Recently in Calgary Category

Last Sunday, EnCana Corporation (ECA) decided to split into two parts, with one part focused on natural gas and the other part on oil sands. While most financial journalists and analysts thought highly of EnCana's move, I think differently.

Those who believe EnCana's move was a smart decision point to increased focus and investors' ability to pick and choose which asset group they want in their portfolio. And, of course, many point to the two smaller sized companies being more attractive as take-over targets. My arguments for opposing EnCana's decision are almost the same. The natural gas and oil sands provided diversification. For example, if natural gas continues to be a weak commodity for several years, then investors in EnCana can enjoy the strong oil sands performance. Of course, some would argue that investors who want diversification could still buy stock from each company and thereby enjoy the diversified benefits. I am not sure, however, that having stock in each separate company provides the same benefit of having just one company.

Suppose, for example, that natural gas prices were fall substantially, both in absolute and relative terms, for several years. EnCana's natural gas might be forced to batten down the hatches while it rides out the storm. If the company remained whole, then the company might be better positioned to use its financial resources from the oil sands to purchase inexpensive natural gas assets.

While I agree that because EnCana's two separate pieces are now better (and easier) takeover targets, that is a bad thing. We Canadians have already lost too many of our resource company to foreigners. Although a strong supporter of free trade, I would like to have at least some our world class natural resource companies remain Canadian. My preference would be for EnCana to be an opportunistic acquirer rather than an aquiree.

In fact, if we look at recent history, we see larger oil and gas companies trying to get bigger, not smaller. ExxonMobil Corporation (XOM), ConocoPhillips Company (COP), and BP p.l.c.'s (BP) takeover of Amoco are all recent examples of giant energy companies having become even larger.

All that said, if we look at how EnCana performed relative to Canadian Natural Resources Limited (CNQ) or Suncor Energy Inc. (SU), we see that there is almost no difference. Last week, they all performed strongly and closed within a few percent of each other. That hardly seems like a ringing endorsement of EnCana's latest strategic maneuver.

I am long stock of EnCana, Suncor, and ExxonMobil.

My photograph of the Bow River Falls is hosted at Flickr. If you click on the picture, you will be taken to my Flickr account where you can see more pictures.

I have been extraordinarily busy this past week, so I did not watch the markets as closely as I normally do. I did, however, purchase more oil stocks and stocks in a couple other sectors. Although I did not load up the proverbial boat with oil stocks, I might further increase my exposure soon. Those who follow my blog know that I am an oil bull, believing that oil prices will continue to rise because of the inability to match supply with demand at current prices. However, there might be some further downward pressure on oil stocks as northern hemisphere enters the spring season and the demand for oil is temporarily lessened. Of course, the current market turbulence might further add to the downward pressure.

That said, I believe that the stocks of oil companies are unlikely to fall much further. Put differently, there is much more upside than downside, especially as you lengthen your time horizon beyond one year. As time progresses, the world demand for crude oil will continue to increase. As the volume of oil consumed increases, the amount of crude that must be found just to replenish the natural decline of existing oil fields also increases. And then, more oil must be found to satisfy the increased global demand. Thus, those companies that have large reserves should do well.

The photograph of Model Linda T is hosted at Flickr. In this photograph, Linda posed in front of a train in the Heritage Park train roundabout. (See Google map:
View Larger Map.) If you click on the picture of Linda, you will be taken to my Flickr account where you see even more pictures of her.

Doug Kass, general partner of Seabreeze Partners Management, Inc. and commentator for The Edge Column on RealMoney Silver (subscription required—part of TheStreet.com family) covered his short position in Zale Corporation (ZLC). I followed suit.

In an earlier article, I provided my rationale as to why I was considering covering my short position in Zale early in the New Year. Now that the stock has fallen even more and because Doug Kass mentioned that he is getting out of the short position, I am ringing the register and closing my short position as well. I shorted Zale in March of 2007 and I covered today. You can see the Yahoo chart on Zale's stock price movement since March 2007.

Calgary model Judith Aldama is featured in the photograph above, 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.

Disclosure: No position in Zale.

The New York Times has an interesting article Remaking The Journal (free registration required) that hints at possible changes to the The Wall Street Journal. As a subscriber to the Wall Street Journal, I was saddened when it got taken over News Corporation (NWS), because I fear it will suffer the same fate at CNN. When Ted Turner ran CNN, it was edgy and interesting. Along came AOL with its remaking of CNN and removing the edge. While it might have enjoyed a wider audience, it also became less informative and interesting to watch. I fear the same thing happening to the Wall Street Journal.

Mr. Murdoch has said that he wanted The Journal to step up its coverage of politics and national and international affairs, making it a more direct competitor to The New York Times. He has lobbied for more hard news and more succinct articles — a marked shift in tone for a newspaper whose signatures include long, often quirky news features that start on the front page.

There has even been talk of a front page with articles short enough to start and end there rather than continuing on inside pages, and of taking the words “Wall Street” out of the paper’s name to give it broader appeal, according to people who have been briefed on the matter. Both ideas were quickly dismissed, but the fact that they were raised even semiseriously shows how unconstrained by tradition the new owner is, these people said.

...

None of that should be surprising from Mr. Murdoch, who is known for being sure of what he wants to do with each of his many properties — often molding them to reflect his own views and wasting no time in doing it. His habit of detailed, personal control contrasts starkly with decades of hands-off ownership by the Bancroft family, which viewed almost any involvement as unethical meddling.

I, for one, often enjoy the front page, long quirky articles. I find those articles to be a refreshing break from the constant barrage of facts, figures, and strong opinions. Moving along to the free with advertising versus subscription based model, I favor the latter. I do not want to be constantly bombarded with advertisements that I need to move out of my way to read an article. I prefer a clean, uncluttered look. In my view, the online WSJ has a balanced approach now with advertising and content. One partial solution that I do like is Barry Ritholtz's solution of allowing the archives to flow freely. In essence, paid subscribers receive current content, while all are allowed to read older content supported by advertisements.

Given that I do not support some of the initiatives outlined in the New York Times article, does that mean I was content with the status quo? No, not at all. I recognize that the news media is a business. Thus, it must be profitable. The Dow Jones with its Wall Street Journal had been languishing for too long—in fact, that is the reason why the Bancroft family accepted Murdoch's offer. So change was inevitable, just a question of what and when. Myself, I would have preferred making the newspaper more informative and more insightful. I would have preferred to see more in depth articles. I am not sure how to translate those broad generic sweeping generalizations to something concrete. And perhaps that was the problem—those running the Wall Street Journal did not know how to make the appropriate changes either. So now we will have to sit and wait for Rupert Murdoch to make his changes.

Calgary model Judith Aldama is featured in the photograph above, 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 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.

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.

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.

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.

In my prior article, I discussed oil sands royalty regime. In this article, I am going to discuss the taxation regime. Having a solid understanding of both royalty and tax will allow us to better understand Alberta Review Panel Final Report (PDF, 2.25mb).

As before with the royalty discussion, I am going to focus on the high level material only. I am not going to address the minutia.

Once again, I provided a table below with line numbers and item descriptions. Each line will be described in more depth shortly. Please note, the official terminology used by the Alberta and federal governments might differ from my presentation below. I am using the basic terminology that I used when I created the economic models for the NOSTF. If you are unsure of the terms operating costs and capital expenditures, please refer to my earlier article referenced above.

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

Below I will discuss each line in the above table.

Line 1: Gross Revenue. Gross revenue is the quantity multiplied by price. The quantity is either synthetic crude oil (SCO) or bitumen and the price is the price of the commodity. In the future, I will discuss the SCO versus bitumen. At present, I believe all integrated developers—that is, mining plus upgraders—use SCO pricing and mine developers use bitumen pricing. The mine producers do not produce SCO, so bitumen pricing is obvious. I will comment in the future on bitumen pricing too.

Line 2: Less: Operating Costs. Operating costs are deducted.

Line 3: Equals Preliminary Net Income One. This line simply shows the result of subtracting operating costs from gross revenues.

Line 4: Less. This line sets up the CCA deductions that come next.

Line 5: Capital Cost Allowance (CCA) 41A. Most initial capital expenditures for a mine or an upgrader with an SCO royalty regime are classified as Class 41A. Class 41A, as we will learn in a moment, is a supercharged depreciation class. I am going to cover more about capital cost allowances (CCA) in a future article. For now, CCA is simply the tax deductible expense for capital expenditures. Most new construction capital expenditures fall into this category, capital expenditures associated with expansions of greater than 5%, and capital expenditures in excess of 5% of gross revenue. New capital expenditures by definition represent a new project so those expenditures qualify for a supercharged write-off. Significant plant expansions also qualify for a class 41A treatment. If a developer spends more than 5% of gross revenue, an amount that is typically equal to the maintenance capital, then the regime assumes that the developer is spending capital to reduce the cost structure. Effectively, class 41A is meant to capture significant capital expenditures in the forms of new greenfield projects, major production expansions, and major cost reduction programs. On Line 5, 25% of the class 41A capital expenditure is expensed. That means it is deducted in a similar manner to operating cost.

Line 6: Capital Cost Allowance (CCA) 41B. This is similar to class 41A capital expenditures above, but these capital expenditures are not typically associated with new greenfield projects, major expansions, nor cost reduction programs. Instead, 41B capital expenditures are typical maintenance capital projects. Every year, the plant must replace motors, pipes, and other pieces of equipment. These capital expenditures are typically classified as 41B. On Line 6, 25% of the class 41B capital expenditure is expensed. The difference between CCA 41A and CCA 41B will become apparent in a moment.

Line 7: Equals Resource Profit Before Allowance. This line represents the gross revenue less operating costs, less CCA 41A and 41B deductions.

Line 8: Less. This line sets up additional deductions.

Line 9: Additional Class 41A CCA Deduction If Line 8 is positive and there is additional CCA 41A capital that has not been deducted, then it can be deducted here. In effect, CCA 41A capital qualifies for 100 % deduction. It is as though CCA 41A were an expense and not capital. By taxation standards, this is an extremely rich and aggressive deduction. Please note, recent budgets have changed this provision. This discussion relates back to the NOSTF.

Line 10: Resource Allowance. If, after deducting the Additional Class 41A capital, the sum total is still positive, then a resource allowance deduction of 25% is taken. Resource allowance was a proxy for provincial royalty. Note that regardless of the actual royalty amount, even if only 1% of gross revenue, the resource allowance of 25% still applied. This feature too has changed with recent federal budgets.

Lines 11 and 12: Canadian Development Expense (CDE) and Canadian Exploration Expense (CEE). These are capital expenditures associated with purchasing and quantifying the oil sands reserves. CEE is depreciated at 30%. Compared to 41A and 41B capital, CDE and CEE capital expenditures are small. CCA 41A and CCA41B account for greater than 95% of all capital, so Lines 11 and 12 are not important.

Lines 13: Equals Preliminary Net Income Two. This line is a subtotal.

Lines 14: Less: Loss Carryforwards. If Line 13 is a negative value, it creates a loss carryforward. Loss carryforwards can be applied against future income for up to seven years. Loss can also be applied against prior income for a period of up to three years. For our purpose, we will simply focus on the forward loss carryforwards.

Lines 15: Equals Preliminary Net Income Three. This line is the sum after applying the loss carryforwards. If this sum is positive, then taxes are paid in the next line. If the value is negative, then nothing happens.

Lines 16: Less Taxes Paid. If Line 15 is positive, then the tax rate is applied to the positive value and tax is paid. The federal tax rate, in the mid 1990s, was 29.12%, including large corporation surtax. The tax rate has changed and I will comment in a future article.

Lines 17: Equals Federal Net Income. Gross revenue, less all deductions, less taxes equals Federal Net Income.

The presentation above is for a new company starting a greenfield development. There are flow through intricacies for developers who are expanding or who existing companies entering the oil sands industry. While these rules are very important for developers, they are beyond the reach of this article. The above information provides a solid basis for understanding the federal taxation regime that was present in the late 1990s.

Below I have provided a table for the Alberta taxation. I will not comment on each of the lines because the provincial and federal taxation calculations are very similar.

Alberta Oil Sands Alberta Taxation

Line Number	Description
Source:	Kevin H. Stecyk
Line 1	Gross Revenue
Line 2	Less:
Line 3	Operating Costs
Line 4	Class 41A CCA
Line 5	Class 41B CCA
Line 6	Maximum of Royalty or Federal Resource Allowance
Line 7	CEE (from provincial pool)
Line 8	CDE (from provincial pool)
Line 9	Equals Preliminary Provincial Taxable Income 1
Line 10	Less: Loss Carryforwards
Line 11	Equals: Preliminary Provincial Net Income 2
Line 12	Less: Taxes Paid
Line 13	Provincial Net Income

The operating costs as well as CCA 41A and CCA 41B are the same for the federal taxes. The maximum of royalties paid or resource allowance might allow for some differences. Those differences, if any, affect the remainder of the calculation. The provincial tax rate was 15.5%. That too has changed and will be discussed later in a future article.

The tax calculation is more complex than the royalty calculation. That said, it is neither overly complex nor difficult. One of the superchargers was the 41A immediate write-off of capital expenditures. When economics are tight, that provision is of huge benefit to a developer. I will be addressing the CCA 41A issue soon in a future article.

When working through the federal tax, I mentioned that the resource allowance was a proxy by the federal government for provincial royalty. This is an important point to keep in mind. With the resource allowance, which has been changed, the federal government effectively limited the Alberta's ability to raise its royalty. The federal government only allowed a 25% deduction. If the province raised its royalty beyond 25%, the federal government would not recognize the additional amount above 25% as a federal deduction. Each government wants its piece of the economic pie.

Another set of important points are the historical federal and provincial tax rates. The federal rate, including large corporation tax, was 29.12% and the provincial rate was 15.5%.

With an appreciation of the historical oil sands fiscal regime, we are now better positioned to understand the Alberta Royalty Review and to provide comments. I will provide another article again on Monday, Columbus Day in the U.S. and Thanksgiving Day in Canada. The article will outline my general impressions of the Alberta Royalty Review, and then I write follow-up articles to provide more detail.

If you have questions, feel free to leave a comment or contact me through e-mail.

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.

Before I begin commenting directly on the Alberta Review Panel Final Report (PDF, 2.25mb), I will outline in high level terms the National Oil Sands Task Force (NOSTF) Alberta Oil Sands Royalty. Ultimately, we need to consider how the oil sands royalty and taxation work together. For this article, however, I will focus on the oil sands royalty and in the next article I will focus on the taxation.

I should point out that there have been tweaks made regarding ringfencing and other provisions. I am not going to address the minutia. Rather, I will focus on the higher level topics that allow us to understand the Alberta Royalty Review.

I provided a table below with line numbers and item descriptions. Each line will be described in more depth shortly. Please note, the official terminology used by the Alberta government might differ from my presentation below. I am using the basic terminology that I used when I created the economic models for the NOSTF.

Alberta Oil Sands Royalty

Line Number	Description
Source:	Kevin H. Stecyk
Line 1	Gross Revenue
Line 2	Less:
Line 3	Operating Costs (Opex) Deduction
Line 4	Capital Expenditure (Capex) Deduction
Line 5	Equals: Net Revenue Before Adjustments
Line 6	Less: Loss Carryforwards, if any
Line 7	Equals: Net Revenue Before Royalty
Line 8	Less: Greater of 1% Gross Revenue OR 25% Net Revenue Before Royalty
Line 9	Equals: Net Revenue

That table does not look too difficult to understand, does it? Let us look at each row and see what we learn.

Line 1: Gross Revenue. Gross revenue is the quantity multiplied by price. The quantity is either synthetic crude oil (SCO) or bitumen and the price is the price of the commodity. In the future, I will discuss the SCO versus bitumen. At present, I believe all integrated developers—that is, mining plus upgraders—use SCO pricing and mine developers use bitumen pricing. The mine producers do not produce SCO, so bitumen pricing is obvious. I will comment in the future on bitumen pricing too.

Line 2: Less. This line simply sets up the deductions.

Line 3: Operating Costs (Opex) Deductions. In a future article coming shortly, I will discuss operating costs and capital expenditures. For those unfamiliar with this terminology, operating costs are those costs for items that are used or consumed in a short period of time. Three large categories of operating costs are labor; energy; and supplies, such as huge tires for trucks, catalyst for the upgraders, and other consumables.

Line 4: Capital Costs (Capex) Deductions. Capital deductions are those expenditures generally associated with infrastructure. The costs of building the mine, extraction, utility, and upgrader facilities are all capital.

Line 5: Net Revenue Before Adjustments. This line is simply gross revenue (money in) less all costs (money out). During the initial construction phase, this number is negative. During subsequent construction phases, this number may or may not be positive, depending on how large the subsequent construction phase is relative to on-going operations and the current price environment. During normal, steady state operations, Line 5 should be positive, unless the pricing environment is extremely adverse.

Line 6: Less: Loss Carryforwards, if any. First we need to understand loss carryforwards. If Line 5 above is negative, it creates or is added to loss carryforwards. The loss carryforwards is carried forward to the following year and increased by the long term bond rate, which is about 6%. In effect, this loss carryforwards represents how much the developer is recently out of pocket. Why is it recently? During the initial construction phase, the developer creates a large loss carryforward as it builds its plants. After several years of normal operation, the loss carryforward is depleted. The developer then might earn several years of good profits. Then, if the pricing environment is extremely adverse for a year, the developer once again creates a loss carryforwards. Or perhaps the developer spends capital to expand its production or reduce its cost structure. Those too will often create a new loss carryforwards. They key point is that loss carry forwards is not a cumulative number for a one time event. Rather, it allows the developer to recuperate losses. When a developer has loss carryforwards, it is said to be in pre-payout mode. When the developer has depleted its loss carryforwards, it is commonly said to be in post-payout. What does the long term bond rate have to do with all this? The long term bond rate is an inflator. It partially compensates companies for their costs, both opex and capex. The long term bond rate is a proxy for debt costs but developers use both equity and debt for the development of their projects, so the long term bond rate is a partial compensation for their costs.

To summarize quickly the preceding paragraph: losses create loss carryforwards. Loss carryforwards can be created multiple times throughout the life of the project. Pre- and post-payout modes refer to whether or not the developer has loss carryforwards. And losses are carried forward at the long term bond rate.

Line 7: Net Revenue Before Royalty. Net revenue before adjustments less carryforwards is the net revenue before royalty. Similar to Line 5, during initial construction this line is negative. During normal, steady state, post-payout operation, this line is positive.

Line 8: Greater of 1% Gross Revenue OR 25% Net Revenue Royalty. This line compares the 1% gross revenue (Line 1) royalty against the 25% net revenue royalty (Line 7) and uses the larger of the two values. In effect, prior to payout, a developer pays 1% gross revenue and post-payout pays 25% net revenue royalty. The minimum value for Line 8 is zero. During the construction phase, gross revenue is zero and net revenue is negative. Thus, the larger of the two values is zero.

Line 9: Equals Net Revenue. This line represents the cash that a developer has after paying royalties.

Some key points to consider:

• 1% gross royalty is a small value; oil prices themselves often fluctuate at or more than 1% within a typical day;
• The developer is allowed to earn the long term bond rate, roughly the cost of long term debt, until paying meaningful 25% net revenue royalty;
  • The ability to earn the long term bond rate before paying substantive royalties greatly reduces a developer's risk;
• If the price environment is poor when the developer begins production, it might remain in pre-payout mode for an extended period of time;
• If the price environment is rich when the developer begins production, it will progress quickly to post-payout mode; and
• Because of the pre- and post-payout modes, a developer has an incentive to spend capital to expand its production or reduce its cost profile.

The oil sands royalty is straightforward. There are just two tiers of royalties, one for pre- and other for post-payout. The intent behind having the two tiers is to allow the developer to earn a return on its investment before paying substantive royalties. Oil sands projects are huge costly undertakings. To reduce a developer's risk, the NOSTF proposed having two tiers.

There are more subtleties that I have shown here. This information, however, serves as a good background for the rest of my commentary and the Alberta Review Panel Final Report. My next article will discuss taxation. The two items need to be considered in conjunction, because together royalty and taxation form the governments' take or their portion of the economic pie. The developer receives the remainder.

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.