TOM WILLIAMS: Now we'll see if I master the technology here. Well, since I can't see on the screen I'm going to hope that I'm on the right slide.

This is the first slide. The title slide, right? Okay. It's a pleasure to be here this morning. My name is Tom Williams. You need to know a little bit about my past, I think, in order to help fill in some of this presentation. I came up here a little over 30 years ago as an attorney for the AG's office to sue the evil oil companies for underpaying their royalties and taxes from Cook Inlet, and now I are one.

In between the -- after the Cook Inlet royalty litigation mostly settled in 1975 they stuck me in charge of oil and gas taxes for the State, one of Dan's predecessors. The division has changed in scope as well as in name, but I think he's got the PCN number, the position control number. And then Governor Hammond in 1979 let me be Commissioner of Revenue for the second term of his administration. And then after that I was in private practice for about a year and then general counsel at Cook Inlet Region, CIRI, for almost four years there and worked on their oil and gas matters as well as their kind of corporate stuff. And I've been with BP since 1987.

Today we're going to talk about ELF. And the first thing I wanted to do is tell you where we are now about oil and gas revenues in general. Here's a slide that shows approximately how much of the general fund unrestricted revenue this fiscal year, 2005, is coming from oil and gas, almost 90 percent. And it's going to continue although right now it's exceptionally high because of exceptional high oil prices. The Department of Revenue says oil revenues to dominate the unrestricted revenue picture and will continue to provide 80 percent of general purpose revenue through fiscal year 2008 and 75 percent through 2012. So oil is important today, it has been important in the past, and will continue to be important in the future.

Alaska gets its oil revenues from four primary sources. The first one is royalty. This is the interest in the production that the State retained when it leased the land. It arises under the lease contract. In fiscal 2004 which is the last year we have actual numbers, royalties paid to the general fund was just over a billion dollars. And another 485 million went into the permanent fund.

The second thing that's paid is the production tax. The production tax is the part that the ELF fits into. As you can see in 2004 just over $650 million went into the general fund from that.

There's a property tax. It's like a property tax on your own home. The State tax is 20 mils. The local governments can tax the oil and gas property and their local tax that we pay is a credit against the State tax. So you see, the State gets just under $50 million from this source and just over $218 million went to the municipalities in FY '04.

And then there's the corporate income tax just under $300 million.

A couple of points here. First of all, the total amount that the State sees, the planners, just over $2 billion. That's what went into the general fund and was available to spend. But from the companies' point of view it's almost, well, it is, over a third larger than that because there's the money that went into the permanent fund, that was real money that we paid even though it's not spendable money for the State, and the 220 million or so that went to the municipalities, also not spendable by the State, but a real payment to the industry, so while it looks like 2 billion to the State it was actually 2 3/4 billion for us.

So first point I'd like to make then is that ELF which took care of the production tax, it's in the production tax only, even if it were to make the production tax zero, and I'll explain how that could happen in a minute, a field pays for royalty to the State, it pays full property taxes on its facilities to the State or to the municipality were those. It contributes fully to the owners' income taxes. It increases the net back value by lowering pipeline tariffs and marine transportation costs per barrel. And it creates Alaskan jobs.

Now the production tax is what we've got to talk about today 'cause that's where the ELF is. It's a tax on the act of producing oil or gas. The tax is equal to the ELF times a base rate times the gross resource value. Now that's gross resource value without regard to the cost of getting the resource out of the ground and producing. Gross resource value is a net back times the taxable volume.

Now what is this net back thing that I'm talking? I'm going to skip ahead to the next slide. Here you see a map showing how the net back works. At the top is the North Slope of Prudhoe Bay and you see the red line coming across Alaska, hopefully you can see that. That's TAPS. And then three black lines going to the West Coast from Valdez. One goes down to Puget Sound, one goes into San Francisco and the other goes in to the Los Angeles area. That's the market destinations.

The net back is you start with a spot price on the West Coast. Let's say it's 25 bucks, plus a 1.61, these are the fiscal '04 historical figures, cost 1.61 on average per barrel to move oil to the West Coast from Valdez. The average TAPS tariff then that year was 3.05. So for a spot price at the West Coast of $25 you had a net back of 20.34. That's at Pump Station 1. For the fields that are away from Pump Station 1 there will be further deduction of the pipeline tariff from that particular field to Pump Station 1.

One thing I'd draw your attention to here is that if the West Coast went to $45, the $20 increase would flow straight into the net back. The marine transportation doesn't significantly change and the TAPS costs don't change as market prices change. So the net back is what's responsive to changes in the oil price.

Back to the tax. The base rate on oil is 12 1/4 percent on the first five years that a field is in production, 15 percent after that. The ELF is a number between zero and one. You multiply that times the tax rate and that tells you what the actual tax rate is for a given field. For each field on oil you calculate its ELF on the basis of how big is the field, how many barrels a day overall in that field, and how much oil per well is it producing. These two are both indicators of the profitability of the field and the thought is the more profitable the field the more you could afford to pay. So that's well productivity. And those two things, field size and productivity, are what dictate the tax rates for an oil field.

Now why have an ELF? The reason we have an ELF, and this is part of the historical reason why I went into my background so long was, you know, we in the Department of Revenue wanted to have the primary tax on the oil industry be a severance tax or production tax and that meant setting a high rate for it. The problem with a high rate severance tax is that it works great in the early years but later on as the resource is depleted since it's a tax on the gross value of the resource it doesn't reflect the operating costs going higher and higher per barrel, and so it tends to accelerate prematurely the end of field life. And that was the adverse consequences as the field is depleted that we wanted to avoid.

And here's the actual statement in the 1977 report that the Department wrote, as operating costs rise during the life of a field the profit margin shrinks. At some point total production costs overtake the value of the oil and gas being produced and production can then be continued only by operating at a loss. So while the cost of doing business production tax contributes the total costs and tends to hasten the time when this break even point called the economic limit is reached. Isn't that beautiful text? Doesn't that sound Shakespearian? I wrote it.

But that was our problem. And here you see an illustration of it. This is -- each column represents the value of barrel of oil and what it goes for. The black at the bottom is the operating costs. And typically that starts off one hopes at a very slight level. The green at the top represents a 1/8th royalty. And the red underneath the 8th represents a 15 tax on the other 7/8ths. Obviously the State doesn't tax its own royalty. So that's 15 percent of 7/8ths. And those remain constant.

What changes over time, the white is the profit margin or operating margin. What changes over time is the black part. It rises and consumes more and more of the value of the barrel of oil. And you can see it goes through four stages here.

In the first stage there's quite a large white margin, and that reflects the fact that you typically had millions of dollars at risk; acquiring the lease, doing the exploration costs, then spending several $100 million if you've discovered something to develop that something, and finally you turn the switch on that's the first time you see a nickel back on all of the millions and millions and millions that you've spent, so you need to have that kind of margin at the front end in order to make the business a going concern.

As time goes by those costs rise and consume more and more. And here's the column in the fourth column there, stage 4, you see that shaded area where it's red and black, that's the loss. The tax is eating into the cost as well. I mean there is no profit there in that stage 4. You are operating at a loss and the amount of the loss is equal to the width of that red and black area in the column. That's when you reach the premature closure.

The producers responses in the first stage do nothing. This is that first column on the left. That's happy days are here, so producers don't really care, those operating costs are minor. The second one is the drive for efficiency. And, again, flipping back and forth here you can see that now you're starting to have the cost be a significant amount. Producers start cost cutting measures, you know, trying to eliminate redundancy in facilities, laying off people sometimes if they have to, using unused capacity in the facilities, just streamlining and debottlenecking as much as they can.

The third phase, this third column, this is the harvest stage. At this point that little white area on the bar is just too narrow to justify investing any further. Even in the previous stage, the second stage, you start having casualties. Projects that you could do to increase the oil production from the field, but which aren't competitive. They just don't pencil out with that sort of margin. By the time you get to the third column nothing is penciling out there and so you're simply operating and trying to be lean and mean. That's sort of the stage that the Cook Inlet fields have gotten into. And, again, that was at normal prices. Maybe they're making investments now at higher prices. I can't speak for them, but they were definitely in this third stage.

Then the final stage is the operating in the red stage. And you operate at a loss because temporarily you do that because you don't expect oil prices to remain as low as they are. It's easy to forget that it was only six years ago that oil bottomed out at $8.16 on the West Coast. And so practically all of the Slope was operating at a loss on that day even Prudhoe Bay, but that was not the expectation, so you grit your teeth and you go on.

The other thing is people will operate at a loss in order to defer the cost of terminating operations. You can't just walk away and leave the wells open and let caribou fall into them or something like that, you've got to remediate and restore and dismantle. And that's a cost that you get no return on, so deferring that cost has a value, too.

So in reaction to the situation about having a high severance tax with this sort of economic profile the Department of Revenue recommended the ELF. Based on the rate of the rate of true economic limit to current production. And this would be -- scale the tax rate down. And this formula here that you see at the bottom, 1 minus PEL over TP. PEL is how many barrels you need to break even, to cover the costs of operating your field. And TP is how many barrels you actually produced. So that fraction is basically the cost percentage of your production. You're subtracting that from 100 percent, that's the one, and that leaves you then the non-cost percentage, the revenue percentage or net revenue percentage that's there. An that is what effectively gets taxed under the original idea of the ELF.

And this is how that formula would avoid the tax consequences. These are exactly the same graphs as before except that you see that the red band is shrinking. It doesn't shrink very much from the first stage to the second stage, but by the time you get to that third stage where the costs are consuming more than half the value of the resource the tax is shrunk back considerably, but it's still there. And there's still tax even in stage 4, but the point is there's still profit in stage 4. You've turned a loss into a profit. You've widened the band in stage 3 so that more investments will still pencil, you've deferred the time when you go into harvest mode. Those are all good things from a State point of view, is growing the pie by taking a little bit less revenue now and overall the expectation is that for the State revenues are closer to being optimized.

So that was the idea behind ELF. And that was the original formula that was proposed. I did not come up with that formula, by the way. My formula is backwards from that. I had TP over PEL and then I subtracted 1 from that. And that formula was too volatile. This formula is nice and well behaved. It can only be as low as zero and only go up to one that's clearly a better idea. And that was David Knutson's. For those of you who've been here a long time you may remember David Knutson.

Another point that I'd like to leave you about the ELF is that in 1977 when this basic formula was enacted it was over industry's objections and the industry objected despite the fact that the ELF was a good thing because the ELF did allow us to raise, us the State, to raise the tax rate. The prior tax, the tax rate on Prudhoe Bay was going to be about, oh, darn, a senior moment, it was either 8.8 or 7.8 percent, but it was under a stair step tax. 7.8, that's what it was and it'll -- hey, I've got it written there. I remembered it. Why don't I read. So it raised it by half, to 11.7. That was what happened at Prudhoe Bay and that was why the industry didn't like it. It was a tax increase. Even though this may have been progressive it was a tax increase and that was why industry didn't like it.

In 1989 the formula was changed. The '77 formula or the original formula was entirely driven well productivity, the 300 barrels a day per well assumption, that you needed 300 barrels a day per well to break even. In 1989 field size became another factor in the formula. Fields larger than 150,000 barrels a day were assumed to have more efficiency and fields less than that -- I'm getting way behind here again, sorry, were assumed to have less efficiency and so the tax rate came down. Field size is the dominant factor in the formula.

Why change the ELF? What was the Legislature told? To get more revenue. Here you can see there's going to be an increase on the tax from the two biggest fields of about 2.9 billion from Prudhoe and Kuparuk. About .2 billion was going to be given away for the smaller fields, a net of 2.7 billion. And in fact, the State -- that was the cumulative effect through 2010. The State reached that point several years ago so that prediction was fulfilled.

The second thing was to give an incentive for marginal fields. The tax rate will be sharply reduced or eliminated entirely. Now, marginal fields -- I put this quote in about the marginal fields, the second one, to make clear that marginal was used sort of a code word back there. It basically meant any field but a Prudhoe Bay or Kuparuk. 'Cause you see listed in there Endicott. In Alaska the marginal fields are the six Cook Inlet Fields, Milne Point, Lisburne, Endicott. At that time Endicott was producing over 100,000 barrels a day. It had come in under budget and ahead of schedule, a 100,000 barrels a day and that was a marginal field.

So when you look back to the text of what the Legislature was talking about back then then you have to understand that marginal is not the dictionary definition of marginal. It was basically code for smallish, not a Prudhoe Bay, not a Kuparuk.

Third was to give an incentive for West Sak oil. And here again, this is a quote from one of the administration's witnesses, the new ELF will increase drilling production and employment at truly marginal fields and let's hope some day West Sak. And it will reduce or eliminate, again, the tax. That's a pro-development impact.

And the fourth reason given was well, Prudhoe and Kuparuk can afford it. Well, one can debate that, but here's what -- point number 3 is that basically, you know, Prudhoe and Kuparuk didn't run off a cliff. There continue to be investments there. And they still have a higher production tax Prudhoe especially. Kuparuk is getting closer to a point where under the formula it will be paying less tax because it's getting close to the 300 barrels a day per well and because its size is getting smaller, but right now the State still had -- I believe that's correct, if I'm incorrect Dan will correct me. It was last year so up until last year at least Kuparuk was paying more.

Satellites and other little fields pay little or no production tax. That's because of the field size factor. Small fields can have the same volume of production per well as a big field but they will pay less tax. That's the third thing. And that's part of the incentive for the small fields because they lack the economies of scale. And the State is already over the 2.7 billion ahead net from the 1989 change, so it did work the way the Legislature was told.

And again, this was over industry's objections. Why? Because it was a major increase for Prudhoe and Kuparuk. Prudhoe went from about 11 1/2 percent to 14 1/2 percent under this ELF formula. For Kuparuk it was an even greater step up in the tax rate proportionally. So those were the reasons for industry's opposition.

Here's what has happened in terms of production since the ELF was changed in 1989. The total bars here show the total amount of ANS production in terms of barrels per day per fiscal year. Each column is a State fiscal year. The black part is the base field. Those are the fields that were producing in 1989 at their natural decline rate which we have assumed to be 15 percent a year, year on year decline. That's probably conservative, but that's -- we're building that as the assumption. No investments, no further development, just run with what you've got, what would that look like. That's the black area of these bars.

The sort of yellowish area above it is the investment -- reflects the investment that was made in those fields to slow the decline because it's the difference between the natural decline and the actual historical production from those fields. Then starting in the mid '90s you see -- well, actually later than that, about 1999 you start seeing production coming in, a little narrow band of sort of teal, satellite fields. And, again, they have grown over time especially since the year 2000. There's part of a key for the no decline after '99. You also see red coming in starting around '97, heavy oil. And then finally, at the very top of the columns and most recent ones, wildcat explorations. And that reflects production from Alpine and production from North Star.

One thing I'd point out to you is that we have more than three times as much oil today because of the investments than we would have had if it had been just straight harvest with no investments and no ongoing development since 1989. And the second this is, is historically the Department of Revenue in 1989 was projecting revenue much closer to that 300,000 barrel a day number from the Slope by now than the close to a million barrels a day that we have. So historically making new investments in these fields has resulted in substantial amounts of additional production. And as of last fiscal year the production was greater from new investments than there had been from the original investments in 1989.

Looking forward, this is a similar sort of pattern, this is the production profile that's behind the Department of Revenue's spring forecast this year. Once again, the black area reflects the 15 percent base rate decline of the existing fields. And we're assuming no decline in the next fiscal year because there's a lag time. Then you see yellow comes in again, that's the new investment. This is the difference between the natural decline rate and the projected production rate in the Department of Revenue forecast from those fields.

The next is the teal band above that. That's the satellite fields as projected by the Department of Revenue. It starts off fairly significant now. It's projected to decline. I hope it doesn't because I think there are more satellites to be found and as the infrastructure and the pipeline network expands outward. So, hopefully, that's a too conservative assumption as we go forward into the future.

The red is heavy oil or viscous oil. And as you can see that is projected to widen in the coming years and be an increasingly important source of North Slope production. It is projected to taper again in the last part of this period. But, hopefully that, too, is a conservative assumption.

And finally, you see on new fields, this is, again, this reflects North Star -- no, it reflects the new fields at NPRA, it reflects Liberty Offshore, it reflects Point Thompson condensate production and other fields. And, again, these are the fields that the Department of Revenue has identified and made their reasonable assumptions about when they'll be brought on stream. That, too, depends on what is found ultimately and what gets developed.

But the point that I would make, once again, is that the future, if anything, is even more dependent than the past has been getting to today on move investments to keep production up. And production -- these types of investments have different economic profiles. It's a very different economic calculus to decide shall I drill another development well at Prudhoe Bay versus should I spend $50 million more on R&D on how to produce the viscous oil out of this crumbly rock that it's in. It's a different calculus again, from somebody saying shall I spend $5 million to acquire a lease and then $25 million drilling a well on it in the Petroleum Reserve or maybe in ANWR.

And so when the State is investing by, you know, having its fiscal regime and its getting its return by having made the resources available through that fiscal regime, has to recognize that investment is crucial for the future. These different kinds of investments to keep oil production up have different economic profiles, different patterns or economic structures. So a change that is good for one type of investment can be very harmful for another type of investment, and they both may have a comparable amount of reward in terms of generating additional production. Thus, any change needs to be carefully examined for the law of unintended consequences.

And then briefly, what does the Governor's office have to do. This is last January. There are six participating areas, satellite fields or smaller fields within the Prudhoe Bay Unit that got thrown together with the main Prudhoe Bay field. That made all of the fields larger under the ELF statute than they had been before. So for Prudhoe Bay, the fact that it had grown by dis-aggregation the ELF went from about .8 to .89. For a number of satellites the ELF went from zero to .89. So it was a very substantial increase for the satellites and a substantial increase for the main field as well, over 10 percent. And so that was the effect of lumping the fields together.

And two of the fields that were lumped together, the Orion and the Polaris prospect are viscous oil from the West Sak and it's in those same sort of stratum that flows west and it becomes known as West Sak participating area and Kuparuk and the Schrader Bluff in the Milne Point area. So those are there and perhaps -- well, that's it. I should shut up. I've stolen Dan's time and I'm stealing time from your (indiscernible). Thank you very much.

MS. LEASK: Thank you, Tom.

MR. WILLIAMS: Sorry, Dan.