Oil Royalties At The Wellhead – Legal Principles And Practical Considerations

Originally published in Blakes Bulletin on Energy - Oil & Gas, July 2007

On February 22, 2007, the Manitoba Court of Appeal released its decision in Missilinda of Canada Ltd. v. Husky Oil Operations Ltd. (Missilinda). In Missilinda, the Court of Appeal examined how royalties should be calculated under a lease providing for a royalty payable on the current market value at the wellhead.

Missilinda of Canada Ltd. (Missilinda), the lessor, had an undivided 50% interest in Saskatchewan land known as the "Red Jacket" field. Husky Oil Operations Limited (Husky) was one of the lessees and operator of the oil wells to which the lease applied. The lease, dated October 9, 1984, contained the following royalty provisions:

The Lessor does hereby reserve unto himself a gross royalty of Seventeen & One Half (17½ %) per cent of the leased substances produced and marketed from the said lands. Any sale by the Lessee of any crude oil, crude naphtha, or gas produced from the said lands shall include the royalty share thereof reserved to the Lessor, and the Lessee shall account to the Lessor for his said royalty share in accordance with the following provisions, namely:

The Lessee shall remit to the Lessor, on or before the 25th day of each month, (a) an amount equal to the current market value at the wellhead on the date of delivery of Seventeen & One Half (17½ %) per cent of the crude oil and crude naphtha produced, saved and marketed from the said lands during the preceding month, and (b) an amount equal to the current market value at the wellhead on the date of delivery of Seventeen & One Half (17½ %) per cent of all gas produced and marked from the said lands during said preceding month.

The dispute between lessor and lessee centered around the calculation of royalties based on the current market value at the wellhead. The parties had agreed in a Statement of Facts that under the terms of the lease, transportation costs from the wells to the point of sale were shareable. Thus the sole issue for the trial judge was whether, under the terms of the lease, Husky was entitled to make further deductions for operating and capital costs and a return on investment for facilities "downstream" of the wellhead.

The trial judge found the "downstream" deductions made by Husky were shareable under the lease terms. Relying on the 1998 Alberta Court of Queen’s Bench decision of Justice Hart in Acanthus Resources Ltd. v. Cunningham (Acanthus), the trial judge found that the terms of the lease were not ambiguous and that the wording of the lease clearly allowed the deduction of downstream costs, including capital costs. Hart J. did not include capital costs in Acanthus, thus the trial judge would have expanded the principle of downstream deductibility. The trial judge also approved of the specific accounting methods used by Husky to calculate the amount of all deductible costs.

At appeal, the Court distinguished between patent and latent ambiguity; latent ambiguity arising when the "ambiguity is not observable on the face of the document" but becomes evident "when one attempts to apply the lease to the facts" (at para. 10). Unlike the judge at trial, a majority of the Court of Appeal decided that interpreting how a royalty was to be payable on the current market value "at the wellhead" was in fact latently ambiguous. Given that oil at the wellhead was not saleable and therefore had no "market value", the phrase required extrinsic evidence to interpret its meaning in context. The Court accepted that extrinsic evidence can be considered where the ambiguity is latent and, preferring Husky’s expert evidence supporting deductibility of downstream capital and operating costs, allowed such deductions in principle. In addition, the Court intimated that the lessor’s concession in the Agreed Statement of Facts, that transportation costs from the wellhead to the point of sale were shareable, was another factor in finding that capital and operating costs must also be shareable:

At one time, trucks were used to move the product from the well to the battery and from the battery to a point of sale. When trucks were used, I assume that the transportation costs included either the capital cost or the rental cost of the trucks and the wages of drivers. Now that those trucks have been replaced by flow lines constituting the gathering system and the sales line to the terminal, it makes sense that both the operating and capital costs of that system should be shared. (at para. 38)

However, the Court stopped short of upholding the calculation of such deductions as "properly calculated". It was not prepared to accept a specific method of accounting nor the values used for return on investment and other costs without satisfactory evidence of its appropriateness in the circumstances. The Court of Appeal did not elaborate on what evidence would be considered sufficient to prove the appropriateness of such costs as this issue was not properly before either court. The sole issue at trial was which deductions were appropriate under the terms of the lease. Whether they were properly calculated was a question for another day.

Twaddle, J.A., in dissent, found extrinsic evidence was not admissible as the term was not ambiguous. The dissent determined that the lease called for "payment of a royalty equal to 17½ % of the current market value of the oil at the wellhead. The fact that no oil could be sold at the wellhead does not invalidate the unambiguous formula ... the wellhead value of oil can be readily established by subtracting from the price eventually realized downstream of the wellhead the sum of the costs of transporting and storing the oil there and the cost of improvements made to the oil after it left the wellhead" (at para. 45). Twaddle, J.A., expressly approved the Alberta Court of Queen’s bench decision in Acanthus, but refused to find that the principal of downstream deductibility, as laid out in Acanthus and by the majority, could also be held to include deductions for capital costs and a return on investment.

The decisions at trial and by the majority and dissent at the Court of Appeal differ in their determination of the ambiguity of the term requiring a royalty calculable "at the wellhead". Practically, however, it is not this difference but rather the difference between each courts’ treatment of what costs may properly be included as part of the "principle" of downstream deductibility that is unsettling. Each court differed in its consideration of what could be properly deducted, how such deductions were to be made and what evidence was required to prove this.

Alberta courts generally consider that the wording at issue here is unambiguous, and that the principle of downstream deductibility allows the lessee to deduct substantial costs properly incurred to move oil to the point of sale. The decision by the Manitoba Court of Appeal in Missilinda is not binding on courts in Alberta and, given the lack of a strong, clear decision by all members of that Court, Missilinda does not provide additional clarity of the principle of downstream deductibility to lessors in Alberta acting under similarly worded leases, nor further comfort that a specific practice of making deductions is correct or incorrect.

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