October 2007 Archives

In an earlier article, I provided a synopsis of the federal taxation model used by the National Oil Sands Task Force (NOSTF). In that article, I provided a table, which I have repeated below. If you require a refresher, I encourage you to revisit the prior article.

Note, I have inserted a large space below for formatting purposes. You might or might not see the large space.

In the prior article, I mentioned that when the NOSTF performed its analysis back in the mid 1990s, resource allowance was 25%. It was a proxy for Alberta Royalty. Regardless of the actual royalty paid, the developer was permitted to deduct 25%. This 25% deduction also capped the amount that the developer could deduct. If Alberta raised the rate beyond 25%, too bad, soo sad. So in effect, the resource allowance capped the Alberta Royalty rate at 25%.

Just to be very clear, the developer could claim 25% resource allowance, even if it only paid 1% gross revenue royalty. Conversely, if Alberta had raised its royalty rate beyond 25%, the developer would be limited to only 25% for a federal deduction. Thus, the resource allowance effectively capped the royalty rate.

In a recent federal budget, actual royalty paid replaced the resource allowance. In theory, Alberta could increase its royalty substantially and the federal government would allow this increased deduction. In reality, I doubt it strongly. Both levels of government want their equitable share of the economic pie. The federal government is unlikely to allow Alberta to gain a significantly larger portion of the pie at its expense. The federal government would likely react by placing a limit, similar to the prior resource allowance, to cap Alberta's royalty rate once again.

Alberta's royalty rate could always exceed an imposed federal limit. Then the developer would pay a heavy penalty because it would pay a cost without being allowed to deduct that cost against taxes. That is an onerous measure.

As far as the developer is concerned, royalties and taxes are one and the same. Royalties and taxes are simply a burden that the developer must bear in order to remain in business. Moreover, the developer does not care how the economic pie is split among the different participants so long as its share of the economic pie is reasonable.

The Alberta Review Panel Final Report (PDF, 2.25mb) made no mention of the need to integrate the taxation regime with the royalty regime to create an overall fiscal framework. Moreover, the Panel neglected to mention that if royalty rates are raised, which it proposed, the federal government would likely respond in some measure to protect its interests. I find the Panel's oversight glaring.

As discussed previously, the federal and provincial tax rates have fallen precipitously. Both levels of governments need to work in a cooperative fashion to maintain an equitable fiscal regime where all participants have a fair portion of the economic pie. One level of government cannot act on its own because it will increase its share at the expense of the others. And that will cause retaliatory changes.

In summary, if Alberta were to adopt the changes are recommended by the Panel to increase the royalty rates on oil sands, then federal government would likely create changes as well to protect its interests. The Panel completely neglected to mention that both levels of government need to work together to maintain an equitable sharing of the economic pie among all three participants: the developer, Alberta and federal government.

Before discussing accelerated capital cost allowance (CCA) deductions, I need to discuss operating costs and capital expenditures. This topic was covered in the royalty and tax discussions earlier. To make my explanations easier to understand, I am going to use a corner grocery example, and then move back to an oil sands example later.

Assume that an entrepreneur is the owner and operator of a small corner grocery store. After he pays his staff, heating, lighting, insurance and the cost of his goods—all of which are operating expenses—he has some cash remaining. This cash could be reinvested back into the store. He might purchase additional shelving. Or, perhaps he might purchase a better store sign or cash register. All of these options are capital expenditures. The significant difference between an operating cost and a capital expenditure is that operating costs are consumed within a year typically and capital expenditures last for several years.

When a business is simple, this differentiation is reasonably clear and easy to understand. But as businesses become more complex, it is more difficult. For example, employee training often has benefits that last many years, yet training is typically an operating cost. Same applies to advertising. If a company buys computer software for a personal computer that lasts for several years, that too is an operating cost. So our earlier one year benefit rule is not a hard and fast rule.

Why does it matter whether or not a cost is an operating cost or capital expenditure? The difference is taxation. When an operating cost is incurred, the company is assumed to have spent all the money and earned all the benefits. The heat and air conditioning costs ensure that the store remained at the proper temperature. All heating and air conditioning operating expenses and benefits are complete at year end. Thus, on the tax return, the owner deducts from his income all his operating costs, which serves to reduce his taxes. If his heating and air conditioning were $2,000 and tax rate were 20%, then his taxes were reduced $400 (=$2,000 times 20%).

When a grocery storeowner purchases a new neon store sign, the neon sign lasts for several years. Thus, a grocery storeowner has merely exchanged cash, an asset, for a neon sign, a different asset. Only as the sign depreciates is the storeowner able to deduct the depreciation expense against his income. The depreciation rates are prescribed by the tax code. Ignoring all the complexities of the half year rule and double declining balances and such, let us assume that the depreciation rate is ten percent per year. So, if a storeowner spent $2,000 on a new neon sign, then he could claim only $200 worth of expenses in the first year. Next year, he could claim $180 (=10% times (2000 - 200)). And so on. In this example, the storeowner's taxes are reduced by $40 (=$200 times 20%) in year one and $36 (=$180 times 20%) in year two and so on.

Note that in our operating expense example, tax savings were $400 in year one. There are no more tax savings. In the capital expenditure example, the tax savings is $40 in year one and $36; in year two. If were to continue for several more years, eventually the total savings would equal $400. The storeowner wants his tax savings realized as soon as possible. From a taxation and cash flow perspective, an operating expense is less painful than a capital expenditure of equal value because an operating cost can be completely deducted against income in the current year.

In the oil sands fiscal regime, all capital expenditures associated with new projects, expansions where production is increased equal to or greater than 25%, and capital expenditures of greater than 5% of gross revenue were deemed CCA Class 41A and were eligible for immediate capital write-off. The 5% of gross revenue rule is meant to capture efficiency projects where a developer spends capital to reduce costs. These capital expenditures were, in essence, transformed into operating costs. Note, this is not completely true because of project ringfencing rules, but close enough for our purposes. During a normal environment where an oil sands company is moderately profitable, this immediate capital write-off capability provides a tremendous boost the developer's bottom line.

On pages 85 and 86 of the Panel's Report, they state:

Corporate Income Tax (CIT) and Accelerated Capital Cost Allowance (ACCA) -

It its 2007 Budget, the federal government announced that it was phasing out the ACCA for oil sands in the federal corporate tax system.

As part of its mandate, the Panel was asked to examine the provincial portion of the ACCA.

In the federal budget, the decision to eliminate the federal ACCA was justified on the following grounds:

"This incentive [the ACCA] helped to offset some of the risk associated with the early investment in the oil sands and contributed to the development of this strategic resource. Over time, however, technological developments and changing economic conditions have led to major investments that have moved the sector to a point where the majority of Canada's oil production will soon come from oil sands. As a result, this preferential treatment is no longer required."

The Panel agrees with this assessment. Accordingly, the Panel supports the elimination of the provincial ACCA for oil sands projects.

Both the federal government and the Panel got it wrong.

While it is true that this incentive helped to offset risk, it also helped to make smart decisions. Earlier we discussed how there is some ambiguity associated with what is an operating cost versus a capital expenditure. And we discussed that, because of tax efficiency where an operating cost is completely tax deductible immediately but a capital expenditure is not, operating costs are preferable to the same value of capital expenditures. Thus, developers are always skewed towards increasing operating costs, even if a capital expenditure provides a better solution.

Let us engage in another thought experiment. Suppose that a developer could address a project requirement by increasing its operating costs by $200 million dollars by burning more natural gas or by building a new facility for $200 million. In this thought experiment, I arbitrarily have all the money spent in one year to eliminate cash costs timing differences. Under this scenario, this developer would burn valuable non-renewable natural gas because it is more tax efficient. The developer is always biased toward operating expenses. That is the reason why I dislike the elimination of ACCA. Without the ACCA, plant engineers often forego the most technical and cost effective solution to implement a more tax efficient solution. With ACCA, plant engineers and others can ignore the tax code and simply focus on the actual costs and technical efficiency. In other words, they can design and implement solutions that cost the least amount of cash while satisfying the technical criteria.

Moreover, they are more likely to invest in capital equipment that will serve to reduce the project's ongoing operating costs as opposed to spending money on operating costs. A lower operating cost helps to reduce risk and helps to ensure that the project can withstand a prolonged period in an adverse oil price environment. In summary, the ACCA promotes efficient design and decision making.

These oil sands projects are unbelievably large and complex. If you have never set foot near an oil sands project, you should. You will marvel at their size and complexity. Because these projects are so large and complex, it is even more important that public policy encourage these projects to use all resources in the most efficient manner possible. Elimination of the ACCA distorts good design practices, sound decision making, and wastes resources.

Back in the mid-1990s when the National Oil Sands Task Force (NOSTF) developing a new fiscal framework, the federal corporate tax rate, including large corporation surtax, 29.12% and the provincial corporate tax rate was 15.5%.

According to 2007 Canadian Federal Budget, federal corporate tax rates are much lower today and going lower still.

Budget 2006 announced that the general corporate income tax rate would be reduced from 21 per cent to 19 per cent by 2010. The Tax Fairness Plan proposes to further reduce the rate to 18.5 per cent beginning in 2011.

On the provincial side, the corporate tax rate has fallen dramatically too. According Alberta Finance, Tax and Revenue Administration, the Alberta corporate provincial tax rate has fallen from 15.5% to 10%.

Given that both the federal and provincial tax rates have been reduced dramatically, we should not be surprised that the government's share—often referred to as government take—has fallen dramatically. Yet, I found no mention in the Alberta Review Panel Final Report (PDF, 2.25mb) of this dramatic change. I find this omission glaring.

Recall from our earlier article that governments' take has fallen. Given that the governments' tax rates have fallen by roughly a third, we should expect that a developer's take has increased dramatically. A key question we should ask of our governments is as follows: While the federal and provincial tax rates were being reduced, why was the oil sands fiscal regime not recalibrated to keep the proportional shares more or less equal?

I had planned on writing about tax rates. Instead, I want to discuss how the National Oil Sands Task Force (NOSTF) arrived at its recommendations. Next, I will return to my previously planned article on tax rates.

As a goal, the NOSTF wanted an efficient fiscal regime. Efficiency in this situation means an improvement to the developer's net present with the least costs tot the governments' net present value. Is not a gain by the developer equal to the loss by the governments? No. The reason why there is a difference is that the developer and governments use a different discount rate. They use different discount rates because of different risk profiles.

How are their risk profiles different? A developer is extremely dependent upon oil price. Prices are high, life is good. If prices are low for a developer, life is more challenging. For the governments, if prices are high, that is good for the royalty and taxes from the oil industry but bad for manufacturing, transportation, tourism, and other many other industries. If prices are low, that is poor for royalty and taxes from the oil industry, but good for manufacturing, transportation, tourism, and many other industries. The government is much less exposed to oil prices than is the oil industry, and thus it has a much lower risk profile. With a lower risk profile, it has a lower discount rate, as we discussed in an earlier article.

The NOSTF examined several different fiscal regimes. We tried various manufacturing and resource regimes in North America. We tried various resource regimes throughout the world. We experiment with investment tax credits and other mechanisms that have been used in Canada and elsewhere. In the end, we found the adopted NOSTF recommendations were among the most efficient of the options examined. Actually, I believe the NOSTF terms were the most efficient, though I am not completely positive. For those looking for more of a theoretical background on the NOSTF recommendations, I recommend you read Garnaut and Clunies Ross, Uncertainty, Risk Aversion and the Taxing of Natural Resource Projects.

Because of the different rates, we learned that that most efficient set of terms allowed the developer to recover quickly its investment capital quickly and then allowed the governments to receive their fair share of the economic pie. The NOSTF terms are very aggressive in returning the investment capital to the developer. This happens because of the low 1% royalty rate until payout and the immediate capital write-off that was available under capital class 41A.

Marginal effective tax rates are often a flawed methodology for setting fiscal policy because they do not account for a skewed cash flow profile where the developer has the costs of investment returned quickly. In other words, the marginal effective tax rate can be misleading. The panel for the Alberta Royalty Review discusses the marginal effective tax rate at length. Instead, it should have focused on the value returned to the developer, Alberta government, and federal government.

The purpose in bringing this information to your attention is to inform you that the NOSTF did not choose its terms arbitrarily. There was an effort to promote activity in the oil sands industry using the most efficient fiscal means.

In this article, I am going to cover three topics:

1. Cash Flow;
2. Net Present Value (NPV); and
3. General Comments On The Alberta Royalty Review.

The first two topics continue from my prior articles on the royalty and taxation. The third topic begins to address my comments the Alberta Review Panel Final Report (PDF, 2.25mb).

Cash Flow

The cash flow is amount of money after everything else has been paid. Knowing the cash flow over the life of a project, we can value it. This will make more sense in a moment.

In the above table, we see that the cash flow is simply gross revenue less all costs, including royalty and taxes. I have described in prior articles how gross revenue and other items were arrived at, so I will not repeat the discussion in this article.

In the next section, I will describe how a developer values a project using the cash flows.

The net present value (NPV) is the sum of a series future cash flows in today's dollars. I provided a table below that helps to explain this concept better.

Imagine you were given $1,000.00 on January 1 of Year 1. If you were able to invest that money at 10% for a year, then next year on January 1, you would have $1,100.00. We could repeat this process for all five years as shown in the table above. As we see, at the beginning of year 5, you would have $1,464.10. Another way of viewing the table is as follows: Imagine that you were going to be given $1,464.10 in five year's time, what is the equivalent value today, assuming that you could invest at 10% per annum? From our table, we know that $1,461.10 in five year's time is worth $1,000.00 today assuming an investment rate of 10%. This is known as the net present value of a single future cash flow.

In our situation with an oil sands project, we might have 45 years of future cash flows in our model. First, we would assume our production and commodity price over the 45 years. That would determine our gross revenues. Next, we would forecast our cost structure in terms of capital expenditures and operating costs. With that information and assumptions about the future royalty and tax structures, we can construct our financial model to determine annual cash flows for each of the next 45 years. We would then bring these future cash flows back to a net present value to arrive at the value of the project.

How can we know the future prices of oil, bitumen, gas and other commodities? Or, how about our future cost structures? If we do not know our future inputs and outputs, how can we arrive at a meaningful NPV value?

The reality is we do not know the future prices and costs. So we run the model several times under various assumptions. Assume low commodity prices with low costs to determine one answer. Assume low commodity prices with high costs to determine a different answer. Assume high commodity prices with low costs to determine yet another answer. And so on. There are systematic and sophisticated methods of varying inputs to arrive an array of outputs. Two popular techniques are known as Monte Carlo simulation and Decision Tree methodology. Both techniques are related but different. Each technique varies the most important inputs to measure the change in value. By knowing how the value of the project changes under various conditions, the developer can assess whether or not the project is viable and worth pursuing.

One item that I have not discussed yet is the investment rate. Earlier I used 10% as an arbitrary value. But what should the value be? This topic is a complicated and is often debated among analysts. The technical term of the investment rate is called the discount rate. It is called the discount rate because future amounts of discounted to a present value. For oil sands projects, a developer is likely using a value somewhere between 10% and 18%. That is a large range of values.

A discount rate is often a proxy for risk. By that, consider if you were to put your money into your bank. You can expect only to receive a couple or few percent return. It is very safe. Next, consider if you were going to invest a risky project. Then you would demand a higher rate. If the rate were the same, you would just leave your money in your bank account. So the discount rate is often used as a proxy for risk.

With regard to oil sands, the discount rate will likely be lower for an existing developer that is already running its operation successfully. Most of the bugs are worked out and the company is just expanding its operations. A new entrant might have a much larger discount rate because it is using a different technology and its management team is still unproven with this new venture.

The discount rate, though somewhat arbitrary, is extremely important to the overall valuation of the project. Again, a thorough discussion of how to arrive at a proper discount rate is beyond the reach of this article.

Another important point to know is that after 25 years or so, the net present value of future cash flows is almost negligible. What do I mean by that? Recall earlier when we had $1,464.10 in five year's time and it was only worth $1,000.00 today. Image you were going to receive a $1,000.00 in 25 year's time. What is its present worth today using a ten percent discount rate? Using a discount rate of 10%, a $1,000.00 in 25 year's time is only worth $92.30 today. Thus, the initial cash flows are most important.

I am going to repeat my prior sentence for emphasis: The initial cash flows are most important.

We have covered a lot of ground. We learned about royalty and tax structures that existed when the NOSTF and the provincial and federal governments created a new oil sands fiscal regime. Knowing that information, we are able to construct financial models to arrive at annual cash flows. And, using annual cash flows, we can determine the value of a project and provide comments on the Alberta Royalty Review. While I will not analyze a project, I will draw upon our knowledge when I comment on the Review.

I read through the Alberta Royalty Review document. I need to study it in further detail before I write the rest of my articles. As a quick impression, however, I find that I agree Alberta is not receiving its fair share and that the report has some serious shortcomings. Although I do agree that Alberta is not getting its fair share, I do not agree with all the recommendations as given. And I found that some information is missing or presented in an awkward manner.

On page 11 of the report, it states:

Cumulatively, the Panel's recommended package for changes for oil sands targets a total government take from the oil sands sector of 64%, increased over the present total take which is a little under 50%. Roughly 60% was the total take identified by the 1995 National Oil Sands Task Force (NOSTF) as consistent with the needs of a fledgling industry. The Panel regards a comparable level of take as more than reasonable for the production powerhouse the sector has become.

As I recall the NOSTF targets, they were roughly one third to developer, one third to provincial government, and a final one third to the federal government, which is close the 60% identified above. With regard to the fledgling industry stuff, I am not sure where the panel dreamt that up. Part of the NOSTF's goal was to have the industry invest $25 billion once the fiscal regime was adopted. That is some fledgling industry.

I have jotted down some topics that I am considering for future articles. This list is not necessarily complete, because I might add or subtract from this list. This list does, however, provide somewhat of a framework. The list, in no particular order, is as follows:

• Historical and current tax rates;
• Capital cost allowance (CCA) 41A;
• Bitumen pricing;
• Upgraders and upgrader credits;
• Complexity of proposed regime;
• Synthetic crude oil versus bitumen election;
• Resource allowance and royalty deductibility;
• Undiscounted cash flows for comparison purposes;
• Confidential versus open process; and
• Super agency.

Again, this list is subject to change. I will, however, start with tax rates as my next article.