2000 May Report of the Commissioner of the Environment and Sustainable Development
Appendix C—Current Income and Excise Tax Provisions for Energy Investments
Provisions for capital expenses
1. Companies and individuals pay federal income tax on their business income; provincially owned oil and gas companies and utilities do not. The Income Tax Act contains general provisions that apply to all sectors of the economy and special provisions that apply only to specific sectors. Table 1 below summarizes those provisions that concern the energy sector only. The provisions for renewable and non-renewable resources are complex, and when they are used, so is the way they interact with each other, with all the other provisions in the Act and with provincial tax and royalty regimes.
Intangible capital expenses
Intangible capital expenses are incurred to explore for and develop non-renewable resources and to develop renewable resources, for example, expenses to bring a discovered oil well to production or to look for a suitable windy site for future wind turbines.
The oil and gas industry uses two methods to write off intangible capital expenses for book purposes:
The renewable resource sector normally capitalizes intangible capital expenses for book purposes and writes them off over the production life of the new resource.
For tax purposes, these expenses are put in different pools depending on their nature and are written off according to the rules for each pool. The pools are described below.
Canadian exploration expense (CEE) includes qualifying expenses to determine the existence, location, extent or quality of a non-renewable resource. CEE can be fully written off as soon as the money is spent (with some limitations) or carried forward to future years. It can also be passed to shareholders who have bought flow-through shares. When this happens, the shareholders claim the CEE rather than the company.
Canadian development expense (CDE) includes qualifying drilling expenses to bring known reserves into production. CDE can be written off at a maximum rate of 30 percent of the balance in the pool each year. The balance left in the pool is carried forward to future years. CDE can be flowed through to shareholders. Under certain conditions small companies can reclassify the first $1 million of CDE as CEE to get a faster write-off.
Canadian oil and gas property expense (COGPE) refers to lease and bonus payments to resource owners, typically provinces, for the rights to explore, develop and take the resource. COGPE can be written off at a maximum rate of 10 percent of the balance in the pool each year. The balance left in the pool is carried forward to future years.
Mining provisions for intangible expenditures are similar to those listed above but there are differences that are particularly relevant to oil sands mining and coal. Property expenses are treated as CDE and can be written off at a maximum rate of 30 percent of the balance in the pool each year (compare with COGPE). Pre-production development expenses for new mines are treated as CEE and can be fully written off as soon as the money is spent or carried forward to future years (compare with CDE).
Canadian renewable and conservation expense (CRCE) includes qualifying expenses to develop a renewable energy project for which it is expected that at least 50 percent of the capital cost of the equipment to be used is eligible for class 43.1 treatment (see below). CRCE can be fully written off as soon as the money is spent or carried forward to future years. CRCE can be flowed through to shareholders.
Tangible capital expenses
Tangible capital expenses are the costs of physical assets, such as buildings and equipment.
Tangible capital expenses are generally written off (depreciated) on a company's books over the useful life of the assets. For tax purposes, they are grouped into capital cost allowance (CCA) classes, each with an annual write-off rate that is often different than the book depreciation rate. There are many CCA classes defined in the Income Tax Act, of which the following five classes are the most relevant to energy investments.
Class 1 includes pipelines, other than oil and gas pipelines with a useful life of 15 years or less, buildings and structures, including their energy-using components, dams, and electrical generating equipment. The CCA rate is four percent (the February 2000 Budget proposes an increase to eight percent for qualifying energy equipment) on a declining balance basis. (This means that the costs are pooled: four percent of the balance in the pool is written off as an expense for the year and deducted from the pool, and the remaining balance in the pool is carried forward to the next year.)
Class 8 includes oil and gas pipelines with a useful life of 15 years or less and electrical generating equipment that has a maximum load of 15 kilowatts. The CCA rate is 20 percent on a declining balance basis.
Class 41 includes all resource extraction assets acquired after 1987. It also includes electrical generating equipment for mines, equipment used in resource exploration and heavy crude oil processing, natural gas processing plants and drilling vessels for oil and gas. The CCA rate is 25 percent on a declining balance basis. There is also a special CCA rate of 100 percent for new mine and mine expansion assets, as defined in the Act, but it is limited to the amount of income earned from the mine. In these cases, no corporate income tax is paid on the income from the mine until all capital expenses are written off.
Class 43 includes energy conservation equipment and heat recovery equipment used in manufacturing and processing plants, equipment used in refineries, natural gas straddle plants, and facilities to produce alternative transportation fuels, such as ethanol. The CCA rate is 30 percent on a declining balance basis.
Class 43.1 covers energy conservation equipment, or investments in renewable energy that produce electricity and heat (with some restrictions). It includes mainly co-generation and specified waste-fuelled electrical generation systems, active solar and passive solar systems, small-scale hydro-electric installations, heat recovery systems, wind energy conversion systems, photovoltaic electrical generation systems, geothermal electrical generation systems, specified waste-fuelled heat production equipment, and electrical generating equipment using solution gas. The CCA rate is 30 percent on a declining balance basis.
Provincial royalties and the federal resource allowance
2. The provinces own much of Canada's non-renewable energy resources. They charge royalties for taking these resources. They also charge mineral taxes on freehold mineral rights. Table 2 summarizes some of the royalty regimes that exist today.
Highlights of provincial royalty regimes
Alberta. The royalty rate on conventional oil and gas production varies with the vintage (the date the oil or gas was discovered), the productivity of the well and the price. There are minimum and maximum royalties. For example, the minimum royalty for natural gas from a normal to high-producing well is 15 percent of the volume produced; the maximum royalty is 35 percent for old gas and 30 percent for new gas. Alberta also provides a refundable royalty tax credit equal to between 25 percent and 75 percent of the first $2 million in Crown royalties paid. As well, Alberta offers reduced royalties or short-term royalty holidays to encourage certain activities, such as drilling gas wells deeper than 2,500 metres.
In the past, Alberta negotiated royalty agreements for oil sands projects with each developer. Its current royalty regime charges a minimum royalty of one percent of project gross revenue. After payout, the royalty is the greater of the minimum royalty or 25 percent of project net revenue. Payout occurs at the point in time when cumulative revenues from the project equal cumulative operating and capital costs plus a return to the developer. There are transitional agreements for developers moving from negotiated agreements to the current royalty regime.
British Columbia. The royalty rate on conventional oil production varies with the vintage and productivity of the well. Rates are lower for new oil. The royalty rate for natural gas varies with the price and the type of gas but not the vintage or productivity of the well. A 36-month royalty holiday is given to oil produced from a new pool discovery well completed after 30 June 1974.
Newfoundland. Newfoundland has separate royalty regimes for onshore and offshore resources. There is currently no onshore production of oil and gas. For the offshore, the royalty rate varies with the amount of oil produced and the level of profit earned. For example, before payout the royalty rate ranges from one percent to 7.5 percent of gross revenue.
The Hibernia Development Project has a separate royalty regime. It includes a fixed royalty of $0.01 per barrel and a variable royalty. Before payout the variable royalty rate gradually increases from one percent to five percent of gross revenue over six years. After payout the variable royalty is the greater of five percent of gross revenue or 30 percent of net revenue (as defined in the agreement). If the project is very profitable, a supplementary royalty also applies.
The Terra Nova Development Project also has a separate royalty regime. It includes a fixed royalty of $0.01 per barrel and a variable royalty. Before payout the variable royalty gradually increases from one percent to 10 percent of gross revenue. After payout the variable royalty is similar to Hibernia's.
Nova Scotia. On 4 August 1998, Nova Scotia announced a new royalty regime for future offshore projects. The royalty varies with project revenues and project profits starting at two percent of gross revenue. A minimum of five percent of gross revenue is always payable after payout. There is no royalty holiday.
The Sable Island project will pay a reduced royalty of one percent of gross revenue for the first three years. After that, the royalty rate increases to two percent of gross revenue. Depending on the profitability of the project, it continues to rise to a maximum of 35 percent of net revenue.
Saskatchewan. The royalty rates on conventional oil and gas production vary with the vintage and productivity of the well, and the price. The rates start at zero for low-producing wells and increase progressively for higher-producing wells. For example, a new vertically drilled heavy oil development well producing 100 cubic metres of oil per month will pay a minimum royalty rate of 7.5 percent if the price is $100 per thousand cubic metres or less and a maximum royalty rate of 22.5 percent. Saskatchewan also provides royalty incentives to encourage new projects.
3. In 1997, the Minister of Finance's Technical Committee on Business Taxation reported that the overall effective royalty rate was between 16 percent and 17 percent of gross revenues for conventional oil and gas; this rate takes into account royalty incentives. As Table 2 shows, the royalty regime for oil sands and offshore projects is initially more generous than that for conventional oil and gas; royalties are around one percent of revenues until cumulative operating and capital project costs and a return on investment are covered.
4. When companies calculate their federal income taxes, they cannot deduct royalties paid to provincial governments for oil, natural gas and minerals. (Normal income tax rules allow a deduction for most amounts that are paid to earn income.) To compensate for this restriction, companies can deduct a resource allowance that is 25 percent of resource profits from mining and producing oil and gas. In general terms, resource profits are defined as resource revenue minus associated overhead, operating costs and capital cost allowances.
Investment tax credits
5. There are two general investment tax credits in the federal tax system that are of particular importance to the energy sector. The Atlantic Investment Tax Credit aims to develop the economy of the Atlantic provinces by granting a 10 percent tax credit on investments in manufacturing and energy production. Offshore oil and gas companies currently receive a large share of the total amount claimed for this credit.
6. The other tax credit is designed to support investments by Canadian industry in scientific research and experimental development. Companies can reduce the taxes they have to pay by claiming a credit equal to 20 percent of the cost of eligible research and development. Smaller Canadian-controlled companies can claim 35 percent, and a portion of this amount is refundable if the claimant does not have any taxes to pay. Many companies in the renewable and non-renewable resource sectors carry out extensive research and development and can use this investment tax credit.
Oil sands, a special case
7. Central and northern Alberta have large deposits of tar-like bitumen, which can be converted into petroleum products. However, the substance is too thick to be extracted by conventional oil production methods. Deposits that are located near the surface can be recovered by surface or open-pit mining techniques. Bitumen deposits buried too deep for mining to be economical are extracted using in situ (drilling) methods more similar to those used for conventional oil and gas.
8. The mining provisions of the Income Tax Act are used for oil sands mines, rather than the oil and gas provisions. The mining provisions are similar to those for oil and gas but allow more generous write-offs for property and pre-production development expenses.
9. There are also special provisions for assets used to extract the bitumen. When a company acquires these assets for a new mine or a major expansion of an existing mine, including oil sands mines, it can write them off immediately, as long as the write-off does not exceed the income from the mine. In other words, the company only pays federal income tax on the income from the mine once it has written off all the eligible capital costs. This write-off is a significant tax concession. In the case of a major mine expansion, the income from the mine includes the whole mine, not just the expansion. As a result, the costs of expanding an existing mine will likely be written off more quickly than the costs of opening a new one. After 6 March 1996, oil sands projects that use in situ extraction methods can apply the mining provisions to all qualifying tangible capital expenses on the basis that the product is similar, regardless of the extraction method.
10. Oil sands projects are also subject to the resource allowance system described earlier, with one major exception. The Syncrude project received a remission order in 1976 that has allowed the participants to deduct provincial royalties as well as the resource allowance for two of its leases. The order is in effect until the production of 2.1 billion barrels of synthetic crude or 31 December 2003, whichever comes first. According to the Public Accounts of Canada, the government had remitted at least $153 million in taxes under the order by 31 March 1999.
11. The tax system has recognized the risks and huge costs of oil sands projects, particularly in earlier years when the technology was evolving and the operating costs were greater than the selling price of the product. As noted in Table 2, the Province of Alberta charges lower royalty rates during the early years of an oil sands project than it does for conventional oil and gas.
12. Consumers pay several taxes on fuels to run their vehicles and equipment: federal and provincial excise taxes, the federal goods and services tax and, in some instances, provincial sales taxes. Consumers who purchase more fuel-efficient vehicles benefit from an effective reduction in the total excise taxes that they would have paid. Alternative fuels, such as ethanol produced from renewable sources, propane, compressed natural gas and methanol, are exempted from the federal excise tax. For blended fuels, the tax exemption applies only to the proportion of the exempt fuel in the product.