Shut-in well due diligence

With a number of oil companies shutting in oil and gas production due to low prices, lessees should be thinking carefully about steps to protect their tenure from expiry in view of a recent Alberta Court of Appeal decision, for which leave to appeal was denied on June 30 by the Supreme Court of Canada.¹

This update will focus at a high level on some practical lessons from this decision, which concerned oil and gas leases from the 1960s that were challenged on the basis that the shut-in well provisions requiring a “lack of or intermittent market” were not satisfied. Some time after a well had been recompleted in a different formation from that initially shut in, claims were brought for a declaration of termination and for an accounting.

The following is a list of 10 key considerations for those shutting in production or bringing production back on after an extended period of shut-in.
 

Know the shut-in rules for your lease

As always, a company shutting in production on a lease should carefully review the provisions of the lease to ensure the planned shut-in has the desired effect of continuing the term. In general terms, the period of a shut-in that is justified by the “lack of or an intermittent market” or other “cause beyond lessee’s reasonable control” is “not to be counted” against the lessee in counting down the 90 days from a stoppage in production during which activities must resume in order for the lease not to terminate. It is worth noting, as there is sometimes confusion on this point, that leases invariably require both paying the shut-in royalties and satisfying the conditions to shut in.
 

The consequences of producing a “dead lease” have become more significant

In the absence of fraud or bad faith by the lessee oil company, the remedy for wrongfully producing from an expired lease is now disgorgement of lessee’s revenues less certain expenses, with no allowance for profit (para 196). This is referred to in this case as the “mild rule.”

Generally, deductible expenses are those production, gathering and processing expenses downstream of the wellhead that a lessee typically deducts from royalty calculations. However Rowbotham J.A. describes the mild rule as calculable “on the basis of revenue less drilling, operating costs and royalty expenses.” The inclusion of drilling costs is significant. O’Ferrall J.A.’s calculation is less forgiving and only allows the usual deduction of “costs incurred to render the leased substances marketable” without reference to capital improvements. If this is the case, unless a counter-claim could be advanced in equity, the capital for a well drilled or recompleted might be absorbed by the lessee without being recouped from the production.

The remedy could get more severe. McDonald J.A., in the minority on this point, favoured the “harsh rule” of “gross sale revenues received” on the basis of bad faith since in his view the lessees should have known they were producing an expired lease.

The selection of the mild rule represents a significant departure from the trial decision and from the ruling in Freyburg v Fletcher Challenge Oil and Gas Inc.,² both of which applied the considerably more forgiving “royalty method.” Under the royalty method the courts held that, since the lessors are not professional oil companies and would inevitably have to enter alternate leases to commercialize their resources, the correct measure of damages is based on whatever higher royalty rate and bonus terms they might extract in a new leasing process.

Why are you shutting in? Is it the market, or is it the well?

There is an inherent judgment call as to why something is uneconomic. Well economics are affected by well and production costs, production rates and prices. This case tells us that an uneconomic well does not necessarily reflect a lack of an economic market for production. O’Ferrall J.A. noted the well’s delivery problems and declining production, saying: “It is important to distinguish between interrupting or suspending production from a well capable of production and ceasing production from a formation that is no longer commercially productive.” In that case he said the production in the particular well was not being interrupted or suspended but “brought to an end.”

Consider: What well characteristics have you documented? Is there a record of production problems, rather than market price issues?

Are you shutting in or abandoning?

The court also considered evidence whether the well was shut in or abandoned. The protection of the shut-in well clause is only available to a well that is shut in. Consider the following:

• Are your changes to contracts and surface handling equipment consistent with a temporary shut-in?
• What is your plan for periodically revisiting the market status of the shut-in?

What should you think about before recommencing production?

Before expending capital on an expensive new well or recompletion you should consider the following:

• What does recompleting a well in a different formation say about the production capability of the originally shut-in formation? How is that different from an entirely new well?
• How long was the well shut in?
• Were other wells nearby in the same formation shut in or producing?
• What do your records state about the reason for the shut-in?
• Did the shut-in cease to be justified at some point?
• A new well or newly recompleted formation will not cure the expiry if more than 90 days has run without production of a defensible shut in of a well capable of production.
• Has there been any correspondence with the lessors about the lease status?
• Would you be safer to get the lease expressly re-granted or ratified?
• How long do you have to re-commence? Rowbotham J.A. states that, while the leases are generally silent on this point, the rule should be that in order to continue the lease, working operations should commence within 90 days of profitability becoming foreseeable.

Impacts for title review and purchase agreements

This case raises the likelihood that historical shut-in periods have resulted in an expiry of the lease. Buyers will want to pay attention to shut-in periods in conducting their title due diligence and may wish to consider modification of seller representations and warranties.

Gross Overriding Royalties (GORRs) should also be assessed carefully for unbroken title in the underlying lease interest. In this case there was a GORR reserved out of the lease and the GORR owner had received production royalties from the trespassing lessees. The court held that the GORR owner had received the benefit of production and this had to be accounted for to the lessors, suggesting that the trespassing lessees were to repay it to the lessors and look to the GORR owner for repayment.

Limitations

In this case, the Court of Appeal held that the lease expired either in 1995 or 2001. However, the lessees were protected to a degree by the Limitation of Actions Act and the two-year limitation period from when the lessors should have discovered their claims. The cause of action was in trespass and conversion and held to be a new claim each day with the result that the damages award “counts back” two years’ worth of production claims.

Lessees and lessors should be mindful to check whether there is any applicable contractual modification of this time period, such as the Industry Agreement on Limitations.
 

What can you consider in determining whether there is an “economic market”

In determining whether you have a lack of an economic market consider the following:

• Some amount of profitability may be reasonable to include in calculating whether an economic market exists for the well. Even in the absence of an express reference to profitability, Rowbotham J.A. decided that the third proviso required an “economic or profitable” market but this was satisfied by satisfaction of basic hurdle rates and did not require “compelling” profitability. Caution is required on this point, as the justices’ decisions differ.
• Receipt of an independent operations notice was noted as evidence of an economic market.
• O’Ferrall J.A. held that, in calculating the economic viability, the costs of recompleting a well (e.g., drilling costs) in a different formation are NOT to be considered since those are for the account of the lessee. The calculation is to include costs of production and marketing but not capital costs.
• Are offsetting wells producing nearby in the same market? The court noted producing offsetting wells as evidence of the existence of a market a number of times.
• How should you document the factors resulting in a lack of market? What factors are affecting the lack of economic viability? Are you documenting them? What is your process for periodically assessing the market?

Lessor’s conduct

Depending on the circumstances, a lessor’s conduct, and what it may or may not have sent, may assist the lessee. Acceptance of royalty payments by a lessor will not in itself constitute “leave and licence” if a claim has been asserted, but it may do so prior to an objection, notice to vacate or claim being registered.

Recommendations when shutting in and recompleting

At the time of shut-in, review the specific lease habendum and shut-in language, identify whether nearby wells are producing, document the economic elements of the shut-in case, and thereafter schedule periodic re-assessments of the applicable economic conditions to ensure timely resumption of activities.

Given the capital at risk when recompleting a well that was shut in, it is prudent to obtain legal due diligence review of the applicable lease provisions, review the circumstances of and evidence relating to any shut-in well periods and, where recommended, seek a ratification or replacement of the original lease prior to expending capital.

Footnotes

1 Stewart Estate v 1088294 Alberta Ltd. [2015] A.J. No. 1227 (CA).

2 Freyburg v Fletcher Challenge Oil and Gas Inc. 2007 ABQB 353, 428 A.R. 102 (QB).