MARK MYERS: as partners with any one or two companies that we allow full competition in the Basin. And why do you do that. And the reason you do it is the same reason you-people hold auctions. The person that's going to value it the most, and everyone at the auction's going to value the value of that commodity differently, is going to be the one purchasing those leases. The one that's the most optimistic about the development is going to invest the capital to develop it. But that requires an open, level, even playing field for all folks. It's one thing to go to an auction where you can inspect that car you're auctioning off ahead of time and you can look at the engine, you can open the hood, you can run the engine, you understand it. It's another thing to go to the auction where your competitor has gone and looked under the hood, understands that car perfectly and you have to look at it from 10 or 20 feet away. We are setting up in this contract the total destruction of our normal competitive environment. And that means we will simply not attract the capital from the other sources for our type of system to work.

The other choice of systems is a system like a lot of they're little countries or dictatorships use, we'd have a state oil company. And that state oil company controls the resources and it brings in partners to help develop those resources. But those systems would work because the state company is in it 100 percent at the beginning and takes the majority of the profit, 80 or 90 or 70 percent of everything. And then pays its proportional share of the development costs. So that state company chooses to run the resources and brings in experts to build infrastructure and to help them market their product.

This new system is akin to that, but it's overlaying on our system upstream, where we were only taking a relatively small percentage of the oil and gas and that we don't control the upstream development. And that's the achilles heel of what's been proposed, we're getting the worst part of both systems under this deal. And it simply won't work, it won't work from a business perspective and it won't work from a government regulatory perspective. So the whole entire concept and deal is flawed, that's why it's so difficult.

So if we work at it, and I'll work you back through some of the lies. Now the first thing is again is an acknowledgement that you need a fair and even playing field for all parties. This contract locks up leases, 500 leases, state leases the producers hold and 750 leases total for 45 years if they meet that weak diligence standard Tom talks about which does not require building a pipeline or it doesn't require investment into a pipeline.

MARTY RUTHERFORD: And I might note here that the diligence standard itself actually is a defined term within the contract. And it defines out of it certain elements such as delays in Canada or treaty problems with Canada or lawsuits. It not only defines those out so that they cannot be used against the producers for a lack of diligence, but it also says that if there are delays associated with that and there are costs for that the state will pay those costs, will indemnify them against those delays.

MARK MYERS: So you contrast a system where these specific producers get a 45 year lock on every lease they own on the North Slope with a system where after 10 -- five, 10 -- seven to 10 years they turn it back if they haven't developed it. Furthermore, many of these leases have no known oil and gas on them, they're simply exploration leases with no work being performed on them. So it locks up leases, again if the producers don't choose to advance exploration activities, they can't-no one else can get at those leases. Our competitive system doesn't work. Furthermore future leases they may buy. Typically, in fact, this last year DNR shortened up the time frame to five years on leases recognizing that we needed to accelerate development. That was a decision made by this current administration. Yet a producer buys that same lease, they get 15 years on that new lease. So now you've done this-the same thing with the car, the producers look under the engine, they get 15 years, they get lots of time for the same competitive situation the other folks who are not a party to this deal only get five years. So are they going to bid, maybe, maybe not.

So what's happened then is the competitive leasing system that we put on has been totally disrupted in an unreasonable fashion. The only way other investors can get in under those types of system is as a co-partner of those three producers. And they won't let you in cheaply and they don't. And typically in the oil and gas business then in order to get in you might have to pay twice or three times the actual costs to get in. You may carry all the development costs for example and the company gets a free ride. The state, does it get any benefit out of that, absolutely not. So again our whole competitive leasing program is undermined by this contract. So that's just at the very first level.

Secondly, the state's ability to ensure that leases are developed in a timely manner, should they be economic. Thecovenant of the lease that says if it's economic you've got to develop it or you-your option's turned back is totally gone out of this, 45 years, no requirements. So currently DNR's ability to enforce requirements within units and producing units in terms of accelerating development or requiring investment, the ability of the state to protect the rights of other parties, non-producers, in these same units are gone. Because again other parties within our major units are not a party to this agreement. So again you've created a sort of two class system among various producers and explorers that simply creates an uneven playing field and will greatly damage future investment by these folks, but they just can't compete under those situations. It also destroys the state's ability to get folks-to guarantee facility access or access into under used existing infrastructure in order to bring these smaller oil and gas accumulations on line. It destroys the state's use of the Regulatory Commission of Alaska and again DNR's authority to require additional infrastructure to be built upstream should it be in the state's interest, the producers' interest and the independents' interest is gone in this contract, specifically prohibited.

So again you see how this changes the whole oil and gas landscape. So that's at the highest level. Let's move down to then as an investment level, let's say independent of all this, if the state wanted to invest in the project, what does it cost the state when it signs this contract. And when I go back- if the gas line does happen the state is going to pay a minimum of about $13.25 billion in direct subsidy to the producers independent of its own investment in the pipeline. I'm going to break those costs down for you so you understand the level of magnitude. And when you talk about billions of dollars it's again, you can get lost in the math, you-I mean, it's a significant percentage of the value of the state's gas. And if you want to take a stress price of gas at $4, at which this project already has a highly economic return to the producers, you've got one estimate of $4 gas, about a 17 percent rate of return at the stress price.

MARTY RUTHERFORD: With no incentives. That's if the producers own 100 percent of the project under the current fiscal system at $4 gas, they have a 17.2 percent rate of return. And if it goes to $5 gas it's 20.4 percent rate of return. We did copy off a couple of those sheets. Again this is Econ One, a legislative and budget and audits company that they hired independently, those are their information. That entire model is on the web and it's available for people to look at.

MARK MYERS: And generally oil companies use about a 15 percent rate of return as a bench mark as to whether a project's economic, so this is above their typical bench mark. But at that $4 gas price the direct subsidy to these companies, independent of our ownership position, is over half the value of the state gas. And again that should shock you, we're giving up over half our value at lower prices.

At $3 gas prices which would be a low stress price, the producers are still net positive, but the state has gone negative. So we are writing a check in order to produce our gas. And I want you to think about that. Under the current system we take absolutely no risk of going negative. If the price goes negative under leaving it in value under severance taxes, we don't get a check, we pay zero, but we don't actually go negative. So any business that would look at its level of risk at lower prices would be very alarmed by this.

And let me walk through those subsidies and where they're coming from and how we derive those numbers so you understand it. And then I will say after I finish that, there's another five to $10 billion of indirect probable risk the state takes under this that it is not exposed to under the current system.

MARTY RUTHERFORD: And that's before, that's before you even add in the 20 percent ownership position the state is committed to for the entire project.

MARK MYERS: So as you wade through the contract, you'll find a thing called an upstream cost where the state has agreed before the gas leaves the unit boundary, to pay for every 1,000 cubic feet of undeveloped, of just raw gas, gas including impurities, 22.4 cents escalated to the consumer price index. What does that mean. That means by the time first gas flows if you have the average long-term historic rate of inflation is 30 cents, before this contract's over, it's over $1. Okay. Again that's in the-that's a figure that's not based on the actual cost of production, it's just a figure-it's just because, it's additional dealer markup. And that subsidy alone over the life of this contract, if the pipeline never expands and the state has the 20 percent ownership of royalty and tax gas, and it takes it in kind, it's worth $4.54 billion. And that's only-that's with the average rate of inflation, not a higher rate of inflation that we're seeing today.

MARTY RUTHERFORD: I might add that you will hear that from the producers that we are required to pay the 22.4 cents upstream cost allowance. And it is true that within one of the royalty settlements, on royalty gas only, not tax gas, but royalty gas only in the Prudhoe Bay Unit, we would have had to pay that 22.4 cents. However, they've expanded that throughout the Slope to not just royalty gas, but to all the gas, tax gas included, and it's for in kind gas for the life of this project. And we deducted that amount that would have been owned to them under that condition, we deducted that from that from our calculations to get you this net cost we will still pay in addition as an incentive to the producers.

MARK MYERS: And that was an example of another poor settlement the state made that-agreeing in Prudhoe Bay alone on that for royalty has cost the state over $2 billion on the oil side up to this point and it will cost us another potential $2 billion on the gas side. But in this case we've subtracted it out and we've accepted that in 1980 the state made a bad decision and agreed to pay costs it was not obligated to under the lease as later shown by later court decisions, but did it anyway to accelerate an RIK gas sale, to advance an-or an RIK oil sale to a rather. So fool me once, shame on me, fool me twice or you. I'll be the fool here. But anyway it's a repeat on a much larger scale of what happened in 1980. Again that was over a $2 billion mistake just on oil alone up to today. But that is $5.4 billion on that upstream cost allowance. Then the combination, the PPT when added in which is a requirement of the producers, gives upstream credits for investment in the fields. But the contract says-and it does that with the justification that we're getting a percentage of the net profit of the field, we're not getting severance tax in oil changes from a-where we get the equivalent of the value of oil in a volumetric sense to a case where we get a net profit share of all the profits. So theoretically you give a credit for investment, you get more investment, the profit goes up. And so they they said that was the big debate in the legislature, what should be the proper rate, should it be 23 percent, should it be 22, 20, et cetera. But all that assumed two 20 percent credits against operating and developing-operating costs and capital costs in the field. On gas though the contract says never mind what the PPT says or the profit tax says, we're going to get 7.25 percent flat of the gas. Now we're going to take it in kind for severance taxes and that's actually 6.8 percent because you have to net out the royalty share. So it's only 7.25 percent on the 7.75 percent that's not royalty gas. So it's actually so we get a flat percentage of gas, but we still pay all those development costs for gas. So you add in future developments we're now this partner that pays 40 percent of the upstream capital costs and 20 percent of the operating cost for all new development for oil and gas.

And on the gas side we get no percentage of the profit, we get less gas actually, I believe, than we would under the current tax system and we take that gas in kind. So that credit in upstream credits, again with no upstream-uplifter bound to the state in terms of its percentage is worth about $4 billion, that credit.

MARTY RUTHERFORD: And we base that 4 billion net, that 40 percent and the 20 percent on the cap ex and op ex, through the cap ex and another 20 percent on the capital investment and another 20 percent on the operating, we base those on very conservative capital costs on the upstream, it may be far greater than that. So that number could end up in real time a much higher number.

MARK MYERS: Yeah. And if you look again at the contact it covers 45 years of base level flow of the pipeline, you subtract out-there's a lot of new gas that needs to be produced particularly from Point Thompson, but also from NPRA and other fields. That is going to require a significant amount of capital investment in the upstream gas development in the fields. So we calculated out what would be a reasonable amount of dollars for that and you can do that based on what an average finding in development costs worldwide or nationwide, and we discount that and you still come up with the state paying at least $4 billion. So again now the state has become the state oil company without getting the benefits of the state owned company by investing 40 percent and getting absolutely no gas or less gas than it does under the current system where it makes a zero investment. So that's a $4 billion credit.

The next is a-what I call the midstream pipeline and gas treatment plant subsidy. The state, under the contract, when they added the extra hundred and some pages to it recently, when it grew from 300 to 400 and some pages, included a credit for 35 percent of all upstream pipelines that leave the unit boundaries and go to the gas conditioning plant that will be centralized at Prudhoe Bay. And for the Prudhoe Bay plant it gives a 35 percent credit as well. Well, if you look at the cost of building that infrastructure, there would be a big gas pipeline from Point Thompson, there may be a dozen other pipelines to get this additional 30 tc of gas we need. And we hope they're-we hope they get built. But under this contract the state pays 35 percent direct cash credit to the producers for the cost of those lines. Then on top of that we have agreed to pay 20 percent of that infrastructure.

MARTY RUTHERFORD: As an owner.

MARK MYERS: As an owner. So what it equates to is then all these upstream pipelines we pay 48 percent of the cost to get 20 percent ownership in them. The same with the gas conditioning plant, calculated to be 2.6 to $2.8 billion by the time it gets built. So you add those things together that is a $2 billion midstream subsidy to this project that's direct against costs of the project. And that's independent of our 20 percent we're going to pay on top of that for ownership of all those facilities. One thing to think about there is all these are part of the defined project with the producers and the producers talk about risk of cost overrun. Well, if you're paying 48 percent of the cost of that upward infrastructure and you're only getting 20 percent of the return, you are bearing far more proportional cost overruns than any of the producers are, you are paying a proportional share to their actual ownership. So we're hit really hard there. Again it's this other element that I'll talk about later, it's not just the element of direct cost, but the element of risk that's in there. You look at this as a business venture, you're taking a disproportionate and incredible amount of risk on billions of dollars of upstream investment and your 20 percent ownership is not going to be sufficient for you to make any significant decisions on what the costs are, what the design specs are or how it's operated.