There has been a great amount of merger and acquisition activity in the oil and gas industry in the last several years, particularly in the last 18 months. Most of the recent activity has been private M&A involving purchases of oil and gas properties, or private oil and gas companies. There have not been many takeovers of
publicly traded oil and gas entities in the last 12 months.
The most active acquirors have been royalty trusts. They usually place a higher value on producing oil and gas properties than do traditional exploration and production companies, because the rate of return a royalty trust requires on an investment is usually lower than that required by an exploration and production company. A royalty trust is essentially not taxable, because it usually distributes all of its income to its unitholders, reducing its taxable income to zero, or close to it. In addition, the rate of return a royalty trust requires is the yield required by its unitholders, which is usually less than the rate of return required by the shareholders of an exploration and production company. Moreover, the main purpose of a royalty trust is to distribute income to its unitholders, while the main goal of an exploration and production company is to find and develop oil and gas reserves. Royalty trusts do not undertake much exploration and development activity. Therefore, in order to survive, they must acquire oil and gas properties to replace production from their existing properties as they deplete. The fact that royalty trusts need to acquire oil and gas properties and place a higher value on them than do exploration and production companies has resulted in exploration and production companies seeking royalty trusts to purchase their producing properties and royalty trusts seeking producing properties to purchase.
One might assume that the almost exponential increase in crude oil prices has stimulated recent M&A activity, but in fact their impact has not been very significant. Generally, the industry views recent price spikes as a short-term phenomenon, and oil and gas properties are evaluated on the basis that in the longer-term prices will return to prices of between $27 and $35 a barrel. If there was not general agreement on this view, it would be difficult for vendors and purchasers to agree on pricing, because vendors would insist on pricing that reflects continued high commodity prices, while purchasers would be reluctant to purchase on that basis. The forward strip prices for crude oil demonstrate the industry view that current commodity prices are not expected to be sustained.
One result of the royalty trust acquisition activity is the purchase of private oil and gas companies when they have developed sufficient oil and gas properties to make them attractive to royalty trusts. Thus, a team of oil and gas managers will incorporate a company, acquire and develop some oil and gas properties and then sell the company when it has reached the point where the return to the promoters of the company is maximized. This is often achieved over a period of two or three years and is the intended business plan of the promoters when the company is first formed. It is not unusual for the management team to start a new company after the disposition with a view to selling it in two or three years. Sometimes, the management team retains a few undeveloped properties and their office lease and furnishings so they can start over again. It can be argued that, to some extent, the exploration and production end of the oil and gas business is being separated into two divisions: exploration and production companies, which find and develop oil and gas properties with a view to selling them to royalty trusts; and royalty trusts, which harvest the properties and distribute their revenues to their unitholders.
It remains to be seen whether the bifurcation of the industry suggested above will continue. Recently, some royalty trusts have withheld funds from distributions to their unitholders for purposes of undertaking some exploration and production activities. However, one by-product of this trend is that riskier prospects requiring more capital and a longer time to develop do not fit the plan and thus are less likely to be developed. Having regard to the maturity of the western Canadian sedimentary basin (i.e., not many significant discoveries left to be made), this phenomenon is not surprising.
Many oil and gas companies conduct operations through a partnership in order to achieve income tax deferrals. As a consequence, some recent sales of oil and gas properties have been structured as a sale of a partnership. This can create some issues with respect to adjustments on account of revenues and expenses associated with the oil and gas properties and income taxes. A partnership does not pay income taxes in Canada. Typically, its income is allocated to its partners on the last day of the partnership's fiscal year, based upon their partnership interests on that day. If partnership interests are sold during the fiscal year, then a mechanism will be necessary for ensuring that the vendor and the purchaser bear their appropriate shares of the income taxes attributable to the partnership's income for the fiscal year in which the sale occurs.
Depending on the circumstances, the partnership may have activities prior to the sale that are unrelated to the properties that are in the partnership at the time the sale occurs, which may complicate the tax adjustments. Conversely, the purchaser may undertake activities in the partnership after the sale and prior to the partnership year-end, which may make the tax allocation difficult. In either event, if the activities are unrelated to the oil and gas properties that are in the partnership when the sale occurs, the party who undertook the activities may be reluctant to disclose information about them to the other party. The purchaser will be unwilling to have any liabilities associated with property sales by the partnership to third parties before it buys the partnership, including income tax liabilities, post-closing adjustments and liabilities for representations and warranties. Typically, an adjustment is made on account of working capital when a partnership is sold, just as when the shares of a private company are sold. Where the partnership has disposed of properties to third parties prior to the sale of the partnership, the working capital adjustment can be tricky. In some cases, all of the partnership's working capital is transferred to the vendor immediately prior to the closing, and the purchase price is reduced by an amount equal to the net income from the oil and gas property that the purchaser is indirectly acquiring between the effective date of the sale and the closing date.
Rights of first refusal continue to be an issue in oil and gas dispositions. They are very common in the oil and gas industry. The most common issue relates to the situation where a right of first refusal applies to a portion of the properties being sold. Typically, the parties to the sale allocate a portion of the purchase price to the property that is subject to the right of first refusal and comply with the right of first refusal on the basis that such portion of the purchase price is the price the holder of the right of first refusal is required to pay if it wishes to exercise the right of first refusal. In many cases, the holder of a right of first refusal is sceptical that the allocation is fair or even bona fide. While it is not unusual for a holder of a right of first refusal to question the allocation, there have been very few instances where a holder has challenged the allocation by a lawsuit. This is probably because the likelihood of a successful legal challenge, combined with the benefit to be obtained thereby, does not justify the time and effort in pursuing a lawsuit. In turn, this has emboldened parties to sale agreements to be even more aggressive in their allocations.
There is one recent case,Calcrude Oils Ltd. et al. v. Langevin Resources et al., relating to rights of first refusal which is of some interest. The case involved a situation where a party acquired oil and gas properties, and a portion of the properties were acquired on behalf of other parties. The acquisition was subject to a right of first refusal, which was complied with, except that the participation of the other parties was not disclosed. Subsequently, the value of the property increased dramatically, and the holder of the right of first refusal learned of the interest of the other parties. The holder contended that the right of first refusal had not been properly complied with because the interests of the other parties had not been disclosed and that it was entitled to exercise the right of first refusal for the price paid in the original acquisition. The court held that the right of first refusal was not properly complied with, but awarded the holder nominal damages on the basis that since the holder could have acquired the property for the initial purchase price, it had not suffered any damages.
Many recent dispositions of oil and gas properties have been quite large. As a result, parties to sale agreements have been paying increased attention to provisions dealing with post closing liabilities, from which a number of trends have emerged. Because there are more buyers than sellers of oil and gas properties, sale agreements have become more vendor-friendly over the years. This is reflected in reductions in the representations and warranties which vendors are prepared to make and limitations on their liabilities for those representations and warranties. Frequently, a vendor will insist that it have no liability for any individual claim that is less than ade minimus amount, and no liability for its representations and warranties unless the aggregate amount of damages suffered by the purchaser exceeds a deductible or threshold amount. Sometimes this is expressed as an insurance-like deductible, whereby the purchaser is required to absorb the amount of its damages up to the deductible limit with no recourse against the vendor. On other occasions, this is expressed as a threshold, whereby the vendor has no liability unless the threshold is exceeded, but if it is exceeded, the vendor is liable for all of the damages and not just the amount that is in excess of the threshold. In the writer's experience, the deductible approach is more common than the threshold, but both are seen. In addition to the foregoing, a vendor will often insist that its liability be limited to a percentage of the purchase price. Historically, this percentage was usually 100%. However, recently vendors have been insisting on a lower amount, typically 25% or 50% of the purchase price.
Many recent dispositions have resulted from auctions whereby an exploration and production company chooses to dispose of non-strategic oil and gas properties. Usually, the vendor wishes to monetize the value of those properties. It is not unusual for the vendor to be able to significantly reduce its overhead costs in these transactions. For example, the properties being disposed of could represent only 20% of the value of all of the vendor's properties, while the overhead associated with them represents 60% of its overhead costs. This can result in termination of some of the vendor's employees. Also, the purchaser will often require some of the vendor's employees in order to manage and administer the oil and gas properties it is acquiring, particularly those that work in the field. The vendor may insist that the purchaser assume some severance obligations as part of the transaction. Naturally, this gives rise to employee issues in the sale agreement. Of particular note in this regard is recent provincial and federal privacy legislation that imposes obligations in regard to the disclosure of personal information. As a result of the privacy legislation, when the purchaser will have the right or obligation to make offers of employment to employees of the vendor, the sale agreement should contain provisions ensuring that the disclosure and use of information relating to the employees comply with the privacy legislation.
Purchasers are acutely aware that in an auction situation a vendor will prefer to sell all of the properties that are for sale in a single transaction. For this reason, it is becoming more common for purchasers to form a consortium so that the vendor can complete its disposition in one transaction. A recent example of this is the sale by Chevron Canada Ltd. of over $1 billion of oil and gas properties to the Enerplus and Acclaim royalty trusts. Enerplus acquired all of Chevron's interests in certain properties, and Acclaim acquired all of Chevron's interests in other properties. In a pre-arranged transaction, one of the purchasers flipped one property to another party. Nevertheless, Enerplus and Acclaim were joint purchasers. While the writer of this paper is not privy to the arrangements between Acclaim and Enerplus, it is understood that they entered into an agreement relating to their joint acquisition, whereby they agreed on how they would share the oil and gas properties being purchased and the liabilities associated therewith. Having regard to the complexity of the transaction, it must be assumed that the joint bidding agreement was complex and required difficult negotiations.
Usually, the vendor establishes a data room (usually through the facilities of a broker), and potential purchasers execute confidentiality agreements whereby they agree that the information disclosed to them in the data room will be kept confidential. Most confidentiality agreements will prohibit a potential purchaser from discussing a joint bid with another potential purchaser. If a joint bid is contemplated, the joint bidders may require a waiver of the confidentiality agreement to permit them to negotiate a joint bid. More often than not, this will be in the best interests of the vendor, but the vendor will wish to know the identity of the joint bidding groups.
It is becoming common in the auction process for a vendor to insist that its representations and warranties be qualified by matters contained in the data room it establishes to facilitate the sale process, so that it will have no liability pursuant to the representations and warranties in the sale agreement in respect of matters that are disclosed in the data room. However, it may not be easy to ascertain after closing what material was contained in the data room. As well, information in the data room is often supplemented or updated during the course of the auction process. In some recent transactions, the parties have dealt with the concern over the content of the data room by scanning its contents onto a compact disc and defining the data room as being the contents of that CD, a copy of which is kept by both parties and their legal counsel.
Another issue that has attracted a little more attention in recent transactions is the handling of seismic data. There are two types of seismic data: proprietary data, which is owned by the vendor, with rights to sell or license it; and trade data, which the vendor licenses from a seismic broker and which is subject to limitations on its disclosure to third parties. More and more, vendors are prone to retain their proprietary seismic and merely grant a licence thereof to the purchaser for licensing fee. As well, parties are recognizing the necessity of allocating a portion of the purchase price to the seismic data that is included in the transaction. This is because the purchase price paid by the purchaser for the seismic data or licence thereof is added to the purchaser's cumulative Canadian exploration expense tax pool and the proceeds of the sale or licensing are deducted from the vendor's cumulative Canadian exploration expense tax pool. Since 100% of the positive balance in such pool is deductible against any kind of income, and the negative balance in such pool must be included in income and is fully taxable, the allocation of the purchase price or licence fee to seismic data can have significant income tax consequences.
Trade seismic data is not transferable without payment of a seismic fee, and for several years trade seismic data has been excluded from most oil and gas property sales. Typically, the transfer fee is also payable in the event of a change of control of the licensee. The transfer fees can amount to millions of dollars, and thus, when control of any entity is acquired, there may be transfer fees payable that result in significant cost of the transaction that was not anticipated by the purchaser. In most cases, seismic brokers are prepared to consider some reduction in the fee, and in fact the fee is often described as being "up to" a specified amount, suggesting the willingness of the broker to consider a reduction. The reason that brokers may be willing to consider a reduction is that they wish to obtain more business from the acquiring entity. In some cases, the transfer fee is not payable if the party acquiring control is not itself engaged in oil and gas exploration and production business in western Canada. In each case, the specific seismic data licensing agreement must be reviewed to determine its implications on the transaction.
Environmental issues continue to be a concern in private oil and gas M&A transaction. However, as has been the case for the last ten or 15 years, the purchaser almost always assumes all environmental liabilities associated with the properties, past, present and future. Its only protection comes from its own due diligence and a very weak representation and warranty, typically stating only that the vendor has not received notice of any violation of environmental laws that has not been rectified. Vendors prefer that the purchaser conclude its environmental due diligence before the sale agreement is executed, in order to avoid either risk of the transaction collapsing or risk of the purchaser seeking a price adjustment. Of course, there is frequently not sufficient time to complete meaningful environmental due diligence before the sale agreement is signed. When a transaction closes in the winter, it may not be possible to complete due diligence prior to closing because of snow and frozen ground. In those cases, the sale agreement will sometimes permit the purchaser to undertake post-closing environmental due diligence, which entitles the purchaser to a purchase price adjustment if environmental problems are discovered. When such provisions are utilized, great care is taken in drafting the description of an environmental defect that entitles the purchaser to a price adjustment. There is often ade minimus and/or deductible amount that the purchaser must eat without any price adjustment.
Most private oil and gas M&A sale agreements provide for due diligence by the purchaser on title to the oil and gas properties that are the subject of the transaction. The conventional structure is that the purchaser is not entitled to any adjustment to the purchaser price on account of title defects, except to the extent that their impact on the value of the oil and gas properties exceeds a deductible amount, usually between 1% and 5% of the purchase price. If the impact on the value is greater than a threshold, usually between 10% and 20 % of the purchase price, either the vendor or the purchaser may terminate the transaction. These provisions seldom result in any reduction in the purchase price or in termination of the sale agreement. Significant title issues are not frequently encountered.
There has been increased interest in coal bed methane development in Alberta recently. As a result, many private M&A transactions are focused on coal bed methane. Unfortunately, it has not yet been determined whether coal bed methane is owned by the coal rights owner or the natural gas rights owner. The Alberta government has declared that where it owns rights to coal and natural gas, dispositions that it makes of natural gas rights include the rights to coal bed methane, and dispositions that it makes of coal do not, subject to the caveat that the holder of a coal disposition has the right to produce natural gas to the extent necessary to exploit its coal rights. Not surprisingly, several freehold coal owners, including EnCana Corp., have taken the position that where they own the fee-simple title to coal, they own rights to coal bed methane. Therefore, when coal bed methane is an important part of an M&A transaction, the sale agreement should address whether the purchaser is entitled to raise the uncertainty over ownership of coal bed methane as a title defect.
The law relating to certified checks was recently changed, such that banks will no longer issue a certified check for an amount in excess of $25 million. As a result, it is common for the purchase price payable for oil and gas properties to be paid by wire transfer. This can cause some delays in completing closing while the parties wait for confirmation that the wire transfer has been received by the vendor. It can also create logistical problems when the purchase price is to be paid to several different parties. For example, when a portion of the purchase price is to be paid to a lender in repayment of a loan and it is a condition of the closing that the loan had been repaid, a chicken-and-egg situation can occur. Usually, a portion of the purchase price is to be used to repay the loan; however, the purchase price cannot be released until the loan is repaid. When certified checks were used, the lender would be present at closing and receive a certified check from the purchaser for that portion of the purchase price used to repay the loan. If the loan repayment exceeds $25 million, that is not possible, and the parties must hope that the wire transfers are properly completed. When a new lender is advancing funds to the purchaser to fund the purchase price and the proceeds are to be used to repay the vendor's secured debt, the requirement for wire transfers can really be a problem.
Recent amendments to Canadian securities legislation have had an impact on some oil and gas dispositions. National Instrument 51-102 requires any reporting issuer to file a Form 51-102F4, business acquisition report, within 75 days of the completion of a significant acquisition, unless an information circular concerning the acquisition has been filed. NI 51-102 sets out three tests for determining whether an acquisition of a business is a "significant acquisition." The first test measures the assets of the acquired business against the assets of the issuer; the second test measures the issuer's investments in and advances to the acquired business against the assets of the issuer; and the third test measures income from the continuing operations of the acquired business against that of the issuer. If any one of these tests is met at the prescribed level, the acquisition is considered "significant," and a business acquisition report must be filed describing the acquisition. The report must contain financial statements of the acquired business and pro forma financial information. Such reports are required for significant acquisitions made under agreements entered into on or after March 30, 2004. Oil and gas properties are considered a business for purposes of this policy. Many oil and gas M&A transactions will require the filing of such a report. Since the report requires significant historical information, the acquiror must be sure that it can obtain the necessary information from the vendor. If the vendor refuses to provide the information, the purchaser will not be able to conclude it, and thus the vendor has little option in this regard. However, the vendor usually stipulates that it will have no liability for the accuracy of the information or any use that is made of it.
Reporting issuers engaged in the oil and gas industry are required to file engineering reports relating to their properties. The securities laws that describe the way in which such reports must be prepared have recently been changed. The reporting requirements under such Canadian securities laws are not the same as the requirements of the United States Securities and Exchange Commission (the "SEC"). If an SEC-regulated entity or unregulated entity proposes to sell oil and gas properties through an auction process, it will frequently commission engineering reports that are in compliance with the Canadian securities laws, since many of its potential bidders, particularly royalty trusts, will require such evaluations if they are the successful bidder.