Now, I’ve at least got the name sorted. Turns out that “row fer” has nothing to do with Michael’s quest for milk and honey, or anybody’s mother. It’s all about rights of first refusal, or “ROFR’s” as folks in the business like to say.

Article XXIV of the 1990, 1981, and 1974 CAPL Operating Procedures, and article XXVI of the 1971 CAPL Operating Procedure, is entitled “Disposition of Interests” and election “B” at paragraph 2401 (paragraph 2601 in the 1971 CAPL) is the most common source of ROFR’s in the oil and gas industry. This article only focuses on this CAPL-type of ROFR. Non-CAPL agreements can also create ROFR’s, but they are non-standard and need to be analyzed individually.

There have been several good articles written about ROFR issues in the Canadian oil and gas industry. If you’re interested in digging into the topic, please see Perell (1991), Smith and Denstedt (1992), Flannigan (1997), Johnson and Stanford (1999), and Tarnowsky, Pittman, and Wilton (2007), as referenced below. There is also an article by Bryan Duguid and Gavin Matthews in The Negotiator, October 2008, that discusses a recent Alberta Court of Appeal decision in Canadian Natural Resources Ltd. v. EnCana Oil and Gas Partnership about how ROFR’s are triggered by farmouts in the 1990 CAPL operating procedure. However, there are four operational A&D issues about ROFR’s that I would like to focus on here that extend some of the discussions in those previous articles.

1. A&D ROFR Triggers, about when a ROFR should be issued in a non-farmout context, such as in acquisition and divestiture transactions;

2. Cherry Picking, about how to value multiple parcels that have been divided by segregation;

3. Underlying Agreements, about how to manage ROFR’s when two agreements on the same land have different ROFR requirements, and

4. ROFR’s to GOR Parties, about whether or not GOR parties are entitled to receive ROFR’s.

1. A&D ROFR Triggers.

In the leading case on this issue, Canadian Long Island Petroleum v. Irving Industries, [1975] 2 S.C.R. 715, the Supreme Court of Canada said that ROFR’s are usually triggered by receipt of an offer the vendor is prepared to accept. That would seem to be a pretty clear instruction. However, parties can draft ROFR clauses that set different triggers. So, in practice, it doesn’t seem to be as simple as Canadian Long Island Petroleum suggests.

Each of the CAPL style of ROFR-generating paragraphs starts off with the phrase, “a party shall not dispose of any of its working interest by assignment, sale, trade, lease, sublease, farmout or otherwise, without first complying with the provisions…” of the operating procedure. This is a bit troublesome because there is ambiguity about what part of the disposition process is the trigger to set things in motion. As discussed by Duguid and Matthews (2008), the Alberta Court of Appeal decision in Canadian Natural Resources Ltd. v. EnCana Oil and Gas Partnership looked at disposition by farmout. CNRL argued that the ROFR was triggered when EnCana intended to farmout its working interest. EnCana said no, the ROFR wasn’t triggered until earning was immanent. The Court of Appeal found both arguments reasonable and recently turned the case back to the Court of Queen’s Bench to trial on the issues, including evidence on industry practice. The courts may find industry consensus elusive. The outcome will be interesting to follow.

The A&D side of the business operates a bit differently than farmouts. So, the CNRL v. EnCana case may not apply directly. However, the A&D process shares the ambiguity about interpreting when a disposition has taken place. Remember, paragraph 2401 says that a party “shall not dispose… without first complying the provisions…” of either alternate A or B. The issue is the requirement to “first comply.” If it just said that ROFR’s should be issued after disposing, there would be little controversy. In A&D, a ROFR would go out after the purchase and sale agreement (PSA) was executed. Unfortunately, that’s not what it says. It says, “first compiling.” So, the plain meaning seems to be that sometime before the disposition, the vendor must comply with the expectations of the ROFR paragraph. This seems to place the timing of the ROFR triggering event in the murky waters of uncertainty that precede disposition. There’s the rub. A&D teams to respond in two distinct ways. Some see the trigger as signing a letter of intent (LOI). Others see the trigger as execution of the PSA.

1. Letter of Intent.

This approach recognizes the trigger as execution of the LOI. It seems reasonable. Signing the LOI morally commits the parties to follow through with a disposition transaction and provides authorization and guidance to the company’s administrative and technical teams. Depending on how it’s written, it may create a beneficial right where the vendor becomes obligated to hold the transaction lands and rights in trust for the purchaser. ROFR’s are then issued even though the exact terms of the PSA haven’t been worked out yet. All the key information is available: purchaser’s name, price, effective date, land description, etc.

This approach seems to fit with the Supreme Court of Canada’s view in Canadian Long Island Petroleum because the ROFR is issued soon after the vendor receives an offer it is prepared to accept. It also fits nicely with the expectation in the ROFR clause to issue the ROFR before disposition because an LOI probably isn’t a binding contract.

Formation of a contract must proceed through offer, acceptance, and consideration. An LOI that is subject to senior management approval may be a conditional acceptance and not binding. One that is not accompanied by a deposit may lack consideration. Other forms of consideration are possible. A simple one is to sign under seal. But, as a general rule LOI’s are not signed under seal. Also, an LOI may be only an agreement to agree—which is no agreement at all. So, if a vendor went ahead and disposed of the transaction lands to a different party, or refused to follow through with the deal, it would be difficult for the purchaser to rely on contract law to successfully sue on the strength of most LOI’s. It would be equally difficult for a vendor to sue a purchaser who backed out. There may be equitable solutions, but it still stands that interpreting an LOI as a disposition is a bit premature. So, either because you are comfortable following the guidance of the Supreme Court of Canada or because you like fitting with the terms of the ROFR clause, it’s probable that issuing a ROFR on the strength of an LOI is a good tactical choice.

Many A&D transactions also proceed on the strength of an LOI because it offers administrative and operational advantages. First of all, the parties can get going with title review, resolution of defects and deficiencies, and issuance of ROFR’s in parallel with negotiation of the finer nuances of the PSA. It takes a lot of pressure off the team drafting the PSA. The land, well, facilities, and other schedules attached to the final PSA, end up being reliable records of the transaction. This is because the PSA isn’t finalized until all ROFR exercise activity has been netted out. That is to say, the final schedules show the lands, wells, and facilities that really form part of the final deal after all the dust has settled from lands being taken out by parties exercising ROFR’s. This avoids the need for the PSA to be amended after ROFR’s are exercised. It makes it much easier for administrators of both the vendor and purchaser to accurately update their corporate records because it’s one-stop shopping. They don’t have to chase after elusive amendments, or have to deduce the net lands in the deal by tracking down all the ROFR responses on their own.

2. Sale Agreement.

This approach recognizes the trigger as execution of the purchase and sale agreement. This is typically accompanied by payment of a deposit, or is signed under seal, and legally commits the parties to follow through with the transaction because a contract has been formed. If either party backed out, the other could sue. Most would agree that execution of a PSA is a disposition of interest. Companies following this approach only issue ROFR’s after the PSA is executed and a copy of the PSA is usually included with the ROFR letter.

A key weakness of this approach is that it doesn’t really fit with either the Supreme Court of Canada in Canadian Long Island Petroleum or the plain meaning of paragraph 2401. The ROFR isn’t being issued when the vendor receives an offer it’s prepared to accept, and it’s not being issued before the disposition takes place. Nonetheless, it’s a common industry practice and there are few objections to it.

There are also administrative and operational challenges with this approach that include the need to amend the schedules after ROFR’s have been exercised. The most up-to-date amendments may not circulate to all stakeholders. Sometimes, administrators are left on their own to compile ROFR responses and net out the lands in the transaction. The result can lead to confusion and data integrity issues as administrators rely on incomplete ROFR compilations, and outdated, or inaccurate schedules.

Anecdotally, the LOI approach dominated the industry in the 1990’s. Only after brokers became increasingly involved did the sale agreement approach begin to predominate. This outcome may be associated with the linkage between execution of the sale agreement and payment of the broker’s fee. Proceeding under an LOI postpones execution of the sale agreement and delays fee payment.

2. Cherry Picking.

Article XIII of the 1990, 1981, and 1974 CAPL Operating Procedures, and article XV of the 1971 CAPL Operating Procedure, is entitled “Operation of Lands Segregated from Joint Lands.” It’s generally known as the segregation clause and it says that when any portion of lands subject to the operating procedure are no longer owned in the same percentages of interest, then the lands become governed under separate operating procedures with identical terms, except as to the working interests. The lands will still share the same head agreement and when analysts find one file and one agreement they are tempted to issue a single ROFR. But, there’s some confusion because the industry actually uses two ROFR alternatives where segregation applies.

1. All-or-Nothing.

The ROFR letter is issued under the head agreement listing all lands that are being disposed in one large parcel with a single valuation for the entire parcel. ROFR recipients are then challenged to either exercise their right of first refusal on the whole package, or waive their rights to the whole package in a take-it-or-leave-it fashion.

2. Cherry Picking.

The ROFR letter is issued with an attached schedule of distinctly valued land parcels. ROFR recipients are invited to exercise their rights in respect to any combination of parcels in which they have a working interest. Essentially, the can pick and choose the “cherries” they want from the deal.

To figure out which approach is correct it’s important to understand how the CAPL segregation clause operates. An illustration may be helpful. Consider head agreement “A” shown below. It’s not subject to segregation. It has one head agreement and a single operating procedure schedule attached to it. In comparison, head agreement “B” is segregated. It has multiple little operating procedure clones attached to it. The tricky bit is that on the physical file you’ll only ever see a single operating procedure as you see for “A”. The multiple operating procedures with “B” are legally real, but are file phantoms—invisible to the eye. Only by analysis can we detect the existence of the “B” structure. On land systems, the existence of “subs” or “splits” (sometimes called “equities”) usually highlight the existence of these phantom operating procedures, although there are also other reasons why land system “subs” may exist, so this isn’t a hard-and-fast rule to follow.

Still, the point to take away, is that for CAPL operating procedures both the segregation clause and the ROFR clause are found in the same document and they operate together. If a parcel of land is segregated, then it must be treated as if it was being operated under a different operating procedure than other parcels of land in the same head agreement. It follows, that if there are different operating procedures, then there are also different ROFR’s for each parcel. Each parcel must be valued separately and partners may independently elect on each parcel. Cherry picking is nothing more than proper application of segregation. So, cherry picking is cool. All-or-nothing fails to apply segregation. So, all-or-nothing is bad.

3. Underlying Agreements.

A client recently asked me to help them work through a situation where the company had an active Joint Operating Agreement (JOA) and an active Non Cross-conveyed Pooling Agreement (NCCP) concerning the same land and rights. The NCCP had language that said it superseded the JOA as to the pooled zone. The JOA had a ROFR using 1981 CAPL 2401B, but there was no ROFR on the NCCP. The client noted that they had already seen this handled two different ways and they wanted my recommendation about which approach to follow. As the client put it, the two alternative approaches were to:

1. sever the underling working interest from the pooled interest by scheduling the WI with a footnote that the interest excludes the pooled interest; or

2. schedule the WI with a footnote that the lands were subsequently pooled and that the pooled interest will follow with the working interest.

Canadian court rulings in connection with ROFR’s are relatively sparse. In 1982, the BC Supreme Court in the Lomac Holdings case (1982), 38 B.C.L.R. 238 (S.C.), said that ROFR’s should be interpreted, “in a large and fair sense so as to give effect to the manifest intention of the parties at the time of contracting.” This case has been somewhat influential outside BC, possibly because it was written by Justice Beverley McLachlin who is currently Chief Justice of the Supreme Court of Canada. Despite some recent cases that may restrict this interpretation a bit, the case suggests that the best rule is to comply with the terms of a ROFR to the fullest extent reasonable.

In 1994, the Alberta Court of Appeal in Mesa Operating Ltd. v. Amoco Canada Resources Ltd., (1994), 149 A. R. 187, looked at ROFR’s and said that, “a party cannot exer¬cise a power granted in a contract in a way that ‘substantially nullifies the contractual objectives or causes significant harm to the other contrary to the original purposes or expectations of the parties.’” It also said that the, “assessment of those expectations should include regard to the commercial context.” So, the reasonable expectations of the parties should be given effect in the commercial context of their agreement. The bottom line appears to be that party conduct must not substantially nullify a ROFR.

Going back to the client’s question, at the time the parties entered into the pooling they knew, or ought to have known, about the underlying JOA. It’s at this point in the contracting process that legal guidance from court decisions needs to be applied. It’s reasonable to expect that the JOA parties bargained for a ROFR with a reasonable expectation that it would have value. So, when the pooling was drafted it had to be done in a way that did not nullify that original contractual ROFR objective or expectation.

The client’s first alternative severs the working interest from the pooled interest. This is a difficult interpretation to operationalize. It means that after exercising the ROFR, a party to the underlying JOA could have an interest in the land, but no right to the revenues from it because the revenue arises through production governed by the pooling. This leaves the ROFR with only the residual value that may remain in the land after the pooling terminates. It’s an outcome that tends to nullify the ROFR by extinguishing its value.

The client’s second alternative avoids severance. It follows the inference that the pooling was drafted with the intention to operationalize the underlying ROFR in a way that maintains the value of its interest in the land. This is probably the best fit with the court’s guidance and makes the second alternative the preferred one to apply.

Johnson and Stanford (1999) briefly addressed this topic. They agree that the ROFR in an underlying agreement like this JOA would persist despite the superseding language in the NCCP, unless all parties, including ROFR holders, agreed otherwise.

4. ROFR’s to GOR Parties.

There is still persistent uncertainty about whether or not parties holding a convertible gross overriding royalty interest in an agreement are entitled to receive a ROFR notice. Of course, the answer always depends on the exact language used in any particular agreement, but for ROFR’s that arise under one of the various CAPL operating procedures, the usual answer is, no. They’re not entitled.

The ROFR clause in a CAPL operating procedure says that the ROFR must be issued to parties to the agreement. The procedure defines a party as, “a person, corporation, partnership… bound by this Operating Procedure.” A convertible GOR interest does not arise because of language in a CAPL operating procedure. Usually, language in the head agreement, or other schedules, creates it. So, prior to exercising the conversion option, the holder of a convertible GOR is not bound by the operating procedure and is not entitled to any of its benefits or obligations, including ROFR’s. Even if they did receive a notice and wanted to exercise, the CAPL ROFR provision only lets them exercise in proportion to their working interest. Working interest is defined as their percentage of undivided interest in a production facility, joint lands, or respective zones. So, because a GOR party holds no working interest their proportion of the interest offered in the ROFR would be zero.

However, there seems to be some inclination to focus on the idea that a convertible GOR includes an option, at payout, on a future right to a working interest. There is a willingness to contort the operative language of the various CAPL operating procedures and imagine that a convertible GOR party should be able to exercise on the ROFR as if they had already exercised their payout option to surrender their GOR interest and take a working interest. We see evidence of this thinking at paragraph 12.02 of the 1997 CAPL Farmout and Royalty Procedure. It says that if certain elections have been made, then a 2401B ROFR will be applied, “as if the Royalty Owner had elected to convert its Overriding Royalty to a Working Interest in that portion of the Royalty Lands immediately prior to the issuance of any required disposition notice.” There is case law such as Calcrude Oils Limited v. Langiven Resources, (2004), 349 A.R. 353 (Q.B.), and DeBeers Canada Inc. v. Shore Gold Inc. (2006), 285 Sask. R. 152 (C.A.), where courts have said that one of the reasons that ROFR’s exist is partly to allow working interest partners to manage who their partners will be. So, here we would have an operational need being extended to parties that are not participating in operations. Wild stuff. Nonetheless, this outcome does occur within the limited scope of elections in the 1997 CAPL Farmout and Royalty Procedure. If it was generally true—if this was the common way to apply ROFR’s—I believe the 1997 CAPL Farmout and Royalty Procedure wouldn’t need to go out of its way to construct it.

Without the authority of the 1997 CAPL Farmout and Royalty Procedure, or a similar agreement, there is no support for an interpretation that extends ROFR’s to convertible GOR parties. It would be risky to offer a ROFR to them by pretending that they had converted. It would deprive other working interest parties of their full entitlement and the ROFR issuer would be exposed to liability.

Summary
In summary, for A&D transactions, it’s probably best practice to issue ROFR’s at the letter of intent stage. However, issuing ROFR’s after execution of the purchase and sale agreement is probably okay. It has become a common industry practice, but it creates administrative, and data integrity challenges. Cherry picking is allowed by segregation. Underlying agreements persist despite the superseding language of later agreements, unless all parties, including ROFR holders, agreed otherwise. GOR parties are not entitled to ROFR’s unless the language of the agreement specifically says so.

ROFR’s are a complex restriction on disposition and this article has only highlighted four operational A&D issues. Those interested in more information on the topic may consult the reference articles. However, as companies quest for their own milk and honey in the oil patch it’s recommended that legal counsel be directly involved in the development and management of policies about the application of ROFR’s and ROFR processes.

REFERENCES

Duguid, B., Matthews, G., 2008. “Key Right of First Refusal Provision ‘Ambiguous’.” The Canadian Association of Petroleum Landmen. The Negotiator, October 2008.

Flannigan, R., 1997. “The Legal Construction of Rights of First Refusal.” (1997) 76 Can. Bar Rev. 1.

Johnson, C. D.; Stanford D. J., 1999. “Rights of First Refusal in Oil and Gas Transaction: A Progressive Analysis. 37 Alta. L. Rev. 316, 1999.

Perell, P. M., 1991. “Options, Rights of Repurchase and Rights of First Refusal as Contracts and as Interests in Land.” (1991) 70 Can. Bar Rev. 1.

Smith K. T.; Denstedt S. H. T., 1992. “Preemptive Rights and the Sale of Resource Properties: Practical Problems and Solutions.” 30 Alta. L. Rev. 57, 1992.

Tarnowsky, G. L.; Pittman, M. F.; Wilton, C., 2007. “Restrictions on Disposition in the Oil and Gas Industry: The Extinction of the Species?” 44 Alta. L. Rev. 477, 2006-2007.

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Trust law developed in England during the Crusades. When knights went charging off to the Middle East they had to leave a friend in charge of any land that they held in order to pay and receive feudal dues. Before the development of trust law, the only way this could be done was for the crusading knight to convey ownership of their land to a friend on the understanding that it would be conveyed back when the knight returned. Of course, all too often the friend was rather surprised that the knight didn’t die on the journey or the battlefield and actually came home. Many trusted friends weren’t pleased by this turn of events and refused to give the land back. The knight had no recourse except to appeal to the king. The king would set things right if he felt like it, but sometimes he was just as happy to let the knight rust in the rain alone and landless. Eventually, this kind of case was became so frequent that the king didn’t have time for it anymore and he delegated the job to the Lord Chancellor by empowering him to do what was just and equitable on a case-by-case basis. Eventually, it became common for the Lord Chancellor to recognize the claims of all returning crusaders. This gave rise to the law of equity as the concept developed that the legal owner, the friend, would hold the land for the benefit of the original owner, the crusading knight, and would be compelled to convey it back when requested. The crusading knight was the beneficiary and the friend the trustee. The term use of land was coined, and in time developed into what we now know as a trust.

From this history we can see that land interests are made up of two components: the legal interest and beneficial, or equitable, interest. When the legal owner is also using and occupying the land, or benefiting from it, these two interests are bundled together. But, they can be taken apart and held separately. For example, in the oil and gas industry, one company can hold the legal interest and another company, or group of companies, can hold the beneficial interest. When this separation occurs a trust exists. It doesn’t even need to be documented. It can come into existence merely through the conduct of the parties. These are known as implied trusts. However, for certainty and to have the best evidence possible about the nature of the trust it’s best to have a contract known as a trust agreement. This is as an express trust. It sets out how the holder of the legal interest, the trustee, will manage the legal interest on behalf of the holder(s) of the beneficial interest, the beneficiaries. The trustee owes a fiduciary duty to the beneficiaries of the very highest order. A court will view a breach of trust as the most grievous kind of contractual breach and the trustee usually faces significant liability.

Curiously, in the oil and gas industry, original trust agreements are often found on mineral files and are not setup in the land system as contracts. This is a risky policy. Like any other contract, trust agreements need to be setup in the system and given their own files to make them trackable and to ensure they are administered properly. Some companies may find it convenient to place a photocopy of a trust agreement on the related mineral file(s), but the original should have its own contract file.

Trust agreements are assignable. Application of the 1993 CAPL Assignment Procedure follows the same rules as for any other kind of contract. When land is being conveyed it can save a lot of time and resources. Unfortunately, the terms of many trust agreements don’t include the assignment procedure. However, companies that want to minimize administrative costs are careful to draft them so they do include the assignment procedure. If all parties agree, it’s also possible to amend existing trust agreements to include the assignment procedure.

Leaving trust agreements out of the contract system creates a nasty administrative challenge for conveyancing because trust agreements that are buried on mineral files are often overlooked. The resulting tangle of express and implied trusts is a legal swamp with major liability risks. So, whenever a trust agreement is found on a mineral file an administrator can add value by pulling it out and setting it up in the land system as a separate contract that is related to the mineral. Of course, analysis is needed to decide whether or not the trust is active. Active trust agreements should be added to the land system as soon as possible. Inactive ones may not have the same urgency, but it can still be helpful for them to be trackable in the land system to support any research or query that needs to find it.

There is also another kind of trust instrument on industry land files—the trust declaration, also known as the declaration of trust. This instrument is a document that is only signed by the trustee. It acknowledges that land interests are being held on behalf of a beneficiary, or beneficiaries, but is not signed by the beneficiary. As an easy rule-of-thumb, no matter what the title on the instrument—whether it’s called a Trust Agreement, Trust Declaration, or Declaration of Trust—if the instrument is only signed by one party, it’s a trust declaration or declaration of trust. In contrast, a trust agreement is signed by both the trustee and the beneficiary.

Companies often execute a declaration just to have it on related mineral files as a physical flag warning administrators that a trust exists. This may serve to document an implied trust that is created by a participation, farmout, pooling, or other kind of contract. Again, best practice is to set up declarations as contracts. It makes them trackable. However, the big difference between a declaration and a trust agreement is that the declaration is not assignable. The 1993 CAPL Assignment Procedure cannot be used. Instead, when conveying land that is subject to a declaration, the assignee that is the new trustee needs to execute its own declaration. Again, if this is overlooked, the trustee company is doing a swan dive into a legal swamp.

Trusts are a complex type of agreement and this article has only highlighted a few key points. It’s recommended that the preparation of a trust agreement or declaration of trust be referred to legal counsel.

There are several things to keep in mind when dealing with confidentiality agreements. The first is that the party providing the information and the party receiving it have very different agendas. The provider will want an agreement that sets out specific safeguards to keep the shared information in confidence and will want to make its scope as broad as possible. In contrast, the information receiver wants a very specific definition of what is to be held in confidence to remove uncertainty about how to manage the expectations of confidentiality. The next concern is that the information provider must be aware of the interests of its existing business associates because it may have pre-existing contractual obligations that restrict its right to release sensitive information for review by interested parties. It’s important to be sure that information disclosure does not breach existing obligations. Fortunately, the 1990 and 2007 CAPL operating procedures include exceptions that allow release of information to third parties for several reasons including acquisitions and divestitures. But, be careful because the earlier CAPL operating procedures don’t have this kind of provision. If there is concern, negotiation with business associates to permit disclosure is usually successful because each one will probably need the same favour one day.

A confidentiality agreement will usually say that everything being shared by the information provider is confidential, except what is already public. It’s also important to be sure that it reaches back and covers information disclosed before the agreement is signed. However, it usually exception information that goes public without fault of the receiver, or through a third party, and it doesn’t restrict information the receiver already had before disclosure.

If there’s ever any dispute about whether or not an exception applies the agreement must be clear about who shoulders the burden of proof. The provider will have trouble showing how the receiver actually obtained the information because it lacks inside information. So, it’s usually fair for the agreement to expect the receiver to show how an exception applies.

Be careful that a confidentiality agreement doesn’t inadvertently setup a trust by including language that says the receiver is holding the information, or any benefits arising from its improper use, on behalf of or in trust for the provider. This could make the receiver a fiduciary of the provider. The agreement should also say that information will only be disclosed to those representatives of the receiver on a need-to-know basis and that these people will be told that the information is confidential and cannot be disclosed to others. It’s a good idea to require representatives to provide a confidentially undertaking to the information provider agreeing to be bound by the terms of the confidentiality agreement. In any event, the receiver should be prepared to indemnify the provider against improper use or disclosure of the information.

Another idea to keep in mind is that it’s often useful to have the agreement prevent disclosure of the fact that the information itself has been shared. The provider must consent to any proposal for joint bids to be made by the receiver with any other party. Otherwise, the mere knowledge that the information has been shared can provide an undesired market signal.

A confidentiality agreement will generally provide that the confidential information is to be used solely for the purpose of evaluating a possible transaction involving the information provider and the receiver. It should block any other kind of use, although it needs to allow disclosure so the receiver can defend itself in legal proceedings. The provider may even want to have the agreement give it the right to become party to any action requiring disclosure and to allow it to defend the action. Otherwise, the provider is at the mercy of the receiver’s decision about whether or not to defend against a claim.

The information provider won’t usually make any promises about what it will disclose. This is best left at the provider’s discretion. If promises are made then the details about what information is to be shared and timelines for delivery need to be established. The provider should also avoid making any representation or warranty about the accuracy or completeness of the information and use of the information by the receiver should not create provider liability. Meanwhile, the receiver should make sure that this disclaimer is subject to the terms of any later agreement relating to the information such as a purchase and sale agreement

The agreement should say that the receiver will return all information provided to it if the deal doesn’t go through. However, there may be an issue about how to handle interpretative reports and data and other material that the receiver generates with the information it receives. The receiver will probably not want to return this material. The best solution is probably to have the receiver agree to destroy everything except information that has been presented to the receiver’s directors and now forms part of the minutes of director’s meetings because this forms part of the corporate record.

Survival of terms is something else to think about. Often, confidentiality agreements have a fuse that makes them expire at a specified date or when a certain kind of even occurs. For example, if the agreement relates an acquisition transaction the obligations usually terminate on closing. However, if there is no transaction, the survival period may be for a year, or so. If the confidentiality agreement is about reserves and production, then duration is not as important because everything will soon become public. Unless it’s a partial sale of interest, the provider is not concerned about disclosure after closing because it has divested its interest. The concern usually rests with the receiver because unsuccessful rivals will be entitled to use and disclose the information after the survival period expires.

It’s helpful to include language that says the information provider has the right to get an injunction if the confidential information is disclosed in breach of the agreement. It clearly tells the court that the provider believes unauthorized disclosure is very serious and that it believes this is a case where the special relief of injunction is appropriate.

Perhaps the most challenging part of a confidentiality agreement is the expectation that the information receiver agree to an area of exclusion. This can apply even though the receiver didn’t use the confidential information improperly to acquire interest within the area of exclusion. It’s hard for a provider to prove that a receiver used confidential information improperly. However, it’s still a good idea for a receiver to negotiate an exception to the area of exclusion for cases where it can show that it didn’t use any confidential information in getting the interest. An area of exclusion also needs to say how the cash value of non-cash deals will be determined; deal with agreements, like farmouts, that restrict assignments; and create an exception for situations where newly acquired interests are a minor part of a much larger acquisition by the receiver.

This is a complex type of agreement to draft and this article has only highlighted a few key points. It’s recommended that the preparation of a confidentiality agreement be referred to legal counsel.

You didn’t hire a lawyer or land professional to help you with this deal. It was too simple. It didn’t involve many assets and you trust your vendor. At closing you moved through the agenda yourself and carefully ticked off each document as it was presented. You received the purchase and sale agreement, general conveyance, statement of adjustments, officer’s certificates, and you delivered the cheque. But, with most transactions you also received ancillary documents such as: notices of assignment, assignment and novation agreements, licence transfers, regulatory transfers, mineral assignments and transfers, surface agreement assignments, directions to pay, changes of operator, and possibly title transfers. You also received piles of files, although they were probably delivered a few days after closing and are in separate boxes under the table.

You bought these assets for a reason. You may simply want the production. You have a drilling program. Whatever you have in mind, these assets urgently need the ancillary documents processed. If they sit unattended, you risk title entanglements that may compromise your partner relationships, limit access to information, and place cash flows into confusion and controversy that may take years to resolve.

For example, your standing as a joint partner in an operating agreement will not be recognized until the first day of the second month after the notice of assignment is received by the current joint partners. The longer service is delayed, the longer you remain in trust behind the vendor. All your communications with current joint partners will have to be handled through the vendor. Your newly acquired cash flow will continue to be handled through the vendor. ROFR’s will only come to you through the vendor—and if you want to exercise you’ll have to instruct the vendor to do so on your behalf. You will not be recognized as a well operator until the license is transferred. The Crown will not deal with you on the Crown rights you acquired until you file the mineral transfer that identifies you as the new designated representative. Meanwhile, other joint partners may be assigning their interests and you will be out of the loop—dependent on your vendor to pass information to you. As your ancillary documents become stale, the process of ongoing assignments and transfers may create the need for many, or all, of your ancillary documents to be re-drafted and re-executed. As long as you remain a trust party behind the vendor, there is risk that time sensitive opportunities and cash flows may reach you too late.

Don’t let the box blow. The deal isn’t done until all the ancillary documents are processed and all the files are indexed and logged in your administrative systems. Most of the documents can be professionally processed by land administrators and joint venture analysts. Hire one. They’ll scope out the complexity of the work and let you know if you’ll need other administration professionals or the assistance of a lawyer.

The first instruction asked for the preparation of a schedule for these lousy, non-performing wells that cross-referenced lands and agreements. Okay. The first well is a shut-in oil well. It appears to have been shut-in since 1975 and the company appears to be its operator. Obviously, it’s a terrible performer. It sits on the southwest quarter of a full section Crown lease that was issued in 1975. Curious. This lease is well past its primary term. It’s continuing indefinitely under Section 15. A very old, shut-in, non-producing well might not be holding this lease. A land analyst will suspect that there are other wells on the land and, yes, there are three producing oil wells. All four wells are tied in to a nearby battery. So, to implement the pooh-bah’s scheme we will have to schedule the SW/4 of this Crown lease for sale and relate the shut-in well to it. Weird. Who would want to buy 1 of 4 wells that are tied into a common battery? How will this work? What are we really trying to sell? Where’s the value?

Oh, we also have to consider whether there’s an operating agreement governing this land; and, not surprisingly, we find that there is one. It’s a joint operating agreement (JOA) from 1975. The company is in it with 4 partners and the JOA includes the 1974 CAPL operating procedure with Clause 2401(b). This means it has a 20-day right of first refusal (ROFR). So, after finding a potential buyer for this property, the company will need to issue the ROFR to its partners. To find that buyer, the company will need to market the opportunity to pick-up just a wellbore or pickup a portion of the Crown lease with a shut-in oil well that cannot be produced with existing infrastructure. Oh, the company also has no certainty that it will be able to transfer operatorship of the well and lands to the buyer. That will depend on how the partners respond to the notice of change of operator that the company will need to issue. Of course, once the lease portion is carved out of the original lease and standing on its own with only a shut-in oil well to support it, the Crown will notice the lack of production and can be expected to issue a Section 18 notice that will give the buyer one year to produce from the land or lose the lease and be left holding abandonment liability for the well. Hot deal—maybe not.

My colleague and I looked at the plan in more detail. We noticed that the pooh-bahs had apparently organized the wells into sale packages based on annual cash flow. Yikes. Here was a list that saw “packages” with wells that were hundreds of miles apart—even in different provinces—all lumped together just because they all had similar annual cash flow. So, you could buy the Alberta shut-in oil well I was just talking about along with a similar one near Estevan, Saskatchewan. My colleague then said that the pooh-bahs forbid the sale of any pipe that was connected to wells being kept. So, we could be left trying to sell half a pipeline—just the end connected to our poor producing well. How do we do that? This was just going from bad to worse.

Surprising as it may seem, the acquisition and divestiture design process does not revolve around wells alone—with the exception of wellbore-only transactions. The assets being traded in oil and gas A&D include a comprehensive package of lands, agreements, and infrastructure—not just wells. From an A&D closing perspective, the wells just go along for the ride as the land title, rights, and agreements are transferred. Except for wellbore-only deals, a well-centric divestiture scheme is probably a bust from the get-go. Wells and production data are certainly critical in driving the economics of a deal. But, to let the sale of low revenue wells drive the structure of a transaction is to let the tail wag the dog. It is fraught with legal and tactical problems, logistical tangles, high transaction costs, and in many cases simply cannot be done. The design of an effective divestiture plan that optimizes value for poor performing wells will need to be built around coherent packages that receive input not only from accounting, but also land, operations, and marketing.

ROFR management is an issue because of unfortunate language used in all of the CAPL operating procedures. The darn things say that ROFR’s are triggered when a party “wishes” or is “wishing” to dispose of its interest, but it doesn’t define when wishes or wishing occurs or what triggers wishing. It’s a sloppy word with ambiguous meaning. If it said “want” it would be clearer because wanting suggests a definite intention to do something and can be measured by overt acts. If it said nothing it would also be better because then it would say, a party “disposing” of its interest, and that too is a measurable act. But, they all say “wishes” or “wishing” and that could mean anything from the moment a landman or evaluations engineer gets a twinkle in their eye, or the letter of intent gets signed, or the sale agreement is signed, or when the deal actually closes. Nobody really knows. But, few people remember this language is in the CAPL procedure. It’s a lost gem. All that most want to know whether the election blank is filled in with an “A” or a “B” because “A” invokes the consent paragraph and “B” invokes the ROFR one. That’s the gold nugget. So, they flip through a contract until they find the right page and quickly glance for the “A” or “B”.

An unfortunate implication of the “wishing” language is that the industry is all over the map when it comes to timing when consents and ROFR’s are issued. Some will do it when the letter of intent is signed. Others wait for execution of the sale agreement. A letter of intent is probably a clear signal that a company is wishing to divest. Therefore, issuing consents and ROFR’s at this stage appears to comply most closely with the expectation described by the operating procedure. Waiting for execution of the sale agreement stretches the ordinary meaning of wishing. It may be common practice and may not generally attract objections, but it is still wise to remember that the actual language of the procedure uses “wishing” to trigger the consent and ROFR obligation. To minimize risk it is probably best to issue consents and ROFR’s at the letter of intent stage. So, the value in this pile of information isn’t only the golden nugget of the “A” or “B” election. There’s a gem of information in remembering about the wish.

Freehold leases provide another example. I was leading a land acquisition and divestiture team and an A&D analyst brought 16 freehold leases to my attention. The analyst believed that the vendor’s land schedule showed these 16 leases with incorrect delay rentals because it showed that each individual one as being net $1280. This was about a family sharing fractional undivided mineral interests in a full section of land. The vendor’s information appeared to show an annual rental obligation of $20,480 for all 16 leases. Fortunately for the purchaser, the land analyst was correct. The gross rent for all 16 leases was $1280, not $20,480. This was just one example. The schedule was long and this problem showed up many times. The total rental error was over $250,000 and this is a large enough sum to impact land valuation. The missing information gem was in the innocuous and seldom noticed “Lesser Interest” clause in each freehold lease. It said,

If the Lessor’s interest in the leased substances is less than the entire and undivided fee simple estate, the royalties, rentals and suspended well payments herein provided shall be paid to the Lessor only in the proportion which such interest bears to the entire and undivided fee.

The math is simple. The $1280 rent has to be divided by the fractional mineral interest. So, the lessor holding a 10% undivided interest gets a rent of $128 even though page one of their lease quotes a rent of $1280. The schedule incorrectly listed the gross rent as the net rent because it was picking up the big bold number filled in above the blank line on page one of the lease and neglecting to apply the language of the skinny little “Lesser Interest” clause on page two. I’ve seen this kind of mistake before. People often forget that a there is usually a “lesser interest” clause somewhere in all freehold leases. A common example is found at Clause 5 of the C.A.P.L. 91 ALTA form of lease.

The bottom line is that quality A&D work needs professionals who maintain a breadth of knowledge that reaches beyond schedules, summaries, and abstracts. It needs people who take time to read and understand more about leases and contracts than is found by glancing at the filled-in blanks and election tick-boxes. Fortunately, in A&D work the industry is aided by land professionals and lawyers. Their input can minimize ROFR management risks. Their careful analysis of something as basic as mineral lease rents can impact valuation, reduce adjustments, and minimize post-closing maintenance costs.