October 2007 Archives

Great minds think alike. Below are the links to two great minds on the outlook for the American currency:

• Wall Street Journal Video Interview With Pimco's Bill Gross; and
• Bloomberg Transcript of Beeland Interests Inc.'s Jim Rogers.

Both individuals are extraordinarily bearish on their outlook of the American dollar. Whether you agree with their assessments, both sources are worth investigating further.

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.

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.

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.

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.