Taxation of Oil and Gas Production and Royalty Interests. Wayne Paproski MNP

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1 Taxation of Oil and Gas Production and Royalty Interests Wayne Paproski MNP Oil and Gas Update June 3, 2014 Regina Saskatoon June 5, 2014

2 Law Society of Saskatchewan Oil and Gas Update Taxation of Oil and Gas Production and Royalty Interests Background This paper will cover some specific topics of interest to legal practitioners working in the oil and gas industry, both from the perspective of the oil and gas producer as well as the freehold royalty interest holder. The topics that will be covered are as follows are: 1. Corporation Capital Tax Resource Surcharge 2. Non-Resident Freehold Mineral Holders 3. Valuation Issues of Freehold Mineral Rights Corporation Capital Tax Resource Surcharge The resource surcharge is contained in the Corporation Capital Tax Act (the Act ) and it applies to a resource corporation which is defined as a corporation that has resource sales and either: 1) has taxable paid up capital or 2) has gross assets in excess of $100 million when combined with all affiliated persons. The calculation of paid up capital of a corporation is the aggregate of the following amounts, as measured on the financial statements of the company: Paid up capital stock; Retained earnings and other surpluses; All loans and indebtedness; Payables of the corporation outstanding more than 90 days; and Declared and unpaid dividends. After the paid up capital of a corporation is calculated there are a few deductions available to determine whether the corporation has taxable paid up capital for purposes of the resource surcharge. There is a standard exemption of $10 million that applies to all corporations. Second, there is an additional exemption of $10 million that is pro-rated among all associated corporations based on the total salaries paid in Saskatchewan over the total salaries paid by all associated corporations in all jurisdictions. There are also deductions for a goodwill allowance, a scientific research and development allowance and an investment allowance that may apply depending on the specific assets of a corporation along with their related tax carrying values. If the paid up capital of the corporation exceeds the available exemptions and deductions it will have a taxable paid up capital balance and will therefore be subject to the resource surcharge. The other way that a corporation may be considered to be a resource corporation is if the assets of the particular corporation and all affiliated persons exceed $100 million on a consolidated basis. In many situations an individual or their family own multiple corporations and could therefore be subject to the

3 resource surcharge unexpectedly in a situation where their oil and gas activities are not their primary business activity but their other holdings push them over the royalty threshold. The rate of the surcharge for oil and gas corporations is 1.7% for all oil and gas wells with a finished drilling date on or after October 1, 2002 and for incremental oil related to new or expanded enhanced oil recovery projects commencing after October 1, The rate for all other oil and gas production is 3%. The resource surcharge is calculated on the oil and gas sales of the company including the corporation s proportionate share of any revenue from partnerships that it holds an interest in. If the corporation has gross assets of less than $100 million it may be entitled to an annual deduction of $2,500,000 from resource sales when calculating the resource surcharge. The value of the resource sales deduction will be offset against gross resource sales and the resource surcharge will be calculated on the net amount of resource sales. When changes are made to the structure of a corporate group that result in more companies becoming associated or affiliated the resource surcharge should be kept in mind as the balance payable could easily be increased as a result of such changes. Consideration should also be given to planning around acquisitions of oil and gas producing assets to ensure the overall tax burden is minimized by structuring the corporate group properly. When changing the structure of a corporate group the anti-avoidance ruled contained in subsections 12(1) and 12(2) of the Act should be considered to ensure that the contemplated planning doesn t offend those rules by resulting in an undue or artificial reduction in the taxable paid up capital or reduction in the capital tax liability. Non-Resident Freehold Mineral Holders Non-resident mineral right holders are subject to Canadian taxes on all income received in relation to their mineral rights. The non-residents are not required to file tax returns in Canada solely because of their mineral interests and instead are subject to withholding taxes on all royalties and payments received. The withholding tax rate on royalty payments is 25% pursuant to paragraph 212(1) (d) of the Income Tax Act (the ITA ). The non-resident would generally be required to report this income in their country of residence, but would claim any tax withheld in Canada against their tax liability in their filing jurisdiction. In the event that the mineral rights are disposed of the purchaser can be liable for tax equal to 50% of the proceeds pursuant to 116(5.3) of the ITA. The disposition of mineral rights causes the non-resident to be deemed to be carrying on business in Canada and requires them to file a tax return. Since the 50% withholding rate is higher than the marginal tax rate that would be imposed on the non-resident, the filing of this return would typically result in a tax refund. When a non-resident enters into a lease with an oil company for the exploration of the mineral rights they often receive a bonus payment for signing the lease. For tax purposes this bonus payment is considered a disposition and is subject to the 50% withholding rate if the vendor has not received a certificate under subsection 116(5.2) of the ITA. When the lease is entered into a T2062A must be filed

4 within 10 days of the disposition reporting the proceeds received and the calculated actual tax liability. The tax remittance is due on the 30 th day of the month following the disposition. Practically what is often done in cases where non-residents have disposed of their interest in mineral rights is to have the 50% tax remitted from the oil company to the mineral right holder s lawyer to be held in trust. The form T2062A along with a draft of the taxpayer s T1 calculating the amount of tax due on the disposition are sent to the CRA in order to have a certificate issued by the CRA prior to the due date of the tax payment certifying that the amount calculated on the tax return is sufficient. Any balance of the 50% held in trust by the lawyer would then be released to the vendor. In the absence of this certificate the purchaser would be required to remit the entire 50% of the purchase price in accordance with 116(5.3). When a non-resident taxpayer dies owning mineral rights they are deemed to have disposed of them at their fair market value. There is no withholding on a deemed disposition at death by a non-resident like there is with a sale to a third party, however they are required to file a Canadian tax return for the year that included the and pay the taxes resulting from the sale. If the taxes weren t paid by the estate the executors would remain liable for the unpaid taxes. There is inherent double taxation when freehold mineral rights pass through the estate of a nonresident individual. This double taxation is the result of the fact that the purchaser/recipient of the mineral rights does not receive an increase to their tax pools that would offset future royalty payments even though the vendor paid tax on the entire value of the property. The double taxation becomes evident when you compare the tax treatment of a Canadian resident recipient of freehold minerals to a non-resident. When a Canadian resident purchases or inherits mineral rights they add an amount equal to the fair market value to a tax pool referred to as the Canadian Oil and Gas Property Expense. This tax pool is claimed against taxable income on a declining balance approach at 10% of the pool balance per year. This deduction allows the recipient to offset royalty income over time and effectively results in the tax free receipt of income up to the original acquisition value. A non-resident on the other hand receives no credit for the acquisition value that is available to offset the royalty income that the property generates. If the production declines over time to the point where the property is worthless the original purchase cost will not be deductable in any form. This inability to deduct the original cost of the property combined with the withholding taxes on the royalties received creates the double taxation. In the event that the property is sold, gifted or bequeathed while it has value by a non-resident that originally acquired it at a high value they will be able to reduce the resulting taxes paid to the extent they can prove their original acquisition cost. This double taxation is often a contributing factor in why many non-residents choose to dispose of their mineral rights after they have passed through an estate and have been subject to tax rather than receiving their value through the collection of future royalties that are subject to withholding taxes. There is a possibility to eliminate the double taxation on royalty payments discussed above if the nonresident can be considered to be carrying on a royalty business in Canada. This would enable them to file a Canadian tax return and claim the same Canadian Oil and Gas Property Expense deduction that a

5 resident taxpayer would be entitled to claim. In the past the Canada Revenue Agency has indicated that this filing position would be appropriate in some cases. We are requesting that CRA update their commentary on these types of situations to provide their current interpretation of these provisions. Valuation of Freehold Minerals Many individuals in Saskatchewan hold the mineral rights on parcels of land they have purchased or inherited. These mineral rights enable the holder to grant a lease the right to explore for oil and gas to an oil company and in exchange for the lease they receive a royalty on all oil and gas produced on the property. This royalty is typically calculated as a percentage of the gross revenue generated from the properties. Any time minerals are being transferred in a non-arms length situation a value must be placed on the properties. The most common non-arms length transfers are transfers to beneficiaries on the death of a mineral holder, the transfer to a corporation or trust as part of a tax and estate plan, or on an intervivos transfer to descendants. Each of these transactions has tax consequences that are dependent on the value of the property sold or transferred. In non-arms length situations the tax implications of using the incorrect value that is the result of not doing a reasonable amount of valuation work are typically that both the vendor and the recipient will be taxed on the difference between the value reported by the taxpayer and the value determined by the CRA. Over time certain rules of thumb have been used by professional advisors when placing values on mineral rights for title, probate or tax purposes. These rules of thumb have been between 3 and 4 times the annual royalties. From a valuation perspective there are many limitations to this approach it doesn t specifically reflect the fact that oil and gas production naturally declines over time, the fact that prices are volatile and that additional wells may be drilled on the properties in question which would increase the royalty revenues. In recent years with the increases in oil prices as well as increased average production from technological advancements in drilling and completions the royalties received by many individual mineral right holders has increased substantially. These increases have caused CRA to scrutinize valuations more frequently and as a result to establish their own assessing position with respect to producing minerals to be in the range of 6-9 years of the royalty revenue. While CRA s assessing rule of thumb is not necessarily any more accurate than the rule of thumb used by the taxpayer, they almost always stick to it unless the taxpayer can provide a report prepared by a qualified valuator. A more appropriate valuation method for this type of income stream would be a discounted cash flow approach whereby the future potential revenues are estimated and then a discount factor is applied to present value the future income into a current value. This approach first requires a forecast of the expected production from the properties in question which includes any potential value for future wells that are likely to be drilled. This analysis needs to be completed by a qualified reserve engineer in order to make these determinations. Next a set of future oil prices must be applied to the production volumes to calculate the total expected income. Finally a discount factor, measured in terms of an interest rate,

6 must be applied to the future revenues. The determination of the appropriate rate is generally done by a valuation professional. After those calculations are completed a value for the property is established. As can be seen with the following examples the use of advisor s rules of thumb, CRA s rules of thumb and a present value calculation can arrive at substantially different outcomes. Example 1 In this example a royalty stream was used that represents an oil well that is recently drilled and would have significant declines in the first year and slowly level off as the production rate declines. The values generated under the various valuation approaches are as follows: Old rule of thumb - $350,000 CRA assessing range - $600,000-$900,000 Discounted cash flow - $232,000 Year Annual Royalties Annual Royalties PV 10% 1 100,000 90, ,000 41, ,000 30, ,000 22, ,000 15, ,000 11, ,000 8, ,000 5, ,000 3, ,000 3,084 Total 313, ,346 In this case the old rule of thumb is higher than the the discounted cash flow, but the CRA assessing range is so much higher that it would potentially result in taxes payable being higher than the royalties received over the life of the production. In this case the importance of a valuation to support a lower value than CRA assesses based on is very important. Example 2 In this example a royalty stream was used that represents an oil well that is not recently drilled and would have lower declines in production from this point forward. The values generated under the various valuation approaches are as follows: Old rule of thumb - $350,000 CRA assessing range - $600,000-$900,000 Discounted cash flow - $474,000

7 Year Annual Royalties Annual Royalties PV 10% 1 100,000 90, ,000 74, ,000 63, ,000 54, ,000 46, ,000 39, ,000 33, ,000 27, ,000 23, ,000 19,277 Total 730, ,823 In this case the old rule of thumb would be lower than the discounted cash flow, but the CRA assessing range would again result in taxes payable being almost equal to the royalties received over the life of the production. In this case the importance of a valuation to support a lower value than CRA assesses based on is very important. Example 3 In this example a royalty stream was used that represents an oil well that is on a secondary recovery (water flood or CO2 flood) and essentially has no declines in the royalties. The values generated under the various valuation approaches are as follows: Old rule of thumb - $350,000 CRA assessing range - $600,000-$900,000 Discounted cash flow - $614,000 Year Annual Royalties Annual Royalties PV 10% 1 100,000 90, ,000 82, ,000 75, ,000 68, ,000 62, ,000 56, ,000 51, ,000 46, ,000 42, ,000 38,554 Total 1,000, ,457 In this case the old rule of thumb would be far lower the discounted cash flow and the CRA assessing range would begin to become a reasonable estimation of value.

8 All of the above examples are based on the simple illustration with the assumption that the well(s) that are producing the revenue are the only ones considered in the cash flow analysis. Depending on the size of the land in question and the other wells that may be producing in the vicinity of the property there may be some additional value ascribed to the undeveloped land that could allow for additional wells. And while a higher discount factor is appropriate for these potential locations given their uncertainty, their existence should be addressed and a value placed on them. In summary, the valuation of minerals becomes more important the higher the revenues and fair market value are as a small change in assumptions makes a significant difference. Since taxable transactions with minerals have a tax rate often exceeding 40%, having the ability to support a valuation lower than these rules of thumb often saves tax many times over the cost of having the valuation prepared.