to the events leading up to the so-called decontracting arrangement. For the purposes of this case the recital of the somewhat complex facts can be abridged simply because the administrative or political reasons that caused the United States regulatory authorities to compel or, at all events, to lean on, PG & E and indirectly A & S to terminate the contractual arrangements with the Alberta suppliers are less important than the fact of the termination and the nature of the payment received.

[13]     Briefly, in or about 1990 the California Public Utilities Commission ("CPUC") believed that Alberta spot prices for natural gas were lower than under the long term supply contracts. It put pressure on PG & E to do something about the situation. Also, the United States Federal Energy Regulatory Commission ("FERC") took steps to end what it apparently perceived as monopolistic practices in the resale of natural gas.

[14]     These regulatory changes ultimately caused A & S, PGT and PG & E to terminate the arrangements relating to the purchase, sale and transportation of Alberta natural gas for the California market. The Canadian and Alberta governments including the National Energy Board ("NEB") saw the actions of the CPUC and FERC as inimical to the interests of the suppliers and took steps to counteract them. The net effect, in brief, of the steps taken by the Canadian and Alberta governments and the NEB was to make it impossible for A & S to substitute short term natural gas contracts with Canadian producers for the existing long term contracts.

[15]     The regulatory changes in the United States if implemented would have caused a major disruption in the business of the Alberta producers. I have summarized above the Canadian reaction to the actions of FERC and CPUC. It is obvious that the problem was a serious one both for the Canadian producers and A & S, PGT and PG & E. The actions of the authorities on both sides of the border resulted in an impasse. The province of Alberta appointed a "Facilitator" to represent the producers in the negotiations with A & S, PGT and PG & E. This position was established by the Alberta Petroleum and Marketing Commission ("APMC"). The position was filled by Mr. Dale Lucas, who had been chairman of the APMC from 1984 to 1991. Mr. Lucas described the atmosphere when he became facilitator as "poisonous ... just awful".

[16]     This is hardly surprising. South of the border the United States regulators were telling the purchasers and transporters of Alberta natural gas to stop buying under the long term contracts, and north of the border the Canadian authorities were saying that no sales to A & S could be made other then pursuant to the long term contracts.

[17]     On February 10, 1993 A & S, PGT and PG & E circulated a restructuring plan to the producers. It was not accepted by the producers. Since the subsequent decontracting plan (which was ultimately accepted by the producers) contains many elements similar to the restructuring plan, I shall set out an outline of the former, which was contained in the document circulated to the producers by A & S, PGT and PG & E:

1.1        Outline of the Restructuring Plan

The Restructing Plan provides for:

•            a transition period during which existing gas supply arrangements will generally continue until August 1, 1994;

•            termination of existing gas purchase and sale contracts effective August 1, 1994;

•            new long term gas marketing arrangements effective August 1, 1994;

•            proportionate allocation of the new long term gas marketing arrangements and A & S's Canadian and non California sales markets among Producers;

•            options for Producers to elect to sell their gas directly to PG & E and/or to obtain transportation capacity directly or to participate in the A & S supply pool for those purposes;

•            assignments of Canadian pipeline transportation capacity;

•            new A & S gas purchase contracts between A & S and all Producers that choose to have any portion of their gas sold through the A & S supply pool; and

•            the resolution settlement of claims against A & S, PGT and PG & E that may arise out of existing gas supply arrangements or the Restructuring of those arrangements.

I have left in the deletions and highlighted portions as they appeared on page 4 of Tab 21 of Exhibit A-1.

[18]     The Decontracting Plan dated July 29, 1993 (Exhibit A-1, Tab 22) differed in some respects from the Restructuring Plan. As part of the Plan circulated to the producers there was an Executive Summary of the Decontracting Plan, which contained the following statement:

The Decontracting Plan replaces the Restructuring Plan provided to Producers in February, 1993 and has been developed in response to Producer interest. It implements the changes required by recent regulatory developments affecting the sale and delivery of Canadian gas supplies to the northern and central California market. The Decontracting Plan provides Producers:

◆          Opportunities -- Producers will regain control of their reserves currently dedicated to A & S and be generally free to make new marketing arrangements after November 1, 1993; and

◆          Choices -- Producers are provided with choices regarding new and modified existing sales arrangements beginning November 1, 1993, as well as transportation capacity.

The following summarizes the Decontracting Plan. Capitalized terms in this Executive Summary have the meanings given them in the Decontracting Plan.

[19]     The Decontracting Plan consisted of a number of articles and schedules. It begins with an introduction as follows:

This Decontracting Plan replaces the Restructuring Plan previously provided to Producers.

Changes in the regulatory environment require that Alberta and Southern Gas Co. Ltd. ("A & S"), Pacific Gas Transmission Company ("PGT") and Pacific Gas and Electric Company ("PG & E") restructure their respective arrangements regarding the purchase, sale and transportation of Canadian gas supplies to the northern California market.

This document provides a description of the plan (the "Decontracting Plan") to restructure those arrangements, including the new agreements and arrangements required to respond to and comply with those regulatory changes.

The Decontracting Plan has been designed to provide flexible arrangements to all Producers that elect to participate in the Decontracting. The benefit of those arrangements may not be available to Producers that do not participate.

Under the Decontracting Plan, Producers' gas purchase contracts with A & E (the "Contracts") will be terminated on November 1, 1993. After November 1, 1993, Producers will be free to make new marketing arrangements for their gas.

In addition to the termination of Producers' Contracts, the Decontracting Plan provides for a combination of new short term gas supply contracts and the continuation of certain existing sales arrangements on a modified basis after November 1, 1993. Pipeline transportation rights to Kingsgate, British Columbia will also be offered to Producers.

This Decontracting Plan must be implemented together with the restructuring of the existing sales and transportation arrangements on the PGT pipeline system. Restructuring of service on the PGT pipeline system is well underway in PGT's FERC Order No. 636 proceedings. Accordingly it is important that the transactions provided for in this Decontracting Plan are completed by November 1, 1993 when the tariff approved under those proceedings for the PGT pipeline system is expected to be implemented.

Details regarding each part of the Decontracting Plan and related considerations are set out below.

A summary of defined terms used in this Decontracting Plan is provided in Schedule A.

[20]     Before the detailed provision contained in the articles, there is a 4½ page summary of the Decontracting Plan which it is unfortunately necessary to reproduce to demonstrate the nature and extent of the total revision in the arrangements. It is as follows:

______________________________________________________

ARTICLE 1.0

SUMMARY OF THE DECONTRACTING PLAN

______________________________________________________

1.1        Summary of the Decontracting Plan

            The following is a summary of the Decontracting Plan:

            (a)         Arrangements until November 1, 1993

Existing arrangements between A & S and the Producers and between A & S and PGT will continue during the period from the date of this Decontracting Plan until November 1, 1993 (the "Decontracting Date").

A & S's operations during this period will be consistent with current operations.

            (b)         Termination of Existing Agreements

                        On the Decontracting Date:

•            the existing Contracts between A & S and the Producers that participate in the Decontracting (the "Participating Producers");

•            the International Gas Sales Contract (the "International Contract") between A & S and PGT; and

•            the Service Agreement (the "Service Agreement") between PGT and PG & E;

            will be terminated.

(c)         New Marketing Arrangements

            Participating Producers may enter into new sales arrangements with other purchasers, aggregators or marketing representatives after the Decontracting Date and decontract lands currently dedicated to A & S in order to serve those sales arrangements.

Those new sales arrangements may include the new markets offered by PG & E under this Decontracting Plan.

(d)         New and Existing Gas Sales and Transportation Arrangements

•            PG & E Markets

            PG & E is proposing to enter into new gas sales contracts (the "PG & E Transition Gas Purchase and Sales Contracts") for part of PG & E's core and core subscription requirements during the period between November 1, 1993 and July 31, 1994. Under those contracts PG & E will purchase from A & S and those Producers that choose to contract directly with PG & E their shares of the modified sales levels resulting from the 1993/94 annual price redetermination under the International Contract.

            The PG & E Transition Gas Purchase and Sales Contracts will be standardized contracts.

            PG & E is also proposing to enter into a new gas purchase contract (the "PG & E Gas Purchase and Sales Contract") with A & S or A & S's successor. This market will only be available to certain qualifying Producers (the "Qualifying Producers") described below for part of PG & E's core and core subscription requirements during the period from August 1, 1994 to July 31, 1997. Through that PG & E Gas Purchase and Sales Contract, PG & E will purchase 75 mmcf/d from those Qualifying Producers that choose to participate in supplying gas for the contract.

•            A & S's Canadian Markets

            A & S will continue to make sales to various Canadian markets ("A & S's Canadian Markets") under existing long term sales contracts. Those sales contracts have requirements up to 184 mmcf/d including the Cochrane shrinkage make-up arrangements. Those requirements may be modified depending on the outcome of negotiations regarding existing Cochrane extraction and shrinkage make-up arrangements.

•            A & S's Transportation Capacity

            A & S's transportation capacity on Canadian pipelines will be offered to the Producers to enable Producers to serve new downstream markets.

(e)         Producers' Shares of New and Existing Sales and Transportation Arrangements

            Each Producer will have the opportunity, but not the obligation, to:

•            supply a share (the "Proportionate Share") of the quantities of gas to be purchased under the PG & E Transition Gas Purchase and Sales Contracts; and

•            acquire part of A & S's transportation capacity.

Qualifying Producers will also have the opportunity, but not the obligation, to participate proportionately in the PG & E Gas Purchase and Sales Contract.

A Producer's Proportionate Share will be based on the attributable contract quantities ("ACQs") under that Producer's gas purchase Contract(s) with A & S as at July 1, 1993.

(f)         Producers' Choices

Each Producer will be entitled to choose on or before August 23, 1993 whether and the extent to which that Producer will:

•            contract directly with PG & E for its Proportionate Share of the PG & E Transition Gas Purchase and Sales Contracts;

•            sell its Proportionate Share of the PG & E Transition Gas Purchase and Sales Contracts through the A & S supply pool;

•            acquire part of A & S's transportation capacity; and

•            if applicable, participate in the PG & E Gas Purchase and Sales Contract.

(g)         Producers' Obligations

            After the Decontracting Date Producers will:

•            be obligated to continue to:

•            make the sales they have agreed to make under the Customer Identified Gas Program; and

•            supply their Proportionate Share of A & S's Canadian Markets; and

•            be responsible for the NOVA receipt point and NUL capacity allocated to them.

(h)         Decontracting Dedicated Lands

              The lands dedicated to A & S under a Producer's Contract(s) will be released on the Decontracting Date. Producers will be required to rededicate part of their lands to A & S to support their continued sales through A & S.

(i)          New A & S Gas Purchase Contracts

            Producers will be required to enter into new standardized gas purchase contracts with A & S that will be effective from and after the Decontracting Date.

(j)          Commercial Closing

            The closing of the commercial transactions required to implement the Decontracting (the "Commercial Closing") will occur on September 15, 1993 (the "Commercial Closing Date").

(k)        Commercial Closing Confirmations

            Confirmations that the Commercial Closing has occurred (the "Commercial Closing Confirmations") will include confirmations that a satisfactory number of Producers have participated in the Commercial Closing and that Participating Producers with similar rights have been treated in a uniform manner regarding the settlement of their claims.

(l)          Conditions of Effectiveness

            Implementation of the Decontracting Plan will be subject to various conditions including obtaining certain required regulatory and governmental approvals.

            In order for Decontracting to occur on the Decontracting Date the Conditions of Effectiveness described in Section 6.1 must be satisfied or waived on or before that time.

(m)        Implementation of the Decontracting Plan

            If all applicable conditions regarding the Decontracting are satisfied, the date for full implementation of the Decontracting, including the commencement of deliveries under the new PG & E Transition Gas Purchase and Sales Contracts, will be November 1, 1993.

(n)         The Settlement of Claims

            Claims against A & S, PGT and PG & E, including any claims against PGT resulting from termination of the International Contract, must be settled as part of the Decontracting.

(o)         Settlement Payments

            A settlement payment (the"Settlement Payment") will be paid to each Participating Producer after the Conditions of Effectiveness have been satisfied or waived and the recovery of that Producer's Settlement Payment has been approved by the Federal Energy Regulatory Commission (the "FERC") through the transition cost recovery mechanism proposed by PGT in its Order No. 636 proceedings.

[21]     I have set out the detailed summary because it demonstrates that the decontracting affected in a substantial way a large part of the business structures of the producers. The settlement payments, which I shall discuss in greater detail below, were part of the overall arrangement.

[22]     Article 3.0 of the Plan deals with the Settlement and Claims which states in paragraph 3.2 that "common principles and assumptions have been applied to determine the Producers' respective Settlement Payments". These principles and assumptions are provided in Schedule F. Since the principles set out in Schedule F were ostensibly those used in arriving at the payments in issue here, I set out Schedule F in its entirety:

SCHEDULE F

______________________________________________

PRINCIPLES APPLICABLE TO DETERMINATION OF SETTLEMENT PAYMENTS

_____________________________________________________

            The common principles and assumptions applicable to determination of the Producers' respective Settlement Payments include the following:

(a)         Historic Value Loss

            Certain Producers claim to have incurred a loss of value (the "Historic Value Loss") by reason of alleged failures on A & S's part to satisfy minimum purchase requirements contained in those Producers' Contracts with A & S in respect of either or both of the 1990/91 and 1991/92 Contract Years.

            The Settlement Payments for those Producers claiming to have incurred a Historic Value Loss will accordingly include an amount that reflects the value of that loss. The value of the Historic Value Loss for each such Producer has been estimated in accordance with the following principles:

    •        the shortfall quantities valued were the difference between A & S's minimum purchase obligations under Specified Load Factor Contracts based on applicable Contract provisions and the actual quantities requested or taken by A & S during each of the 1990/91 and 1991/92 Contract Years;

    •        Producers were assumed to have been unable to mitigate any shortfall quantities incurred in respect of the 1990/91 Contract Year;

    •        Producers whose Contracts provide those Producers the right ("Excess Sales Rights") to sell gas from dedicated reserves to purchasers other than A & S when A & S is not purchasing the entire contracted quantities are assumed to have mitigated 50% of the shortfall quantities in respect of the 1991/92 Contract Year ("Mitigated Quantities") by selling those Mitigated Quantities into the intra-Alberta spot market. The only loss of value incurred by Producers with respect to those Mitigated Quantities is the difference between the A & S average allocable price for the 1991/92 Contract Year and a published average intra-Alberta spot price for that Contract Year that is assumed to have been received in respect of those quantities;

    •        shortfall quantities incurred in respect of the 1990/91 Contract Year and that portion of shortfall quantities incurred in respect of the 1991/92 Contract Year which were not assumed to have been mitigated through the exercise of Excess Sales Rights are collectively called "Non-mitigated Quantities";

    •        those Non-mitigated Quantities are assumed to be sold by Producers during the 1994/95, 1995/96 and 1996/97 Contract Years at published forecasted market prices for each of those Contract Years;

    •        a Producer's Historic Value Loss will be the difference between:

    •        the total of the loss of value on the sale of the Mitigated Quantities and the loss of profit that would have been earned from the sale of the Non-mitigated Quantities in the 1990/91 and 1991/92 Contract Years based on the applicable prices for each of those Contract Years; and

    •        the profit assumed to have been earned from the sale of the Non-mitigated Quantities in the 1994/95, 1995/96 and 1996/97 Contract Years based on a published price forecast for those Contract Years; and

    •        in determining a Producer's Historic Value Loss:

    •        profits on by-product revenue associated with the sale of Non-mitigated Quantities were included using an Alberta average profit margin per mcf of Non-mitigated Quantities adjusted to reflect whether the by-product content of a Producer's gas reserves is primarily low, high or average;

    •        operating costs and royalty rates were deducted, assuming industry average operating cost and royalty rates; and

    •        all amounts were adjusted to reflect the present value of those amounts as of November 1, 1993.

(b)         Shortfalls Prior to the Decontracting Date

            Data assessed to date indicates that no shortfalls in quantities required to be purchased by A & S under Specified Load Factor Contracts occurred during the 1992/93 Contract Year and none are anticipated to occur during the period from July 1, 1993 until the Decontracting Date. Operations during this period will not accordingly have any bearing on the determination of Settlement Payments.

(c)         Future Value Loss

            Each Producer's proposed Settlement Payment will include an amount that reflects the loss of value expected by some Producers to result from changes to their rights and obligations under the current arrangements due to implementation of this Decontracting Plan. The amount of that lost value (the "Future Value Loss") for each Producer has been estimated in accordance with the following principles:

    •        the Future Value Loss for each Producer was calculated by multiplying the quantity of gas (the "Valuation Quantity") that A & S would have been required to purchase from the Producer under the Producer's existing Contract(s) during the period from July 1, 1994 to June 30, 2005 (the "Valuation Period") by a price differential;

    •        the principles and assumptions applicable in determining each Producer's Valuation Quantity included the following:

    •        sales by A & S to PGT during the Valuation Period were assumed to be 900 mmcf/d;

    •        sales to A & S's Canadian Markets during the Valuation Period were assumed to be 184 mmcf/d;

    •        generally a Producer's reserves under existing Contract(s) were assumed to decline over the Valuation Period at a forecast A & S system-wide average rate of decline which takes into consideration the Producers' rights to infill drill and conduct other operations for the purpose of maintaining the level of DCQs under their Contracts. Contract specific decline rates were used:

    •        for Contracts with reserves that are in blowdown;

    •        for Contracts with reserves that given their age or size will decline at a rate which is significantly different than the system-wide average rate; and

    •        in circumstances where Producers have the right to require that A & S purchase additional gas from lands not presently dedicated under their Contracts with A & S;

    •        Non-Specified Load Factor Contracts were assumed to have a notional minimum purchase commitment equal to 30% of the Contract DCQ        ;

    •        Specified Load Factor Contracts were assumed to have a minimum purchase commitment equal to the minimum purchase commitment applicable under each of those Contracts;

    •        Firm Contracts were assumed to have a notional minimum purchase commitment equal to 100% of the ACQs; and

    •        all amounts were adjusted to reflect the present value of those amounts as of November 1, 1993.

(d)         Risk Adjustments

            The amounts determined for each Producer's Historic Value Loss and Future Value Loss were then adjusted to reflect:

    •        differences in the relative strength of specific contractual rights; and

    •        the risks applicable to the enforcement of the Contracts, taking into consideration both the specific and general legal defences that each of A & S, PGT and PG & E has in relation to the Contracts including:

    •        the availability of force majeure and other similar defences; and

    •        that A & S is the only party that any claim for Historic Value Loss, Future Value Loss or other losses under the Contracts could be enforced against.

[23]     On August 18, 1993, the Management Committee of Amoco Canada wrote a memorandum signed by the president, Mr. Stacy, as follows (Exhibit A-2, Tab 26):

Amoco Canada recommends accepting the provisions of a decontracting plan proposed by Alberta and Southern Gas Co. Ltd. (A & S) and its parent, Pacific Gas and Electric Company (PG & E). The plan provides that Amoco Canada (along with the other A & S producers) will terminate its existing contracts with A & S on October 31, 1993 and release A & S from all historic and certain future gas purchase obligations in exchange for the preservation of significant natural gas liquids (NGL) extraction rights and a cash payment of US $21 MM. The plan also requires that Amoco Canada accept assignment of the NOVA Corporation of Alberta (NOVA) receipt point and Northwestern Utilities Limited (NUL) transportation capacity associated with its dedicated lands (PVO US $74 MM).

Although not required by the decontracting plan, Amoco Canada also recommends accepting assignment of the NOVA delivery point and Alberta Natural Gas Pipeline Ltd. (ANG) transportation capacity associated with its dedicated properties (up to a maximum of 130 mmcf/d / PVO US $83 MM). Holding this transportation capacity to Kingsgate (interconnection of the ANG and Pacific Gas Transmission Company (PGT) pipelines at the international border) is desirable because Kingsgate is expected to be a key aggregation point and offers the lowest cost access for sales of Canadian gas to the US market (irrespective of whether PGT is tolled on an incremental or rolled-in basis). Sales of Canadian gas in the Kingsgate market are expected to generate premiums (versus alternative sales in Alberta markets) above the breakeven point of 1.8 percent required under the JFC Lower forecast and 1.3 percent required under the JFC Upper forecast.

Amoco Canada's alternative to accepting the proposed decontracting plan is resume litigation for the historic shortfall and continue (uncertain) future deliveries to A & S. Although it has a strong legal position, Amoco Canada believes that continued legal action may result in the loss of its NGL extraction rights associated with A & S's industry-wide dedicated properties. A & S and PG & E have agreed to make continuance of Amoco Canada's NGL extraction rights a part of the decontracting plan.

Amoco Canada recommends accepting the restructuring plan because the value of preserving the NGL extraction rights, together with the settlement payment, exceeds the value Amoco Canada can reasonably expect to recover through continued litigation with the PG & E family and fractured negotiations with decontracted A & S producers for extraction rights. Accepting the proposed decontracting plan yields a PV11 of US $0.5 MM under the JFC Lower forecast and US $14.8 MM under the JFC Upper forecast. In addition, accepting the decontracting plan avoids a potentially lengthy and costly battle in the Canadian and United States courts, and provides Amoco Canada with the desired greater control over its gas supplies.

[24]     The implementation of the decontracting plan necessitated a number of agreements. The net effect of the various steps required to implement the decontracting plan was as follows:

a)        the natural gas supply contracts between the producers and A & S were terminated;

b)       the lands dedicated to the natural gas supply contracts were released, thereby permitting the producers to sell to whomever they wished;

c)        the producers had to accept all of the transportation obligations relating to the inlet to the NOVA pipeline system and the Northwestern Utilities Limited pipeline capacity with respect to the gas produced from the lands previously dedicated to A & S;

d)       the producers were also entitled to accept further transportation obligations with respect to other natural gas pipeline systems;

e)        the producers entered into transitional and short term natural gas contracts with A & S and PG & E to provide natural gas to the California market.

[25]     One significant change that was made as part of the decontracting arrangement had to do with the Cochrane Extraction Plant Partnership ("CEPP"). Amoco had an arrangement with the CEPP under which the CEPP had long term rights to extract natural gas liquids from all natural gas A & S purchased and transported to California as it passed the Cochrane Extraction Plant. Amoco had a long term right to purchase the natural gas liquids and sell them throughout North America. Decontracting put the arrangement in jeopardy. If A & S was no longer responsible for the transportation it had no obligation to provide natural gas to the CEPP for the purpose of extracting the natural gas liquids.

[26]     The solution was an addendum to the Decontracting Plan (Exhibit A-2, Tab 23), the effect of which was to require all producers, as part of the decontracting, to enter into an agreement with CEPP giving it the right to extract natural gas liquids and ethane from any natural gas transported by the producers past the Cochrane Extraction Plant up to the aggregate of the maximum daily amounts under the producers' contracts with A & S.

[27]     This resolution of the natural gas extraction problem evidently satisfied Amoco. The decontracting plan was approved by it.

[28]     Tab 24 of Exhibit A-2 is a memorandum prepared by the head of the Natural Gas Liquid Business Unit, following the conclusion of the negotiations relating to the natural gas liquids extraction business. The memorandum reads:

Status of PG & E Negotiations - August 12, 1993

PG & E is going forward to the producers with the negotiated terms on extraction rights subject to the following:

1)          The extraction rights group signs the "Agreement in Principle Respecting Proposed Cochrane Arrangements" today.

Note: In Amoco's case, we will ensure that this does not imply acceptance of the terms of the Decontracting Proposal, lawsuit, etc. PG & E has confirmed verbally that it was not their intent.

2)          PG & E can terminate the "Cochrane Arrangements" at any time prior to October 18, 1993 if they feel that the Decontracting Plan cannot be implemented in a manner substantially in accordance with the provisions of the Plan.

I was advised by PG & E that they will not go forward with the Decontracting Plan or the Cochrane Arrangements without Amoco's participation. They will not increase the Amoco settlement above $22 million and they require Amoco acceptance by approximately September 15th to meet the FERC approval process.

I recommend Amoco accept the $22 million settlement amount because:

1)          Gas Marketing indicated it wanted $6-$8 million additional "value" but would settle for less than that. The value of the Cochrane extraction rights is much greater than that as shown in the attached memo. Amoco's operating income from the ANG Agreement is $20-$25 million per year.

Note: PG & E knows approximately what Amoco receives because they know what ANG earns and have copies of the ANG/Amoco agreements so they can hold firm.

2)          There must be some value in retaining a reasonable relationship with PG & E as a customer. They will continue to be a large, long term customer in an attractive market for Canadian gas.

[29]     The lawsuit referred to in the memorandum was a lawsuit brought against A & S and PG & E by Amoco Canada Resources Ltd. (the predecessor of the appellant) and its related company Amoco Petroleum Company Ltd. for damages for breach of contract for $49,100,000 and $35,600,000 respectively arising from an alleged failure to purchase the minimum annual volumes under the required natural gas contracts.

[30]     The total amounts claimed were made up of a number of figures, comprising losses on both revenue and capital account. Paragraphs 10 to 13 of the Amended Statement of Claim (Exhibit A-2, Tab 40) read:

10.        As a result of the failure to purchase and take the minimum annual volumes of natural gas as prescribed by the Amoco Petroleum Contracts and the Amoco Resources Contracts as aforesaid the Plaintiffs say that they have suffered losses and damages, as a result of the lost sales, in the amounts of $29,400,000 and $22,900,000 for Amoco Petroleum and Amoco Resources respectively.

11.        As a further consequence of the aforesaid failure to purchase and take, the Plaintiffs say that the ultimate recovery from the various fields is reduced as the reserves are depleted due to their unstable nature and the delay in the production, whereby the Plaintiffs have suffered losses in the amounts of $2,200,000 for each of Amoco Petroleum and Amoco Resources.

12.        As a further consequence of the aforesaid failure to purchase and take, the Plaintiffs say that they suffered losses as a result of drainage from the various reservoirs through production by others, in the amounts of $500,000 for each of the Amoco Petroleum and Amoco Resources.

13.        As a further consequence of the aforesaid failure to purchase and take, the Plaintiffs say that they incurred further losses as a result of the loss of use of the monies expended for capital expenditures and operating costs which were not required, in the amounts of $17,000,000 and $10,000,000 for Amoco Petroleum and Amoco Resources respectively.

[31]     The appellant's first witness, Mr. Dowhanik, a senior officer of the appellant, was the head of the team negotiating the settlement payment and the restructuring and decontracting of the A & S arrangements. He prepared a memorandum to management (Exhibit A-2, Tab 25) recommending acceptance of the Decontracting Plan under which Amoco (both companies) would receive $21,000,000 US. The memorandum compared the net economic results of accepting the decontracting plan. He postulated a best-case scenario and a worst-case scenario in determining the cost of accepting the plan and the difference between the two was about $14,000,000 US.

[32]     I set forth here his brief description of the Decontracting Plan:

Elements of Decontracting Plan

    ◆       Amoco/A & S/PGT/PG & E terminate all contracts and Amoco receives US$21MM from A & S/PGT/PG & E Condition precedent: removal of Canadian export restrictions

Amoco regains control over supply and gets cash. Canadian regulators are willing to remove restrictions for an industry supported settlement. Transition contracts are in place for 9 months.

    ◆      Amoco preserves NGL extraction rights

NGL extraction at Cochrane of A & S gas is a cornerstone of our profitable liquids business. Preservation of this was a key part of Amoco's settlement. Margins on 4000 bbl/d NGLs/

    ◆      Amoco receives NOVA/NUL receipt point capacity (Demand Charges US$74.1MM)

This transportation can be considered similar to gathering costs. It allows us to enter the intra provincial grid. It is mandatory for gas sales. We were paying these costs on a netback basis through A & S, although we did not have the obligations on our footnotes. 265MMcfd of transportation for approximately 8 years.

    ◆      Amoco has a two stage option on NOVA delivery and ANG transportation capacity to the international border (Demand Charges US$12.8MM)

This transportation allows us to access international markets (California and the Pacific NW). Holding this transportation will allow us to make Firm sales to these markets rather than interruptable. Premiums for firm sales will outweigh the demand charge costs. We are requesting 20MMcfd for these sales as well as 50 MMCFD for a previously authorized sale. The restructuring provides us with the opportunity to capture the previously authorized transportation.

    ◆      Amoco releases A & S/PG & E from all claims under our lawsuit

The lawsuit will be suspended until decontracting occurs. At that point claims will be dropped. The settlement relieves us from potentially large legal bills.

[33]     His recommendation was as follows:

A & S / PGT / PG & E Decontracting

Recommendation Accept the decontracting plan because the value of preserving the NGL extraction rights together with the settlement payment exceed the value that Amoco could reasonably attain through litigation.

This is a very good deal for the following reasons.

    ◆      Avoid risk of loss of litigation

The result of litigation is not a certainty. The corporate veil issue could not be guaranteed in our favour. The settlement is certain.

    ◆      Preservation of NGL extraction

A key part of the settlement was the preservation of our strong competitive position at Cochrane.

    ◆      Resolution of regulatory stalemate

This reduces the future regulatory interference and allows for the potential of stability.

    ◆      Provides transportation to market center

The settlement provides for transportation to the point of competition for Canadian gas to the Pacific NW and California.

[34]     Mr. Softley's cross-examination of Mr. Dowhanik was thorough and skilful and in it he endeavoured to support the basis upon which the assessment was made. The amended reply to the notice of appeal states that the assessment was based upon the following assumptions:

a)          the facts as admitted;

b)          the payments received by the Appellant pursuant to the Decontracting Agreement and Amendment Agreement were calculated by applying the price differential between the natural gas price in the terminated gas supply contracts and the current market price to the volumes of natural gas to be delivered under the gas supply contracts;

c)          the payments compensated for amounts that otherwise would have been received and credited to the profit of the business of the Appellant;

d)          the Appellant continued to produce oil and natural gas for sale after the termination of the gas supply contracts with A & S pursuant to the Decontracting Agreement and Amendment Agreement;

e)          the payments were not made for any actual production of natural gas by the Appellant;

[35]     The cross-examination sought to establish that over the years in which Mr. Dowhanik was employed by the appellant or its predecessors there had been a number of changes as part of a gradual evolution. The changes brought about by decontracting were simply part of that evolutionary trend. In other words the pre- and post-decontracting method of operating was not significantly different. I shall revert to this contention later in these reasons.

[36]     Mr. Dowhanik agreed that Amoco's (both the appellant and Amoco Canada Resources Ltd.) gross sales of natural gas were about one billion cubic feet per day and of that amount about 13% was under the contracts to A & S and the remaining 87% was to other purchasers. A substantial portion of the 87% was to other aggregators, which the witness stated that the A & S sales represented between 15 to 20% of Amoco's sales to all aggregators.

[37]     The second aspect of Mr. Softley's cross-examination of Mr. Dowhanik related to the manner in which the payment was calculated. Much of this centred on Schedule F to the decontracting plan, which is reproduced above.

[38]     I set out portions of the cross-examination on this point (transcript, volume II, pages 179 to 186):

Q.         That said, I take you now to Schedule "F" of the document and you will see in Schedule "F" it is entitled "Principles Applicable to Determination of Settlement Payments"?

A.         Yes.

Q.         Once again, would you agree with me that at this point in time you at Amoco understood that the principles by which the determination of settlement payments were going to be made by A & S were as expressed in this schedule and had flowed out of further discussions subsequent to the restructuring plan?

A.         That is what this document says.

Q.         And that is what you understood?

A.         This calculation which is really indeterminate, we can't calculate the unique number. You can calculate it at a billion dollars. I don't think this is what would have been in front of us.

Q.         I'm trying to understand what you just said. Are you telling me that if the calculation had been a billion dollars then you would have thought A & S would have gone, "Whoa", and not proceeded with stating these principles, is that what you are saying?

A.         Yes, as I shared with you in January and April. We had negotiations with A & S and this decontracting plan was very much a presentation from A & S, they wrote it, they presented it to the 190 producers and it was a way for them to market the decontracting to us, so they probably felt that they needed to provide a rationale.

Q.         Not only did they feel it, they did it and this was set forth in this document and would it not be fair to say that your understanding was that they were providing the same principles and rationale with respect to the configuration and determination of the settlement payment as they had done in the restructuring plan?

A.         They have words that say almost exactly the same thing.

Q.         Indeed they do, thank you.

A.         And when you take a look at it, I don't know exactly what their intent was. I do know that we negotiated with them over the settlement payment.

Q.         And further to that discussion, you will agree that the system that was in place that was being suggested through this plan and which ultimately actually came to be the system when the decontracting agreement was signed, was that settlement payments would be provided and calculated and given to producers such as Amoco and that a third party reviewer would be affirming in its review of those payments that there was equal treatment being afforded to various participants?

A.         When I was talking to Mr. Meghji yesterday I made some comments about the equal treatment confirmation that was made by Deloitte and Touche and I still struggle with exactly what that confirmation means because I really don't see that it had an awful lot of - it wan't clear as to exactly what they were confirming, that similarly situated producers were being treated generally the same and to me that gave an awful lot of latitude that they were equally treated.

Q.         All right.

A.         At the time of decontracting it was a big smirk on all of the producers' faces. Nobody would understand exactly what that meant. I think it was primarily there for the facilitator.

Q.         But it was also part of the contractual arrangements that you signed, correct?

A.         I didn't sign it, but it was part of the closing document.

Q.         Well, I suppose we will leave to argument how much meaning we can put on the components, what the corporations signed.

            You will agree with me that at the end of the day, Amoco received its cheque?

A.         I agree that we received a cheque for 22 million dollars.

Q.         And it received an equal treatment confirmation from the third party reviewer?

A.         It was part of our closing book, yes.

...

Q.         MR. SOFTLEY:           Was it your understanding at this time when Amoco received equal treatment confirmation form that the third party reviewer was acting in accordance with the principles and policies of the decontracting plan and agreement?

A.         I am going to try to answer this carefully two different ways. The equal treatment confirmation says that they did. Did we believe that they did it? Mr. Softley, it's a stretch to think that the number that was calculated was 22 million followed by 8 zeros. That level of precision to come up with a number that round with a formula that is in principles and we have been going back and forth on them, is a bit of a stretch.

Q.         Sir, I don't think I understand what you mean when you say 22 million followed by 8 zeros?

A.         It's like having 10 significant figures in mathematics. That means that every single figure is significant because one following does not change it so when you look at it there is 22 comma, zero, zero, zero, comma, zero, zero, zero point zero, zero. A formula as complicated as schedule "F" purports to be you would never be able to get something that got to 22 million even rounded. It would be a confluence of a great many -- the probability would be so low.

Q.         I think I understand what you are saying with respect to the mathematical precision, but you will agree with me that the exercise was to be or it was understood to be providing a payment in accordance with common principles?

A.         That is what the equal treatment confirmation says.

...

A.         I have it.

Q.         If you can go to page 17, clause 8.7.

A.         Yes.

Q.         That is headed "Equal Treatment Confirmation", and I would just like, for the record, to read it together with you and it says:

"Insurance of the equal treatment confirmation by the reviewer shall constitute conclusive evidence that the principles used to calculate participating producers' settlement payments including sellers' settlement payment generally have been consistently applied and generally participating producers with similar rights have been treated in a uniform manner regarding the settlement payments paid to them."

            Now, having read that together, sir, would you not agree with me that Amoco has never taken issue with A & S, PGT or PG & E that the equal treatment confirmation they received from the reviewer was not provided in compliance with this clause?

A.         The equal treatment confirmation was provided pursuant to this clause.

[39]     As I read Mr. Dowhanik's evidence I cannot find that the $21,000,000 received by Amoco was calculated as the "price differential between the natural gas price in the terminated gas supply contracts and the current market price to the volumes of natural gas to be delivered under the gas supply contracts". I do not think that Amoco, as represented by Mr. Dowhanik, saw it as such a calculation or as an amount that was to be credited to the profits of the business. It was essentially an arbitrary figure forming part of an overall restructuring of their relation with the California market.

[40]     The essential arbitrariness of the figure is confirmed by the evidence of Mr. Jenkins-Stark, who at the relevant time was the senior person in charge of the decontracting negotiating team on behalf of PG & E. Essentially he started with a figure of $199,000,000 US (subsequently raised to $210,000,000 because of an error) that he was prepared to pay to all of the producers. His main problem was how to allocate this amount among the producers.

[41]     A few passages from his examination in chief are illustrative (transcript, volume II, pages 242 to 247):

Q.         But in terms of the final number that you arrived at, say with Amoco, how was that number arrived at?

A.         We knew generally a range of numbers that Amoco had demanded, and I can't recall what they were right now, but we knew that there was a range of numbers that they were demanding and, you know, frequently producers were not forthcoming with a specific demand because they were holding out and holding out, but as I recall we knew a range of numbers and we also knew that given Amoco's contracts and applying certain weights to each of the attributes to their contracts, when applied those same weights to the entire pool would get us to a number in this 22 million dollar range, so I knew that if Amoco said, "We are not doing this for less than 30 million dollars.", I couldn't do that number because that would exceed my 199 cap and I was adamant of not exceeding that. So we basically at the end of the day came to an agreement over dinner with Amoco about what the final number would be and we used that number and all the attributes of the Amoco agreements to extrapolate what the outcome for the entire pool would be and that then fell under the 199 number that I established.

Q.         Mr. Jenkins-Stark, I am going to put in front of you a document that is in a binder here.

                        Your honour, I am taking the witness to tab 22.

                        Mr. Jenkins-Stark, do you recognize that document?

A.         Yes, I do.

Q.         Is that the decontracting plan that was circulated to the producers in July of '93?

A.         It looks like it.

Q.         Would you turn to article 3, please.

A.         Yes.

Q.         This article deals with a settlement of claims and if we go to the second paragraph it says,

"Economical analyses have been undertaken to determine any loss of value that A & S or the producers may experience as a result of the implementation of the plan. These economic analyses produce different results depending on the legal and economic assumptions used."

Do you see that?

A.         Yes.

Q.         And then it says,

"In recognition of the potential for differences of interpretation regarding the results of the economic analysis in order to complete the decontracting plan in an expeditious manner, settlement payments would be made to each producer that participates in the decontracting."?

A.         Yes.

Q.         Were such economic analyses conducted as the phrase is used there, what kind of analysis would that be talking about?

A.         I believe it refers to the factors that were used in the allocation scheme which included, I think --

Q.         Are you looking at schedule "F"?

A.         Yes. So each of those was used in the spreadsheet to calculate a producers specific payment, however there are some key paragraphs in schedule "F" that are very important to this overall spreadsheet in that there are a couple of cases where you will see that there is an estimate of the future price forecasts that are used and then there is also an estimate of the relative strength of specific contractual rights and availability of certain defenses to PG & E.

Q.         I can take you to that, if you look at page F4 in schedule "F" the last item says,

                        "Risk Adjustments"

Is that what you are talking about? I think the words you used were "significant" or whatever?

A.         Yes.

Q.         Now, why is that risk adjustment clause significant, why would you refer to it that way?

A.         Well, it's significant for two reasons and one is it is real, i.e., there were differences in the specific contractual rights of each party and of course any litigation has its litigation risk and there were defenses available to PG & E and its affiliates so it's significant in that it is real.

                        The second reason that it is significant is that no matter what the foregoing calculation yields, I can multiply by a number here to get the right number for each individual producer in the entire pool so just hypothetically let's say the calculation of everything that preceded it added up to 1 million dollars and if applied to the entire pool I now had a billion dollar calculation, well, that didn't fall under my 199 cap so I would take that 1 million dollars and I would have a risk adjustment of .2 and all of a sudden I have a $200,000.00 payment here with, again, applied to the entire pool yielded 200 million dollars so this was in there by design in the calculations but it was also real, it represented real legal issues.

Q.         Mr. Jenkins-Stark, do the principles set out in the schedules reflect why PG & E paid the producers this amount as part of the decontracting?

A.         No, they don't set out why we paid them, we paid for our own commercial interest.

Q.         What do these principles do, sir?

A.         They set out the mechanism by which each producer can be assured of receiving their fair share of the payment pot, so that they are similarly situated, producers are treated similarly, which was, as I said, a guiding principle from the Alberta government and the APMC.

                        Now, I think they do say how it's calculated but it's key to remember that there are one or two assumptions plus the litigation risk assessment which allow us to then contain all the payments within the cap that I identified to the team.

Q.         Mr. Jenkins-Stark, after these contracts were cancelled, did PG & E enter into any similar long-term contracts again?

A.         I was directly responsible for the gas purchasing activities at PG & E following this and we did not, albeit there was transitional agreements as part of the restructuring, a small tiny agreement.

                        Now, we went to what really occurs today all through North America which is a series of spot and short-term contractual agreements and some may extend several months and some may be for the day and some for a week, it's a mixture of agreements but the days -- well, Alberta and Southern was disbanded after this decontracting and was disbanded and there were remnants of Alberta and Southern that were sold.

[42]     I have referred at some length to the evidence of these two important witnesses, one representing the payor and one the payee, in an attempt to determine whether the view that the payments were calculated by reference to lost profits or lost revenues can be supported, because this is essentially the premise on which the assessment is based. I do not think the evidence supports this designation of the payment or the manner of its calculation. It was an arbitrary figure forming part of the regulation of a major restructuring of an important part of the appellant's business. Moreover, part of the settlement entailed getting rid of a large and troublesome law suit whose outcome was at best uncertain.

[43]     With respect to paragraph (d) of the assumptions that the appellant continued to produce oil and gas for sale after the termination of the gas supply contracts with A & S, the statement is true. The appellant's business did not come to an end. However, with respect to that part of its business that involved A & S, it was carried on under a significantly different structure. The contracts were short term, the pricing was different and the appellant's lands and reserves relating to the gas and oil to A & S were released and no longer dedicated to the requirements of the particular purchaser, A & S. Moreover, the transportation arrangements were significantly altered.

[44]     The respondent contended that the amount received by the appellant was simply compensation for the cancellation of a sales contract. With respect, I think this is an oversimplification. The arrangements with A & S entailed the dedication of reserves on particular lands to the contracts and also relieved Amoco of any transportation obligations. Once the contracts were terminated the lands were released and Amoco had to make its own transportation arrangements.

[45]     One final point before I turn to the cases. Mr. Meghji read into the record portions of the examination for discovery of an officer of the Crown in which it was admitted that the contracts were capital property. He said (transcript, volume II, page 287):

Q. Okay. In reviewing the documents and in raising this assessment, you never assumed these contracts were inventory at any time did you?

A.         No.

Q.         These contracts were not acquired for sale?

A.         No.

Q.         These contracts were acquired by Amoco or Amoco entered into these contracts to earn income therefrom?

A.         Yes.

Q.         So, they were always capital property?

A.         Capital in that nature, yes.

A.         Okay. You don't disagree with the fact that those contracts were essentially disposed of as a result of the decontracting payment?

There is no question about that?

A.         They were terminated, yes.

[46]     It was of course quite proper to put these questions to the Crown officer and to read them into the record but the admissions are admissions of law or at best mixed fact and law and are not binding on the court. Nonetheless I agree with the Crown officer. It would be difficult to describe these long term contracts as other than capital assets.

[47]     There is no paucity of jurisprudence in this area of the law. Counsel referred to over forty cases in the aggregate and this I am sure is but the tip of the iceberg. In the past, Canadian courts have derived guidance from the vast body of English jurisprudence in the area of capital versus income receipts or payments. For example in M.N.R. v. Algoma Central Railway, 68 DTC 5096, the Supreme Court of Canada referred with approval to a decision of the Privy Council in B.P. Australia Ltd. v. Commissioner of Taxation of the Commonwealth of Australia, [1966] A.C. 224 at p. 264, where Lord Pearce said:

The solution to the problem is not to be found by any rigid test or description. It has to be derived from many aspects of the whole set of circumstances some of which may point in one direction, some in the other. One consideration may point so clearly that it dominates other and vaguer indications in the contrary direction. It is a commonsense appreciation of all the guiding features which must provide the ultimate answer.

[48]     This observation is useful whether we are dealing with receipts or payments. As Canadian courts have developed their own body of jurisprudence there is perhaps less need to refer to English cases although I still consider it worthwhile to see how English courts have dealt with similar problems. Obviously, where there is a divergence, the Canadian cases must prevail.[1]

[49]     I start then with a reference to two English cases, both of which have been cited with approval and followed in Canada and which I believe are good law in Canada. The first is Van den Berghs Ld. v. Clark, [1935] A.C. 431. In that case the appellant and its rival, a Dutch company, had entered into a series of agreements regulating the manner in which they carried on business and pooling their profits. Disputes arose and lengthy negotiations and arbitration ensued. The matter was settled by the Dutch company agreeing to pay the appellants 450,000 l. "as damages". The House of Lords held the receipt was on capital account. At pages 438-9, Lord Macmillan said:

My Lords, the problem in discriminating between an income receipt and a capital receipt and between an income disbursement and a capital disbursement is one which in recent years has frequently engaged your Lordships' attention. In general the distinction is well recognized and easily applied, but from time to time cases arise where the item lies on the borderline and the task of assigning it to income or to capital becomes one of much refinement, as the decisions show. The Income Tax Acts nowhere define "income" any more than they define "capital"; they describe sources of income and prescribe methods of computing income, but what constitutes income they discreetly refrain from saying. Nor do they define "profits or gains"; while as for "trade," the "interpretation" section of the 1918 Act only informs us, with a fine disregard of logic, that it "includes every trade, manufacture, adventure or concern in the nature of trade." Consequently it is to the decided cases that one must go in search of light. While each case is found to turn upon its own facts, and no infallible criterion emerges, nevertheless the decisions are useful as illustrations and as affording indications of the kind of considerations which may relevantly be borne in mind in approaching the problem.

The reported cases fall into two categories, those in which the subject is found claiming that an item of receipt ought not to be included in computing his profits, and those in which the subject is found claiming that an item of disbursement ought to be included among the admissible deductions in computing his profits. In the former case the Crown is found maintaining that the item is an item of income; in the latter, that it is a capital item. Consequently the argumentative position alternates according as it is an item of receipt or an item of disbursement that is in question, and the taxpayer and the Crown are found alternately arguing for the restriction or the expansion of the conception of income.

[50]     At pages 440-441 he said:

My Lords, if the numerous decisions are examined and classified, they will be found to exhibit a satisfactory measure of consistency with Lord Cave's principle of discrimination. Certain of them relate to excess profits duty and not to income tax, but for the present purpose this distinction is immaterial. A sum provided to establish a pension fund for employees, as has already been seen, is a capital disbursement: British Insulated and Helsby Cables, Ld. v. Atherton (4); so is a sum paid by a coal merchant for the acquisition of the right to a number of current contracts to supply coal: John Smith & Son v. Moore (5); so is a payment by a colliery company as the price of being allowed to surrender unprofitable seams included in its leasehold: Mallett v. Staveley Coal & Iron Co. (6) Similarly a sum received by a fireclay company as compensation for leaving unworked the fireclay under a railway was held to be a capital receipt: Glenboig Union Fireclay Co. v. Commissioners of Inland Revenue. (7)

On the other hand, a sum awarded by the War Compensation Court to a company carrying on the business of brewers and wine and spirit merchants in respect of the compulsory taking over of its stock of rum by the Admiralty was held to be a trade or income receipt: Commissioners of Inland Revenue v. Newcastle Breweries, Ld. (8); so was a sum paid to the shipbuilding company for the cancellation of a contract to build a ship: Short Brothers, Ld. v. Commissioners of Inland Revenue (1); so was a lump sum payment received by a quarry company in lieu of four annual payments in consideration of which the company had relieved a customer of his contract to purchase a quantity of chalk yearly for ten years and build a wharf at which it could be loaded: Commissioners of Inland Revenue v. Northfleet Coal and Ballast Co. (2); so was a sum recovered from insurers by a timber company in respect of the destruction by fire of their stock of timber: J. Gliksten & Son v. Green. (3) Conversely, where a company paid a sum as the price of getting rid of a life director, whose presence on the board was regarded as detrimental to the profitable conduct of the company's business, the payment was held to be an income disbursement: Mitchell v. R.W. Noble, Ld. (4); so was the payment made in the case of the Anglo-Persian Oil Co. v. Dale (5) in order to disembarrass the company of an onerous agency agreement. There are further instances in the reports, but I have quoted enough for the purposes of illustration.

(4) [1926] A.C. 205.

(5) [1921] 2 A.C. 13.

(6) [1928] 2 K.B. 405.

(7) 1922 S.C. (H.L.) 112.

(8) (1927) 17 Tax Cas. 927.

(1) (1927) 12 Tax Cas. 955.

(2) (1927) 12 Tax Cas. 1102.

(3) [1929] A.C. 381.

(4) [1927] 1 K.B. 719.

(5) [1932] 1 K.B. 124.

[51]     And at pages 442-443:

Now what were the appellants giving up? They gave up their whole rights under the agreements for thirteen years ahead. These agreements are called in the stated case "pooling agreements," but that is a very inadequate description of them, for they did much more than merely embody a system of pooling and sharing profits. If the appellants were merely receiving in one sum down the aggregate of profits which they would otherwise have received over a series of years the lump sum might be regarded as of the same nature as the ingredients of which it was composed. But even if a payment is measured by annual receipts, it is not necessarily itself an item of income. As Lord Buckmaster pointed out in the case of the Glenboig Union Fireclay Co. v. Commissioners of Inland Revenue (1): "There is no relation between the measure that is used for the purpose of calculating a particular result and the quality of the figure that is arrived at by means of the test."

The three agreements which the appellants consented to cancel were not ordinary commercial contracts made in the course of carrying on their trade; they were not contracts for the disposal of their products, or for the engagement of agents or other employees necessary for the conduct of their business; nor were they merely agreements as to how their trading profits when earned should be distributed as between the contracting parties. On the contrary the cancelled agreements related to the whole structure of the appellants' profit-making apparatus. They regulated the appellants' activities, defined what they might and what they might not do, and affected the whole conduct of their business. I have difficulty in seeing how money laid out to secure, or money received for the cancellation of, so fundamental an organization of a trader's activities can be regarded as an income disbursement or an income receipt. Mr. Hills very properly warned your Lordships against being misled as to the legal character of the payment by its magnitude, for magnitude is a relative term and we are dealing with companies which think in millions. But the magnitude of a transaction is not an entirely irrelevant consideration. The legal distinction between a repair and a renewal may be influenced by the expense involved. In the present case, however, it is not the largeness of the sum that is important but the nature of the asset that was surrendered. In my opinion that asset, the congeries of rights which the appellants enjoyed under the agreements and which for a price they surrendered, was a capital asset.

(1) 1922 S.C. (H.L.) 112,115.

[52]     Now what guidance does this venerable authority afford to us in the year 2002? There are a number of things that Lord Macmillan says that are of interest:

a)        A contract that forms a fundamental part of a company's business structure is a capital asset.

b)       If a contract is a capital asset a payment for its cancellation is a capital receipt.

c)        In distinguishing between capital and income amounts the same principles apply whether we are dealing with payments or receipts. I hesitate to accept this proposition wholeheartedly. However, the question is not one that needs to be answered here.

d)       The cases listed by Lord Macmillan as falling on one side of the law or the other illustrate the difficulty of finding perfect consistency in this area.

[53]     Van den Berghs is at one end of the spectrum. At the opposite end is London and Thames Haven Oil Wharves, Ltd. v. Attwooll (Inspector of Taxes), [1967] 2 All E.R. 124 (C.A.) at pages 134-135, where Lord Diplock made the following statement, which has frequently been quoted with approval in Canadian courts:

The question whether a sum of money received by a trader ought to be taken into account in computing the profits or gains arising in any year from his trade is one which ought to be susceptible of solution by applying rational criteria; and so, I think, it is. I see nothing in experience as enbalmed in the authorities to convince me that this question of law, even though it is fiscal law, cannot be solved by logic, and that, with some temerity, is what I propose to try to do.

I start by formulating what I believe to be the relevant rule. Where, pursuant to a legal right, a trader receives from another person compensation for the trader's failure to receive a sum of money which, if it had been received, would have been credited to the amount of profits (if any) arising in any year from the trade carried on by him at the time when the compensation is so received, the compensation is to be treated for income tax purposes in the same way as that sum of money would have been treated if it had been received instead of the compensation. The rule is applicable whatever the source of the legal right of the trader to recover the compensation. It may arise from a primary obligation under a contract, such as a contract of insurance; from a secondary obligation arising out of non-performance of a contract, such as a right to damages, either liquidated, as under the demurrage clause in a charterparty, or unliquidated; from an obligation to pay damages for tort, as in the present case; from a statutory obligation; or in any other way in which legal obligations arise.

The source of a legal right is relevant, however, to the first problem involved in the application of the rule to the particular case, viz., to identify for what the compensation was paid. If the solution to the first problem is that the compensation was paid for the failure of the trader to receive a sum of money, the second problem involved is to decide whether, if that sum of money has been received by the trader, it would have been credited to the amount of profits (if any) arising in any year from the trade carried on by him at the date of receipt, i.e., would have been what I shall call for brevity an income receipt of that trade. The source of the legal right to the compensation is irrelevant to the second problem. The method by which the compensation has been assessed in the particular case does not identify for what it was paid; it is no more than a factor which may assist in the solution of the problem of identification. I will not again traverse the cases. They seem to me to be directed to the solution of one or other of these two problems, which are not always distinguished in the judgments. In the course of these judgments different metaphors and similies (appropriate no doubt to the particular facts of the case) have been used. But I do not think that any of these conflict with the rule as I have expressed it.

[54]     Most cases fall somewhere between these two extremes. One must avoid the temptation to pluck felicitous phrases from the cases, which can support almost any conclusion, and thereby to lose sight of the real purpose of the enquiry, that of determining whether the payment is made for the termination, disposition or sterilization of a capital asset or is one of the ordinary incidents of an ongoing business so that the receipt properly forms part of the normal receipts of the trade.

[55]     I do not propose to deal with all of the authorities referred to by counsel. Whether a piece of property, such as a contract, is a capital asset of the business is a conclusion of law that depends on the facts of the particular case. For example, in Aallcann Wood Suppliers Inc. v. The Queen, 94 DTC 1475, it was held that the sale of a taxpayer's contract with a pulp mill was the sale of a capital asset. In Prince Rupert Hotel (1957) Ltd. v. The Queen, 95 DTC 5227, the Federal Court of Appeal upheld a trial court decision that damages received from the taxpayer's solicitor for errors in drafting agreements under which it was to receive management fees were income. Canadian National Railway Company v. M.N.R., 88 DTC 6340, and Pe Ben Industries Company Limited v. The Queen, 88 DTC 6347, arose out of somewhat similar circumstances - a payment for the cancellation to a transportation contract. In the former case, it was held that no enduring asset in the form of a separate business or a long term contract was destroyed whereas in the latter it was held that a distinct part of the appellant's business structure was destroyed. Therefore in the Canadian National Railway case the payment was on revenue account and in the Pe Ben case it was on capital account. In Westfair Foods Limited v. The Queen, 91 DTC 5073, it was held that amounts received for the termination of two leases were capital.

[56]     In The T. Eaton Company Limited v. The Queen, 99 DTC 5179, the Federal Court of Appeal held that the payment for the cancellation of a participation clause in a lease was a capital receipt. Robertson, J. with whom Strayer and Linden, JJ. concurred, stated at page 5185:

[35] In this case, the buy-out of the participation clause had no effect upon the taxpayer's normal business operations. Nor did it affect the taxpayer's right to remain in possession under the lease. Its termination did not, for example, "cripple" the taxpayer's profit-making business at the Oshawa Shopping Centre. Thus, I readily concede that the Fleming exception has no application to the present case. But this concession does not end the matter, because I am also of the view that the trade contract analogy is inappropriate.

[36] In my respectful view, the participation clause is not only an integral component of the lease in question, but it also profoundly affects the value of a capital asset, namely, a leasehold estate in land. As stated in London & Thames Haven, an asset's profitability is an element to be considered in assessing its capital value. In this regard, the participation clause is intimately linked to a capital asset and its value. What the Minister fails to appreciate is that a tenant's lease is not simply a liability, as was asserted in oral argument. A leasehold interest in land also represents a capital asset, the value of which depends on both the terms of the lease and market conditions. For example, a tenant whose rent obligation is one-half the market rate has a valuable asset which can be sold by way of assignment, subject to any restriction protecting the interests of the landlord. Similarly, a lease which contains a participation clause is of even greater value, particularly if the shopping centre becomes profitable, as in the present case. Otherwise, the landlord would not have been willing to buy-out the clause for $9.25 million.

[37] In my respectful opinion, the buy-out of the participation clause had the obvious effect of diminishing the value of the taxpayer's capital asset by $9.25 million. That is what the clause was worth to both the landlord and the taxpayer. I see no reason why this Court should not accept that compensation paid for the diminution in value of a leasehold estate is on capital account. The cancellation of the participation clause had as much effect on the value of the leasehold interest as would a fire, which partially destroys the premises. Since compensation for such a loss would be on capital account, the same should hold true for a voluntary loss arising from the cancellation of a contractual right which forms an integral component of a capital asset.

[38] At the end of the day, there are two sets of prescription lenses that can be used to determine whether compensation for the loss of future profits arising from the cancellation of a participation clause is on income or capital account. Using the Minister's prescription, the buy-out of the participation clause replaces an income source and is, therefore, an income receipt. According to the taxpayer's prescription, the buy-out diminishes the value of a capital asset for which compensation must be characterized as a capital receipt. Were it not for the fact that the participation clause in question is an integral component of the lease, the Minister's prescription would have been the only acceptable one.

(emphasis added)

[57]     In applying the principles enumerated in the above cases, as well as the numerous other cases quoted by counsel, I can summarize my conclusion briefly.

a)        The long term natural gas supply contracts that the appellant had with A & S were capital assets of the appellant. They formed a significant part of the structure of the appellant's business. Indeed, the dedication to the contract of the lands containing the reserves does no more than fortify this conclusion. By analogy to the portion of the T. Eaton judgment italicized above the dedication of the reserves on the lands affects the value of the contract and reciprocally the dedication in the contract affects the value of the lands, which are obviously capital assets. Put more simply, the lands are an integral part of the contracts.

b)       The payments made to the appellant were not for a loss of a "stream of income". Indeed they were not based on the income that the appellant expected to receive from the contracts. Rather they were an aspect of the entire decontracting arrangements which involved a major restructuring of a significant part of the appellant's business a part of which in turn was the cancellation of the long term contracts. Even if the payments were measured by the present value of the profits which the company might reasonably be expected to earn this would not deprive the payments of their quality of capital because they were compensation for the sterilization of a capital asset. This principle was stated by the Lord President (Clyde) in The Glenboig Union Fireclay Co., Ltd. v. The CIR, 12 TC 427 at pages 448-449, and in the House of Lords by Lord Buckmaster at pages 463-464 and by Lord Wrenbury at pages 465-466.

c)        I have concluded that the assumptions contained in paragraphs 13(b) and (c) of the amended reply to the notice of appeal have been demolished. They were fundamental to the assessment which, therefore, cannot stand. The amounts received were not income from the appellant's business nor were they income from any other source. They were receipts on capital account. It remains therefore to determine how such receipts of capital are to be treated under the Income Tax Act. Capital receipts have a variety of different consequences under Canadian income tax law. Sometimes they are treated as the proceeds of disposition of capital property, giving rise to capital gains or losses. Sometimes they are treated as proceeds from the sale of eligible capital property. Sometimes they are simply non taxable capital receipts. Lottery winnings, bequests, gifts, proceeds from the sale of a principal residence or damages for personal injury fall into this category.

d)       I do not think the receipts here fall into the latter category. I see no reason to disagree with the appellant's characterization of the amounts received as proceeds of disposition of the contracts, which as I have said are capital assets. The contracts and the rights under them were terminated and this in my view constitutes a disposition. If I am right in this conclusion it follows that the amounts represent a capital gain. The appellant did not endeavour to establish that the contracts had an adjusted cost base in excess of nil dollars. If I am wrong in concluding that the amounts represent the proceeds of disposition of the contracts this would not detract from the conclusion that the receipts are capital amounts. They certainly are not income.

[58]     In light of this conclusion I need not deal with the appellant's alternative contention that the amounts, if income, are resource profits.

[59]     The appeal is allowed with costs and the assessment is referred back to the Minister of National Revenue for reconsideration and reassessment on the basis that the amounts received from A & S and PGT represent proceeds of disposition of capital assets and are therefore receipts on capital account.

Signed at Toronto, Canada, this 16th day of October 2002.

"D.G.H. Bowman"

A.C.J.

COURT FILE NO.:                             2000-5160(IT)G

STYLE OF CAUSE:                 Between BP Canada Energy Resources Company

as Successor to Amoco Canada Resources Ltd. and

Her Majesty The Queen

PLACE OF HEARING:                      Calgary, Alberta

DATE OF HEARING:                        June 17, 18, 19 and 20, 2002

REASONS FOR JUDGMENT BY:     The Honourable D.G.H. Bowman

                                                          Associate Chief Judge

DATE OF JUDGMENT:                     October 16, 2002

APPEARANCES:

Counsel for the Appellant:          Al Meghji, Esq.

                                                Gerald A. Grenon, Esq.

                                                Catherine E. Bradley

Counsel for the Respondent:      William L. Softley, Esq.

                                                R. Scott McDougall, Esq.

COUNSEL OF RECORD:

For the Appellant:

Name:                 Al. Meghji, Esq.

Firm:                  Donahue LLP

                         Calgary, Alberta

For the Respondent:                  Morris Rosenberg

                                                Deputy Attorney General of Canada

                                                          Ottawa, Canada

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