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The new royalty structure is largely a nonevent (see New Royalty Framework document (PDF, 950kb)). I expect that most oil companies have long term oil price projections of $55 to $65 WTI, with $55 being the more likely target. Companies are conservative by nature.

At $60, the terms are very nearly back to 1% gross revenue royalty and 25% net revenue royalty. So in terms of future development, the net effect should be muted. At higher prices, new entrants are discriminated against relative to existing players.

It is only at significantly higher prices that larger provincial takes kick in.

The markets, despite all the hoopla, have largely shrugged off this event. Suncor Energy Inc. (SU) and Canadian Oil Sands Trust (COS-UN.TO) were off less than 1.5% combined—easily within daily trading noise—yesterday, the first business day after Premier Stelmach's proclamation.

Some might think that these Suncor and Canadian Oil Sands were already down in anticipation of the royalty review. Not so, this link to a Yahoo price chart shows Suncor in U.S. dollars and Exxon Mobil Corporation (XOM) in U.S. dollars. You will note that Suncor has outpaced Exxon during the last three months. It did not tank prior to or after the Panel's published report.

Without crunching the numbers, a worthwhile exercise, I think the terms that existed during the mid 1990s were possibly harsher with the higher provincial and federal taxes that were about 50% higher than today's percentages. It is only under significant and sustained high prices, say $75+, that the new regime might be more punitive. And even that might be moderated going from synthetic crude oil to bitumen royalty regime. This entire last paragraph is intuitive guesswork that should be more thoroughly investigated.

With regard to the royalty percentages exceeding 25%, I would not be surprised to see the federal government cap royalty deduction at 25% of resource income. If that happens, then there will be a slight further hit to the oil companies. I remain skeptical that the federal government will offer to pay about 20% of the oil companies' increased royalties.

Given the final outcome, I am disappointed with the Panel's work. They had the opportunity to create a meaningful and workable royalty regime. Instead, they presented a wonky royalty regime with an oil sands separation tax, which was not tax deductible and extraordinarily difficult to pass politically. That combined with a royalty rate above 25% would have been very punitive on the oil companies.

After I think more about the Premier's new framework, I will likely comment further. I might even run some numbers through my economic models and discuss the comparisons. At present, however, I think the new framework is largely a nonevent.

I also urge you to read two other weblogs that discuss the new framework: WTF Journal by Ian Langdon and Ken Chapman by, you guessed it, Ken Chapman. My view differs from those of both writers. And that is okay. Blogging should be about informing. Our differing views will allow others to see arguments from different perspectives—a good thing.

Calgary model Jennifer Nguyen is featured in the photograph, which is hosted at Flickr. If you click on the picture of Jennifer, you will be taken to where you can view a larger version and see even more pictures of her.

In this article, I will briefly highlight major points raised in my prior articles. To help keep this article brief and easy to read, I will use bullet points throughout most of the article. If you want more depth, please read my individual articles leading to this summary. Please note that my summary will not necessarily follow the same order of the original articles.

 

Spacing added for weblog formatting purposes.

 

 

 

 

1. Royalty Review Terms of Reference
   • A quote from page 101 of the Report:

     An independent Panel of experts will review all aspects of the oil and gas royalty system, including conventional and oil sands. The Panel will also examine the tax regime faced by the resource companies, including income tax and freehold mineral rights levied on freehold mineral rights holders.

2. High Level Recommendations
   1. Prepayout
      • 1% gross revenue royalty.
   2. Postpayout
      • 1% gross revenue royalty (treated as a cost) plus,
      • 33% net revenue royalty.
   3. Oil Sands Severance Tax (OSST)
      • Starting at C$40 WTI, 1% gross revenue increasing by 0.1% for every dollar until 9% at $120 WTI.
      • Ineligible for payout calcuation purposes and nondeductible for federal and provincial taxes.
   4. Upgrader Credits
      • 5% of the capital cost for additional upgrader capacity in Alberta/
3. Did the governments and National Oil Sands Task Force (NOSTF) propose fair and equitable terms back in the 1990s?
   • While a thorough discussion of constitutes fair and equitable terms is a good exercise, let us for the moment assume that the governments and NOSTF did propose fair and equitable terms at roughly one third value to each of the following key project stakeholders: developer, province, and federal government.
4. Changes in tax rates since the mid 1990s
   1. In the mid 1990s, the federal rate, including large corporate surtax, was 29.12% and provincial rate was 15.5%.
   2. The federal rate will soon be at 18.5% and the provincial rate is at 10%. The provincial and federal tax rates were approximately 50% higher in the mid 1990s.
   3. If we accept that the sharing of the economic value pie was correct in 1990s, then the fiscal regime must be changed now just to reflect differences in taxation rates, let alone changes in commodity prices and other circumstances.
5. Resource Allowance and Royalty Rate
   1. Resource Allowance was set to 25% of resource income. Resource allowance has been replaced by actual royalty paid.
   2. If the province were to increase its royalty beyond 25%, the federal government is likely to cap the allowable deduction of royalty to 25% (back to resource allowance again) to preserve their portion of the economic value pie.
   3. By not having the federal government involved in the creation of a harmonious oil sands fiscal regime, the current proposal is likely dead on arrival. The federal government is unlikely to support a massive royalty increase, much of which will come at their expense unless the federal government caps the royalty deduction amount. Again, federal government is likely to cap the royalty amount as a federal tax deduction.
6. Support for Federal Elimination of Accelerated Capital Cost Allowance (ACCA)
   1. With ACCA, developers and engineers are more efficient in that they seek to spend the minimum amount of capital to address an issue; they will build infrastructure (capital expenditures) to address an issue because it reduces the project's ongoing operating costs.
   2. With the elimination of ACCA, developers and engineers are more likely to increase operating costs than spend capital dollars to address an issue because operating costs are more tax efficient; the downside is that higher operating costs increase the project's risk to a sustained downturn in oil prices or a sustained upturn in input costs.
7. Royalty Credits for Upgraders is Flawed
   • Royalty credits for upgraders are flawed because it does not consider the profitability of the developer. Imagine if oil prices were to hit all time highs, yet we citizens were subsidizing extraordinarily rich oil companies' investments in new upgraders. It makes no sense.
8. Royalty Based On Bitumen
   1. A bitumen based royalty is challenging because of the challenge of valuing bitumen and creating an open and transparent market for bitumen. Every project produces its own unique concoction of bitumen. All bitumen products from different developers with have different levels of fines (sand and clay), sulfur content, and other impurities.
      • Moreover, each upgrader is specifically configured to process its own feedstock. In other words, Upgrader Z values its feedstock differently than Upgrader Y would.
   2. A bitumen based royalty might kneecap future investments in upgraders when the current large heavy light oil differential disappears and upgraders return to being marginal investments. Upgraders are normally marginal investments. If, in the future, normality returns and a project requires an upgrader, it might be unable to proceed with the overall project because the cost of the upgrader is prohibitive and cannot be used to offset royalties. At present, a developer can elect to its royalty based on synthetic crude oil or bitumen. Because of the wide differential between light and heavy oil, a bitumen based royalty is preferred today.
9. Oil Sands Severance Tax (OSST)
   1. The Oil Sands Severance Tax is very punitive because it kicks in before payout and because it will harm new entrants most.
   2. Having a provincial OSST ineligible for the purposes of the royalty payout calculation and having it non deductible for provincial and federal taxes is poor policy
      1. It might discourage or delay developers from undertaking expansion, debottlenecking or efficiency projects.
      2. It might discourage or delay developers from undertaking additional environmental projects.
      3. It sets a poor precedent for taxation in Canada, giving Canada an unsavory reputation.
      4. Although not mentioned in the detailed article, what if the federal government wants to implement a windfall or carbon non deductible tax of their own? Should these windfall tax programs be coordinated between both levels of government?
   3. A challenge with burdening companies during good times with OSST, do governments come to the rescue during bad times?
10. Undiscounted Cash Flow Graphs for Comparison Purposes
    • In the report, the Panel showed various graphs for fiscal regimes around the world. These graphs, however, usually showed undiscounted cash flows. Perhaps that works well when comparing various conventional resources, but when comparing conventional and oil sands, it does not. Conventional production follows an exponential decline, meaning that most of the cash flow comes early in life, usually within the first ten years. Oil Sands have a steady or increasing production with time, meaning that much of its cash flow comes later in life, usually after the first 15 years. Thus, the sum of undiscounted cash flow charts will overstate the relative value received by oil sands companies.
11. Complexity of Proposed Regime
    • The new royalty regime is complex. The Panel proposed a 1% gross revenue royalty payable before and after payout. Post payout, an additional 33% net royalty is adjusted partially to account for the initial 1% gross royalty. In other words, the 1% gross royalty is treated as a cost in the post payout calculation. As mentioned previously, the OSST is an additional royalty or tax payment that is calculated and applied separately.
12. Open Process
    • I commend the Panel for putting the whole review process into the public domain. That is where it belongs.

I am critical of the Alberta Review Panel Final Report (PDF, 2.25mb). From my understanding, there does not appear to be a harmonious design between royalties and taxes. The Panel appears not to have considered the federal government's role in setting an overall fiscal regime. When it proposed provincial royalties beyond 25%, I knew that amount would be partially paid by the federal government, something that the federal government is unlikely to accept. At that point, I concluded that the Report was dead on arrival.

From there, I read the Report carefully and found other flaws, some of which are substantial. The Panel had the opportunity and, presumably, the resources to recommend a fiscal regime that would restore fairness to the citizens of Alberta and Canada. To act upon this opportunity in a proper fashion, the Panel needed to have broad wide ranging view. Instead, the Panel's view was rather myopic. It did not think through the implications of its design. It did not even bother to quantify the values to each of the major stakeholders, a fundamental act in any negotiation. Instead, it relied upon wonky international undiscounted cash flow summaries, which do not capture value well, and marginal effective tax rates, which are not effective measures when capital is returned to a developer in an expedient fashion. Moreover, the OSST has a host of issues of its own. In short, I believe the Panel's work is deeply flawed.

As an Albertan, I am disappointed.

Calgary model Judith Aldama is featured in the photograph, which is hosted at Flickr. If you click on the picture of Judith, you will be taken to where you can view a larger version and see even more pictures of her.

I am critical of the Alberta Review Panel Final Report (PDF, 2.25mb). Over the prior articles, I have outlined shortcomings with the report. In this article, I will outline how I would have approached the same challenge of responding to their terms of reference. Below is a quote from page 101 of the Report.

Royalty Review Terms of Reference

An independent Panel of experts will review all aspects of the oil and gas royalty system, including conventional and oil sands. The Panel will also examine the tax regime faced by the resource companies, including income tax and freehold mineral rights levied on freehold mineral rights holders.

If, for a moment, we accept that the National Oil Sands Task Force (NOSTF) in the mid 1990s was correct in splitting the economic value pie into three approximately equal parts for the developer, province, and federal government, then how do we respond given that a) the federal rate was 29.12% then and is 21% now and falling to 18% by 2011 and b) provincial tax rate was 15.5% then and 10% now. In other words, the federal and provincial tax rates were about 50% higher then than they are now or soon will be. Surely, that has resulted in a transfer of the value from economic value pie away from citizens and toward developers. Without much further analysis, we citizens can conclude that our governments have not been safeguarding our interests by maintaining an equitable share of the economic value pie.

As a side note, throughout my discussion in this article, I am deliberately referencing economic value. I find undiscounted cash flow values present specious arguments and are not worthy of serious discussion.

What other key changes have happened since the NOSTF's work back in the 1990? Just thinking quickly, I would rattle off some differences:

• Oil prices have departed from their long run historical US$20 real per barrel pricing and have risen substantially;
• Oil rich provinces such as Venezuela and Russia are no longer welcoming foreign investment on easy terms;
• Brazil, Russia, India, and China (BRIC) are all racing toward becoming modern industrialized countries, soaking up vast quantities of all commodities, including oil and gas;
• According to Alan Greenspan, the United States is involved in a war in Iraq largely centered on oil issues;
• Geopolitical tensions have increased with terrorists waging war against democracies and western civilized world;
• Construction and material costs have risen around the world; and
• Conservation, greenhouse gases, and alternative fuels have become household words as people seek to lessen their environmental footprint and reduce their energy costs.

A lot has changed in only a decade. And, I am sure that I have not captured all the major changes. However, let us look at what I have mentioned and how it might influence our thinking.

Oil prices have increased. There might be the potential for windfall profits. How do we want to address huge profits that are earned by the industry through good fortune? When some of the oil sands companies purchased their leases, they did not foresee these generous prices, not even in their wildest dreams. They purchased the leases at then fair value then, but at bargain basement prices today. Do we want to moderate these windfall profits?

The Panel by recommending an Oil Sands Severance Tax has attempted to moderate windfall profits. While I understand why people might want to capture windfall profits, I remain unconvinced that windfall taxes are good public policy. I remain open, however, to the argument.

Oil rich provinces are not as accessible as they once were. If developers do not like Alberta, they can no longer readily leave and go to Venezuela, Russia or some other countries that are much more protective of their natural resources. Given that Alberta remains a friendly place with good government, adequate infrastructure, and the rule of law, developers should place a premium on working in Alberta compared to many other locations. This is especially true given the size the resource and the lack of geological risk.

BRIC countries and others are racing toward a modern society. As Jim Rogers has argued for a long while, commodities are likely to enjoy a bull run for several more years. Commodities were once considered irrelevant, because you could always easily and readily secure them. That is no longer true. Commodities have become scarcer and countries are hoarding their resources for themselves.

Wars and terrorism and oil. That almost says it all. Oil is no longer a cheap commodity in bountiful supply. There is a race to secure vast quantities of oil as oil becomes increasingly more difficult to find and produce. Much of the oil rich regions are located in more interesting places of the world from a risk point of view. Again, that bodes well for Alberta.

Costs have gone up dramatically. Perhaps surprisingly, this is a non factor for the NOSTF, because its recommendations were focused on economic profits. If a developer feared it would not be profitable, then its correct course of action was to not build. Period. If a developer believed that it would be profitable given the economic landscape, then the economic spoils (economic value pie) were split approximately equally among the developer, province and federal government.

Conservation, greenhouse gases, and alternative fuels all speak to the notion that we have to use fossil fuels wisely because they are scarce and because they do pollute.

Nothing has happened during the prior decade that motivates me to want to reduce the government take. Two larger questions are as follows: Should the government take be increased from the NOSTF's recommendations, and if so, by how much? These questions deserve public consideration and comment.

In addition to reviewing the current events, I would encourage others to compare and contrast alternative regimes in different jurisdictions, with a note of caution. Comparing different regimes is fraught with difficulty. Often, politics enter into the picture. The Gulf of Mexico has very generous terms because the United States wants to encourage exploration and production. Middle East countries have very harsh terms because of the geological risk is comparatively low and because those countries depend heavily upon oil and gas revenues to sustain their economies. Some countries have generous terms, but transportation costs are prohibitive. The key point is that if you torture the data long and hard enough, it will confess to anything.

So while I think it is important to look internationally for comparisons, I think it is equally or more important to look at the risk reward ratio for engaging in oil sands activity. Do developers earn modest, fair, or generous returns given all the risks? And, what defines modest, fair, and generous returns?

So, what have we accomplished thus far? We know that the provincial and federal tax rates were about 50% higher during the 1990s than they are today. (Equally true, I could write that taxes have fallen by about one third from 1990s level to today's level, but that does not sound nearly as dramatic.) So that alone motivates us to want to recalibrate the overall fiscal regime to bring the stakeholders' proportions back into balance. We have also acknowledged that major changes have occurred during the past decade, none of which to my mind would influence me to want to reduce the government take. We should, however, engage all interested parties—including the public and developers—to a vigorous debate as to what is a fair and reasonable government take. And we should probe whether that take should remain constant over a wide range of oil prices or whether the take should reflect oil prices.

Next, I would construct a sample of projects to evaluate. These projects would demonstrate how much the developer, province, and federal government received. The projects I would examine would be as follows:

• Greenfield mining project with and without an upgrader;
• Greenfield in-situ project with and without an upgrader;
• An upgrader;
• Expansion project (increase production by greater than 25%)
• Efficiency project (production remains unchanged, but costs decrease); and,
• Debottlenecking project (a variant of the prior two).

An initial step once these sample projects or scenarios were created would be to run each of these projects under two fiscal regimes with two parameters. Use the royalty and taxation regime that existed in the mid 1990s with the rates that existed in the mid 1990s. Next, do the same exercise, except with today's regime (there have been tweaks during the past decade) and today's rates. This exercise would clearly show how the values shares have shifted.

Then to arrive at a new fiscal regime to rebalance the proportional shares, various fiscal levers would be used to examine the percentage value shares (not the sum of undiscounted cash flows) to the developer, province, and federal government. If, by raising the provincial royalty, the federal portion decreased, then we know that is a likely nonstarter. I discussed this topic at length in a prior article.

Experiment and debate the relative shares to the different stakeholders until a satisfactory regime is reached. As part of that experimentation and debate, use the most efficient fiscal means possible. Recall that different stakeholders have different costs of capital. That allows some economic levers to be more efficient than others.

In summary, if I had been charged with the same assignment, I would have a) shown that the current sharing of economic value has shifted toward the developer and away from governments as the tax rates have decreased during the past decade; b) reviewed current events to set the stage for a dialog to determine the appropriate sharing going forward; c) reviewed risk and return profiles so that everyone has a common understanding of the risks taken by the oil sands industry with the expected net present value shares; d) use different fiscal levers to arrive a new regime that satisfies the agreed upon splits in the economic value pie value; and e) communicate to the public in a transparent manner throughout the entire process.

This is undoubtedly a difficult process to arrive at a fair and equitable fiscal regime. At the end of the process, not all parties will be satisfied. The key is to make the process as transparent and accessible to the public as possible. Given the increasing value of oil sands along with its environmental impacts, the public has right to have a full and open hearing. Creating a new fiscal regime is an extremely complicated process because of the need to consider the vast array of public policy issues and because of the importance to the economies of Alberta and Canada.

Calgary model Judith Aldama is featured in the photograph, which is hosted at Flickr. If you click on the picture of Judith, you will be taken to where you can view a larger version and see even more pictures of her.

The Panel in their document Alberta Review Panel Final Report (PDF, 2.25mb) proposed regime that is complex. More specifically, Panel recommended the following:

• During the prepayout period, the royalty is 1% of gross revenue.
• During the postpayout period, the royalty has two parts. First, the 1% of gross revenue from prepayout still applies. And second, the 1% gross revenue royalty is treated as a cost before an additional 33% net revenue royalty is applied. The net revenue is the gross revenue less 1% gross revenue royalty less operating costs and capital expenditures.
• Rather than attempt to summarize this last portion of the royalty, I will simply quote from page 13 of the report:

  Oil Sands Severance Tax (OSST) – The Panel recommends strongly that a severance tax, applicable to all oil sands projects, be introduced.

  The Panel views the OSST, applying to all Alberta bitumen production, as an absolutely essential component of a "fair" royalty system for Albertans. The Panel recommends:

  • That, for each project, an OSST be levied against gross revenues from bitumen production, with a floor applied to the bitumen price equal to 40% of the price of West Texas Intermediate ("WTI") in Canadian dollars. This floor price should remain in effect until a permanent "generic" bitumen methodology is in place, as discussed below;
  • That rentals, base royalty payments, and net revenue royalty payments be deductible from the base against which OSST is applied;
  • That the OSST rate be linked to the price of WTI in Canadian dollars, as follows:
    • Zero for WTI prices of less than $40/barrel;
    • 1% at $40/barrel, and growing by 0.1% for each $1/barrel increase in the price of WTI;
    • Reaches a maximum of 9% at $120/barrel, and stays at this rate thereafter;
  • That OSST payments not be considered eligible expenditures for purposes of calculating Payout, revenues for royalty purposes, and income for corporate tax purposes.

I will review the three components above. First, the prepayout of 1% gross revenue is the same as the existing regime. As a matter of principle, I dislike gross revenue royalties because they are not tied to profitability. I would rather have no gross revenue royalty with a higher net revenue royalty percentage in the postpayout phase. Most people, however, feel that a developer should pay something during the prepayout phase and 1% of gross revenue is an amount that is palatable to both the developer and the province. In summary, the 1% gross revenue royalty during prepayout is the same as the existing regime and most accept a low royalty during the prepayout phase.

As an aside, I discussed in prior articles that prepayout and postpayout are not singular one time events. If a developer loses money in a given year, the project goes back into prepayout until it climbs back out of the hole and earns the long term bond rate again. Why would a developer lose money in a given year? Low commodity prices, expansion projects, debottleneck projects, efficiency projects, extreme plant upsets, and labor disruptions are some of the potential reasons why a project might reenter the prepayout phase again. To add further clarification, an expansion project creates additional production capacity. A debottleneck project also increases production capacity by removing one or more of the project's constraints, such as insufficient upgrader capacity. An efficiency project reduces the cost of the production. Perhaps by adding more pots and pans the project can reduce its natural gas requirements and lower its operating costs. In effect, the royalty terms allow—more accurately, encourage—developers to look for opportunities to increase the value of the project to both the developer and the governments.

Moving along to the second bullet point, the postpayout phase has two components: the gross royalty of 1% and net revenue royalty of 33%. Again, I am not a big fan of gross revenue royalties. I am even less of a fan of combining these two measures together. I think it adds unnecessary complications. How much is the total royalty? The answer is, I do not know. I would have to get a pencil and paper and figure it out. I would prefer that the royalty were simply 34% or 35% of net revenue during the postpayout phase. Eliminate the gross revenue number and slightly increase the net revenue percentage value. Now, it is easy to understand. If you need to explain to someone what the royalty percentage is, then you can simply reply that the value is 34% of the net revenue which is the gross revenue less all costs. The Panel made this section needlessly complex with a dose of poor policy thrown in for good measure.

In an earlier article, I warned about having royalties above 25% without having the federal government at the negotiating table. You might need to reread my earlier article as a refresher.

The OSST is a whopper. I have discussed the bitumen versus synthetic crude oil royalty in a prior article. In this article, I will focus more on the numbers.

The OSST is a sliding scale royalty that is sensitive to oil prices. As oil prices move above C$40 per barrel for West Texas Intermediate (WTI) benchmark, a 1% an additional gross revenue royalty kicks in. It increases at 0.1% for every Canadian dollar increase in the price of WTI. At C$120 per barrel, the gross revenue royalty tops out at 9%, meaning that 9% is the highest percentage. Interestingly, this royalty is not eligible for payout calculations or as deductions for provincial and federal taxes.

This last royalty measure is intended to be an enhancement to the government for reasonably high oil prices. As the price climbs higher, the enhancement grows. That is the reason why it is not part of the payout calculations. The lack of deductibility for corporate taxation requires more explanation.

While I am not positive why the Panel chose to make the OSST ineligible as a deduction against corporate taxes, I can make a good guess. As the overall combined royalty and taxation levels increase, there is an incentive to gold plate. To demonstrate the incentive to gold plate, I am going to create an absurd example.

Stepping away from the oil sands industry for a moment, assume that a company operates in Alberta with combined provincial and federal tax rate of 30%. That implies that when the company spends money, it receives a shelter equal to 30% of the expense. Suppose a manager wanted to take his ten person team to Banff for a week of team building. After checking costs, the manager learned that he would have to pay approximately $1,000 per day per employee. So five days, ten employees cost his company $50,000. That $50,000 is an expense, so the real cost to the company is $35,000 (=70% times 50K).

Assume that the same manager with the same company and location had a combined provincial and federal tax rate of 90%. The real cost of that prior $50,000 expense is only $5,000 (=10% times 50K). So for $5K, he can take his entire team to Banff for the week. Because the cost is so low, why stop at Banff? Perhaps Macau is a more interesting and exotic location. The average cost per day, including airfare and hotel, is $5,000 per day per employee. The total costs is $250,000, but the real cost to the company is only a paltry $25,000 (=10% times 250K). Just imagine after five fun filled days of gambling and entertainment, his team will have sharpened its business acumen and will be refreshed to enjoy the new challenges at work.

The point of this absurd example is that, with higher taxes (or government take), developers can spend lavishly almost without consequence. There is no need to operate efficiently. There can be exorbitant travel and training expenses. Employees get the newest and best computers every six months, with new PDAs every three. To help ease the staff shortage while the team is away on various team building and training sessions, the developer can hire additional staff, because the real cost is only ten cents on the dollar.

I am assuming that the Panel chose to make the OSST exempt from royalty payout calculations as well as provincial and federal tax to prevent the gold plating and foolish spending. The OSST is an after-tax, direct hit to the bottom line.

What is wrong with this measure? First, the tax is paid even during the prepayout phase. A developer might be unfortunate in its timing. After construction is complete, oil prices are high (normally a very good thing) and the project is paying high royalties with no offset to delay postpayout or tax relief. Furthermore, once a project is up and running smoothly and prices spike up, the OSST might discourage developers from undertaking expansion, debottlenecking or efficiency projects. Because the OSST is soaking up a substantial portion of the cash flow, developers are unable to create large nest eggs to undertake these projects.

Without having run the numbers for various hypothetical situations, it is difficult for me to provide much more insight. My initial reaction is that the OSST appears very punitive. It is also unbalanced in that if times are extraordinarily good, the government take is extraordinarily high. If times are poor, too bad, soo sad.

To provide more meaningful insight, we would need to examine a typical greenfield project under various scenarios. And then we would need to examine the same project with secondary projects such as expansion, debottleneck, and efficiency. Then we could evaluate the harshness of the OSST.

There are some other royalty provisions, such as a 5% royalty credit for upgraders and such. I either have discussed these provisions in prior articles or have chosen to ignore them for our discussions.

In summary, the new regime is more complex and likely much harsher. The 1% prepayout is the same as before. The postpayout of 1% gross revenue royalty and 33% net revenue royalty is significantly higher than the existing 25% net revenue royalty is. Moreover, there might be severe issues with the federal government with a royalty rate in excess of 25%, because a higher royalty rate eats into its share of the economic pie. The federal government might be forced to cap the allowed royalty percentage to maintain its share of the pie. The OSST is complex in that it is a sliding scale starting at 1% at $40 WTI and ending at 9% at $120 WTI. This royalty is not eligible for postpayout calculations or as deductions for provincial and federal corporate taxes. Without having performed numerical analyses, the OSST appears punitive.

Model Linda T is featured in the photograph, which is hosted at Flickr. If you click on the picture of Linda, you will be taken to where you can view a larger version and see even more pictures of her.

For those interested in more discussion, particularly of a political nature, concerning the Alberta Royalty Review, I encourage you to read Ken Chapman over at his blog. I have not followed his blog closely; however, by reading several of his recent posts, I get the strong impression that he is a voracious reader with strong opinions. And, I note that he has some hecklers that participate in his comments, which is always a good thing. A few hecklers and doubters always spice up a blog.

I have largely ignored the political aspects of the Alberta Royalty Review. I have read and heard some media commentary on the Panel's work, but found the media coverage wanting. I do not think the media has a solid understanding of the issues, or how and the fiscal terms were created. Lacking a strong background, the media tends to parrot various sources.

Again, for those looking for more of a political interpretation and analysis of how the Royalty debate is progressing in Alberta, I urge to read Ken Chapman's blog.

In the report, the Panel showed various graphs for fiscal regimes around the world. These graphs, however, usually showed undiscounted cash flows. Perhaps that works well when comparing conventional resources, but not oil sands. Conventional production follows and exponential decline, meaning that most of the cash flow comes early in life. Oil Sands have a steady or increasing production with time, meaning that much of its cash flow comes later in life. Thus, undiscounted cash flow charts will overstate the "value" received by oil sands companies.

The Panel in their report Alberta Review Panel Final Report (PDF, 2.25mb) often use undiscounted cash flows to compare government takes in various jurisdictions. As a reminder from prior articles, government take is the proportion that the government charges or takes in the form of royalty and taxes. For example, assume that there is million dollars of cash flow after operating costs and capital expenditures have been paid. If the different levels of governments take seven hundred thousand dollars and leave the developer with three hundred thousand dollars, then the government take is 70% for that year.

The Panel uses the cumulative total cash flows over the life of different projects in various jurisdictions and then ranks them according to governments' takes. For the purposes of government takes, mixing oil sands regimes with conventional oil is wrong.

Before explaining why it is wrong, I need to explain a bit more about conventional oil and why the cumulative cash flow government take methodology is often employed by the conventional oil and gas industry. I am going to discuss decline rates, discount values, and then return to why the methodology is flawed when including oil sands. With that information as a background, I will then discuss marginal tax rates.

Conventional oil and gas production follows a decline curve. That is, after each year, the production flowing from that particular well declines following an exponential decline curve. The decline rates differ depending upon the geology and technology used to recover the oil and gas. In the table below, I have demonstrated the effects of different decline rates for a well with an initial production rate of 1,000 barrels per day.

Well Production With Given Decline Rates

	Daily Production in Barrels
Year	3%	5%	7%	10%
Source:	Kevin H. Stecyk
1	1000	1000	1000	1000
2	970	950	900	850
3	941	903	810	723
4	913	857	729	614
5	885	815	656	522
6	859	774	590	444
7	833	735	531	377
8	808	698	478	321
9	784	663	430	272
10	760	630	387	232
11	737	599	349	197
12	715	569	314	167
13	694	540	282	142
14	673	513	254	121
15	653	488	229	103
16	633	463	206	87
17	614	440	185	74
18	596	418	167	63
19	578	397	150	54
20	561	377	135	46
21	544	358	122	39
22	527	341	109	33
23	512	324	98	28
24	496	307	89	24
25	481	292	80	20
26	467	277	72	17
27	453	264	65	15
28	439	250	58	12
29	426	238	52	11
30	413	226	47	9

In looking at the above table, I want to draw to your attention how fast the production falls off. After ten years, the production has fallen off by roughly one quarter for the 3% decline rate well. For the 15% decline rate well, production has fallen by nearly three quarters. I recall reading that the average international well lasts for between 15 and 20 years. The key learning from this exercise is that the bulk of the cash flows come early.

For an oil sands project, its production profile is very much different. Its production actually tends to increase with time. That is, its production in later years is actually higher than during the initial years. Oil Sands projects are not subject to the same geological natural laws that govern conventional well. Oil sands projects—both mining and in-situ—are completely different from that of conventional. With time, oil sands projects tend to debottleneck and increase efficiency to increase production rates.

So why are the production rates important? Recall that earlier I discussed that for net present value (NPV), early cash flows are much more meaningful than later cash flows. If we value the cash flows, which are highly correlated to production, then conventional production sees relatively little discounting in comparison to oil sands production. Conventional production tends to last for 15 to 20 years with the vast majority of its production in the first ten years. The value of oil sands production is heavily discounted because its production tends to last 40 plus years with the vast majority of its production occurring after 15 years. Thus, from a value perspective, we cannot compare the value of conventional and oil sands production by simply adding up the cash flows. By doing so, we completely neglect the valuation—that is, the net present value—of the cash flows. Thus, undiscounted cash flow graphs give the impression of overstating the value received by oil sands projects.

The Panel's demonstration of government takes showing undiscounted cash flows from conventional and oil sands projects are misleading. While perhaps technically correct from an undiscounted cash flow perspective, from a true value perspective the graphs are meaningless. They present a specious argument. Rather the using undiscounted cash flows, the Panel should have used net present values. The key question is, How much value did the governments and developers receive in different jurisdictions?

If net present value graphs are the proper methodology, then why did the Panel not use them? While I cannot respond for the Panel, I can provide some additional insight that might explain their presentation.

The common practice in the oil and gas consulting game is to show conventional resources around the world using undiscounted cash flows graphs, similar to the graphs presented in the Panel's report. From earlier articles, recall that the discount rate is a proxy for risk. Different countries have different risks associated with them. Angola, Nigeria, Venezuela, Russia, North Sea, Gulf of Mexico and various other oil rich regions all have different risks. The problem is, analysts all view and quantify these risks differently. If a company has been operating in a risky region successfully for many years, it might deem its risks low as it has learned to work cooperatively with the government officials and thus does not perceive much risk. A new entrant might view the risk as substantial. Moreover, different developers will view the geological risks—that is, the prospectivity of the region—differently. To avoid the risk discussion, consultants use undiscounted cash flows. If a well is drilled in the North Sea or off the coast of Angola, its production will still decline with time. Analysts can overlay their own risk profile on the undiscounted cash flows. Setting aside the risk argument for a moment, the analyst can see how different regions of the world stack up with respect to government take.

The problem, again, for including oil sands in the same basket for comparison purposes is that oil sands production does not follow the same decline rate. So drilling off the coast of Angola or the North Sea is not the same as an oil sands project. Again, the vast majority of production from a typical international oil well occurs within the first ten years. For an oil sands project, the vast majority occurs after 15 years.

Another wrinkle is that the discount rate for the governments and the developer are different, even for the same project. One reason is that government still has less risk. For example, if oil price plummets, the oil sands developer is hurt severely. The government is somewhat hedged in that manufacturing, tourism, transportation and other sectors that consume oil will become more profitable. So while the government loses taxes from the oil sands industry, it gains taxes from others. Is the offset one-for-one? I doubt it. A silly example is to imagine the government as a vendor selling suntan lotion and umbrellas on the beach, while the developer as a vendor only selling suntan lotion. Regardless of the weather, the government with its two products will have sales. The developer needs the sun to shine. Another reason is that government can raise capital more cheaply than the developers can. The government long term bond rate has less yield than a similar corporate bond rate. Yet, another reason is that the governments always have the ability to raise taxes to meet shortfalls. Developers are the mercy of oil prices. So for all these reasons, the governments enjoy a lower discount rate than do the developers.

In summary, when comparing government takes, we need to compare the value received by the governments and developers to arrive at a meaningful comparison when mixing conventional and oil sands projects together. When performing an international comparison, this task is almost impossible. And perhaps that is why the Panel took a shortcut and ignored values and simply provided undiscounted cash flows. This methodology presents a visual picture where the developer's take is overstated from a valuation perspective. Thus, for government take comparisons, undiscounted cash flows provide irrelevant information.

Our last topic is marginal effective tax rates. Marginal tax rates are often helpful because we can view how severe or onerous the terms are. Again, we can compare across different fiscal regimes. The challenge, of course, is that fiscal regimes are structured differently and that can make marginal tax rate information less relevant. For Alberta oil sands projects, the developer is allowed to recoup its investment rapidly because the 25% royalty is not imposed until payout. It was even more rapid before when accelerated capital cost allowance was permitted. If we look Panel's set of recommendations, the same general structure is still present. That is, the developer is allowed to reach payout—all its capital investment returned inflated at the long term bond rate—before paying the higher royalty amounts. If a developer were allowed to recoup its investment early, one would expect to see a higher tax and royalty rate at the end. In effect, the developer has reduced its risk by receiving its cash early and now it is payback time. So under this scenario, marginal effective tax rates can be somewhat misleading.

To make the preceding paragraph clearer, imagine the following two scenarios: One, a developer is allowed to pay no taxes and no royalties until it has earned 20% on its investment, which is expected to occur in year 10. Two, a developer pays 30% net profit royalty with no shielding and pays a combined provincial and federal tax of 30% from day one. In year 11, which scenario should have a higher combined royalty and total tax rates? I think most would argue that under Scenario One, the developer has received a great benefit from paying no taxes and royalties and now it is payback time. If you were to look at the marginal effective tax rate in year 11 when the developer in Scenario One is paying high rates for royalty and taxes, you might be tempted to conclude that Scenario One is onerous. In fact, it is likely generous because the developer was allowed to earn a high return before paying anything. Its risk was greatly reduced. The key point from this example is that marginal effective tax rates will, in many cases, fluctuate throughout the life of the project and that looking at any one year can provide a misleading picture. Instead, we need to consider how much value the governments and developers earn over the lives of different projects.

The last statement is really the summary statement for the entire article. That is, when examining the fairness of a fiscal regime, we need to examine the governments' and developers' net present values over the lives of different projects. Then we can judge whether they receive an appropriate share. Using undiscounted cash flow and marginal effective tax rates can and do provide incomplete and misleading conclusions.

Model Linda T is featured in the photograph, which is hosted at Flickr. If you click on the picture of Linda, you will be taken to where you can view a larger version and see even more pictures of her.

To set the stage, I quoted below from pages 14 and 13, respectively, of the Alberta Review Panel Final Report (PDF, 2.25mb):

Bitumen Pricing – As noted earlier, there are no well functioning markets for bitumen and the interests of Alberta bitumen producers are not all the same with respect to the price received for their product: production-only developers prefer high bitumen prices, while lower bitumen prices (relative to those for SCO) are in the best interests of integrated producers. "Let the market decide" appears unlikely to resolve this issue in the best interests of Albertans.

For hard-to-price commodities like bitumen, formula-based approaches based on published prices for correlated surrogate commodities are common throughout the world as price setting mechanisms. The Panel believes the Government's best option rests with such an approach to pricing bitumen.

A permanent, generic "bitumen valuation methodology" (BVM) applicable to all calculations requiring such a value, used by all participants in the exploitation of Alberta's bitumen resources where a bitumen price needs to be calculated, should be put in place by 30 June 2008. It would replace all current or intended uses of temporary BVMs and alternatives to the permanent BVM would not be allowed.

In very strong terms, the Panel recommends that a truly independent, unconflicted, world-renowned and highly experienced advisor be hired to consult widely, consider relevant international practices and then develop a permanent BVM. Consultation for this purpose, as a point of clarification, would not entail or imply negotiation nor is it intended to introduce any sense of 'veto' power or 'consent' requirement on the oil sands industry. As described above, there are simply too many competing interests, too little time left before a BVM is required, and resolving the issue is too fundamental to Alberta's economy (certainly in the sense of the Treasury of the Province) to continue to leave this issue in limbo or to put the province at risk of hitting an impasse with industry.

The Panel recommends, without limitation but by way of example, that the valuation methodology obtained from this process be applied to all bitumen produced in the province for purposes of determining Payout and for calculating base royalties, and OSST payments. Once a permanent BVM is in effect, the bitumen floor device described above for determining OSST can be lifted, in favor of the new methodology.

From page 13, the Panel states the following:

Oil Sands Severance Tax (OSST) – The Panel recommends strongly that a severance tax, applicable to all oil sands projects, be introduced.

The Panel views the OSST, applying to all Alberta bitumen production, as an absolutely essential component of a "fair" royalty system for Albertans. The Panel recommends:

• That, for each project, an OSST be levied against gross revenues from bitumen production, with a floor applied to the bitumen price equal to 40% of the price of West Texas Intermediate ("WTI") in Canadian dollars. This floor price should remain in effect until a permanent "generic" bitumen methodology is in place, as discussed below;
• That rentals, base royalty payments, and net revenue royalty payments be deductible from the base against which OSST is applied;
• That the OSST rate be linked to the price of WTI in Canadian dollars, as follows:
  • Zero for WTI prices of less than $40/barrel;
  • 1% at $40/barrel, and growing by 0.1% for each $1/barrel increase in the price of WTI;
  • Reaches a maximum of 9% at $120/barrel, and stays at this rate thereafter;
• That OSST payments not be considered eligible expenditures for purposes of calculating Payout, revenues for royalty purposes, and income for corporate tax purposes.

At present, bitumen pricing is an opaque process. A buyer and seller come to terms for a quantity of bitumen with a specified quality to be delivered over a specified period. Those terms are confidential between the parties. The Panel wants to make bitumen pricing more transparent—in effect, make bitumen a fungible commodity.

The problem is that every project produces unique bitumen. Syncrude's bitumen is different from Suncor's which again is different from Shell's and so on. Each project's bitumen will be priced differently and is worth a different value to different upgraders. Some bitumen will contain more fines (sand and clay particles) than others, some will have more sulfur content than others, and so on. The upgraders receiving the bitumen will be configured to accept the known qualities of their purchased bitumen and thus will price it appropriately. In summary, there is tremendous challenge in trying to develop a transparent marketplace.

With that as a background, I will comment on the Panel's statements. I will begin by addressing a permanent, generic BVM. I have seen one version of a BVM by the Alberta Department of Energy. It was a complex multiple regression analysis equation. In short, it made no sense. Regression analysis always depends upon the factors thrown into the mix. And what might hold true today, might make absolutely no sense tomorrow. It does not explain cause and effect. Rather than a complex multiple regression analysis equation that practically nobody understands, a BVM should be transparent and understandable.

A transparent and understandable BVM is still overwhelmingly difficult. Earlier I discussed the different qualities of bitumen produced by each project. That is one hurdle. Another hurdle is that how would the fiscal regime manage temporary gluts and surpluses? For example, assume for a moment that Syncrude's upgrader had a huge fire—it has happened before—and that Syncrude's bitumen is now on the marketplace. Spot market bitumen prices in Alberta have just plummeted. Should those independent mines coupled with independent upgraders with long-term contracts be able to reset their bitumen prices for royalty purposes? Do integrated producers suddenly benefit? Should one party (independent mines and upgraders versus integrated producers) be treated differently than the other? Do smaller independent mines without long term contracts benefit? If any of these parties benefits, smart lawyers, accountants, and royalty specialists will create mechanisms that allows all parties to arbitrage from short term aberrations in the marketplace. If no parties benefit, then Alberta will be deeming unrealistic prices. There is no solution that satisfies everyone.

Moreover, I find it odd that Alberta could witness record highs in WTI prices, yet record lows in bitumen prices because of a plant upset. That upset then has the potential to cost not only the direct affected projects, but also cost Alberta less royalties from all projects.

Another solution is simply to set bitumen prices as a percentage of WTI. The challenge is a) to determine an appropriate percentage, and b) to recognize that upgraders do not cost a percentage of WTI prices to process the bitumen but rather a fixed and variable cost. That is, the cost to process bitumen might be $15 for Upgrader Z regardless of the WTI price. Each upgrader will have a different cost structure. And each upgrader's cost structure will differ over time.

Another challenge with having a bitumen priced regime is that Alberta could find itself in a position whereby upgraders are marginal businesses, yet mines are highly profitable (see an earlier article). Developers would then be faced with the challenge of building an expensive yet marginal return upgrader in order to develop the mine and thus to make the whole project viable. In other words, without an upgrader, there is no project. Thus, with a bitumen based royalty, Alberta might kneecap future projects from building an upgrader simply because upgraders have returned to their normal marginal rates of return.

Under existing rules, a project can elect to use bitumen or synthetic crude oil (SCO) based royalty regime. Then, if upgraders do return to being marginal businesses, projects can elect to throw the whole mix into the royalty ring fence to reduce the overall risk of the project (thus, ensure viability) and to increase the project's return.

I will address the OSST in a separate article. I included the OSST quote in this article because the OSST is integral to the bitumen pricing. As we see from the OSST quote above, the Panel has chosen an arbitrary value of 40% of WTI price for bitumen as a temporary measure. The 40% of WTI price for bitumen is of pivotal importance, yet do we know if this value is appropriate or correct?

Moving on to a different segment, a truly independent, unconflicted, world-renowned and highly experienced advisor would be hired. Where would Alberta find such an esteemed individual? Oh wait, we have one working on the Panel. I wonder if he would be interested? Given some of the glaring problems with this report, I am not sure that a truly independent, unconflicted, world-renowned and highly experienced advisor is the best route to follow.

In summary, there are extreme challenges in developing a transparent bitumen market. Each project produces a unique quality of bitumen, and each upgrader has been configured to optimize its incoming feedstock. Different upgraders will value the same bitumen differently, depending upon their configuration and their other feedstocks. If Alberta resorts to using a multiple regression type analysis for pricing, the price will not be understandable or stable over time. Nobody will have a solid understanding as to how price was arrived at or when the inputs need to be reevaluated. Moreover, bitumen prices are volatile and can be affected by plant upsets. It is conceivable—indeed likely—that Alberta will at some point experience extreme high oil prices and low bitumen prices. The low bitumen prices would result from an extreme plant upset. If Alberta only applies spot pricing to those projects that are using spot prices, smart professionals will create arbitrage mechanisms. If Alberta deems a bitumen price, then Alberta might be providing an artificially inflated price for the industry. Using a bitumen based royalty regime, Alberta might kneecap future projects that require an upgrader when upgraders are earning normal marginal rates of return. As a temporary measure, the Panel recommends that a 40% of WTI price be used for bitumen valuation. Is this value fair and reasonable to all parties? And last, the Panel recommends a truly independent, unconflicted, world-renowned and highly experienced advisor to help solve this mess. Given the quality of the Panel's report, I am dubious that a truly independent, unconflicted, world-renowned and highly experienced advisor will provide the answers needed.

Model Linda T is featured in the photograph, which is hosted at Flickr. If you click on the picture of Linda, you will be taken to where you can view a larger version and see even more pictures of her.

Ian Langdon has an informative blog WTF Journal where he writes about issues facing Alberta. Naturally, many of his recent posts concern the Alberta Royalty Review. His blog is a great resource and highly recommended for finding current commentary.

As preparation for this article, I encourage you to read my prior article about Syncrude Canada Ltd. and Suncor Energy Inc. (SU) moving away from a synthetic crude oil (SCO) based royalty to a bitumen based royalty. In my prior article, I explained that I expected that Alberta would put a clawback measure in place to recapture the royalty sheltering that occurred when the companies used their capital spending on their upgraders as part of their royalty deductions. A reader wrote to me and highlighted a recent presentation by Canadian Oil Sands Trust (COS-UN.TO) at Scotia Capital's Energy Trusts Conference. On page 11 of their presentation, Canadian Oil Sands Trust states:

The outstanding issues that need to be resolved before making our determination is a methodology for valuing bitumen and how capital invested for the upgrader would be recaptured.

This quote is in relation to how Syncrude would move from an SCO based royalty to a bitumen based royalty. One challenge is to value properly the bitumen, which I will discuss in a future article, and other challenge is to recapture the lost royalty because of the prior upgrader investments. Knowing that Syncrude is already involved in negotiations, I assume that Suncor had or will have similar negotiations. Thus, my prior expectation appears correct in that the Alberta government will put a clawback mechanism in place for those companies that elect to move from a SCO to a bitumen based royalty.

Moreover, on page 15 of Alberta Review Panel Final Report (PDF, 2.25mb), the Panel states:

Upgrader Royalty Credit - Even though it cannot do so unanimously, the Panel recommends that a tradeable royalty credit be introduced at a rate of 5% of eligible capital expenditures on additional upgrading capacity in Alberta. This would only apply for projects whose application to construct and operate an oil sands upgrader is approved by the Energy and Utilities Board (or successor agency) after the bitumen valuation methodology is in place (30 June 2008 indicated above).

This recommendation is poor. I understand that the recommendation's purpose is to encourage upgrader construction in Alberta. In my view, that thinking is flawed. Upgraders are often poor investments. Upgraders and refiners to have production creep whereby upgraders and refiners to expand their production capabilities and reduce their cost structures such that the investments earn only a marginal rate of return. Because of the flood of oil sands production, there is currently a glut of heavy oil in the marketplace and thus a high differential between heavy and light oil. That glut, however, is not expected to endure. When glut of heavy oil is no longer present as new upgraders come on stream, the marketplace will become more balanced, and the high rates of return now enjoyed by upgraders will be diminished greatly.

With an anticipated balanced heavy oil and upgrader marketplace, imagine the following scenario: Oil prices are at record highs at over $100 per barrel yet upgraders are earning marginal but acceptable rates of return. Oil companies are enjoying record profits. Alberta consumers are feeling the pinch of higher energy prices. And those same consumers are subsidizing oil companies' investments in their marginal upgrader projects by virtue of granting those projects 5% royalty credits. Maybe it is just me—but I do not see why Albertans should be asked to subsidize an industry making record profits from a non-renewable resource.

In this article, I covered two topics: one, synthetic crude oil versus bitumen election; and two, upgraders and upgrader credits. Both topics involve upgraders and seemed to fit logically together. On the first topic, there are implications from moving from an SCO to a bitumen based royalty scheme. And in the second topic, the Panel tried somehow to allow companies to enjoy a bitumen based royalty scheme and enjoy a kicker from building an upgrader in Alberta regardless of their profitability. I find it odd that Alberta would want to recapture its lost royalty because of a switch from an SCO based royalty to a bitumen based royalty but would grant an incentive for building upgraders. The two actions seem at odds.

Disclosure: I am long Suncor stock and Canadian Oil Sands Trust Units.

Model Linda T is featured in the photograph, which is hosted at Flickr. If you click on the picture of Linda, you will be taken to where you can view a larger version and see even more pictures of her.

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.

 

 

 

 

 

Alberta Oil Sands Federal Taxation

Line Number	Description
Source:	Kevin H. Stecyk
Line 1	Gross Revenue
Line 2	Less: Operating Costs
Line 3	Preliminary Net Income One
Line 4	Less:
Line 5	Capital Cost Allowance (CCA) 41A
Line 6	Capital Cost Allowance (CCA) 41B
Line 7	Equals: Resource Profit Before Allowance
Line 8	Less:
Line 9	Additional Class 41A CCA Deduction
Line 10	Resource Allowance
Line 11	Canadian Exploration Expense (CEE)
Line 12	Canadian Development Expense (CDE)
Line 13	Equals Preliminary Net Income Two
Line 14	Less: Loss Carryforwards
Line 15	Equals Preliminary Net Income Three
Line 16	Less: Taxes Paid
Line 17	Equals Federal Net Income

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.

Edmonton model Nikki G is featured in the photograph, which is hosted at Flickr. If you click on the picture of Nikki, you will be taken to where you can view a larger version and see even more pictures of her.

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.

Edmonton model Nikki G is featured in the photograph, which is hosted at Flickr. If you click on the picture of Nikki, you will be taken to where you can view a larger version and see even more pictures of her.

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?

Calgary model Judith Aldama is featured in the photograph, which is hosted at Flickr. If you click on the picture of Judith, you will be taken to where you can view a larger version and see even more pictures of her.