埃尼石油 (E) 2006 Q4 法說會逐字稿

Ladies and gentlemen, welcome to the First Calgary Petroleum 2006 results conference call on Wednesday, the 28th, March, 2007. [OPERATOR INSTRUCTIONS]

I'll now turn the conference over to Mr. Rick Anderson. Please go ahead, sir.

Hello and thank you for taking the time to dial in. My name is Richard Anderson, I'm the Chief Executive Officer of First Calgary. With me today is Shane O'Leary, Chief Operating Officer; and John van der Welle, our Chief Financial Officer. We are taking this opportunity on the announcing of the results for the year ended December 31, 2006 to update all on the Corporate developments over the past year.

This time last year, First Calgary put forth a corporate strategy that involved two initiatives. One to, commercialize Block 405b with a stage development plan. And, two, to strengthen the reserves through drilling. I'm very pleased to say the Company has done exactly that. With the signing of a gas marketing agreement, and approval of the exploitation license First Calgary has taken a giant step forward on the commercialization front.

With respect to the drilling results, I will say that 2006 was a year in which we had to complete exploration of the block before the end of the exploration phase on December 30. As a result, a good portion of the wells we drilled in 2006 were high-risk, designed to test new areas and structures, or the limits of previous discoveries on the block to ensure that we could retain any new discoveries into the appraisal period. We had mixed results. Some of the high-risk exploration wells and stepouts did not positively affect our reserve position. While others extended previous discoveries. In case of the TAGI formation, a significant new oil pool was discovered and continues to be delineated in 2007.

Our company has had many impressive achievements. As of today, First Calgary has drilled and cased 24 wells on Block 405b. 20 of the wells have been tested resulting in cumulative flow rates of 282,989 barrels oil equivalent per day, which is made up of a little over 1 Bcf per day of gas and 112,000 barrels of oil and condensate. One well is currently testing, three wells are waiting to be tested, two rigs are currently drilling.

To bring this production to market, you must commercialize according to the procedures in Algeria. This plus the fact we are located in the central part of the Sahara desert has made it challenging. First Calgary has assembled the people under Chief Operating Officer Shane O'Leary that have done the job and will continue to do so. The first stage of an overall integrated development plan has been approved by the Algerian authorities, the Gas Marketing Agreement critical to realizing revenues from gas production has been entered into, which ensures a fair market price for First Calgary's share of gas production. First Calgary is one of the first foreign companies to have successfully explored for gas in Algeria and moved forward to develop these discoveries.

As I mentioned a moment ago, the production sharing contract came to the end of its primary five year exploration term December 30, and the drilling program conducted over the past year has allowed the Company to retain all lands deemed respective. We have now entered into a two-year appraisal period covering what we refer to as the central area field complex and the [ZED ER] area in the northwest corner of the Block.

What has the drilling done to the reserves? First, understand how the Company has explored the Block. Initial drilling targeted structures identified from our 3D seismic and geological interpretation. The highs were targeted, resulting in some of our best wells. The second phase of drilling targeted the outer limit of these structures and as expected, some of the wells did not test as productively as the original wells.

The next phase of drilling, which the Company is in now is to define the extent of the reservoirs more definitively and file a development plan for the central area by the end of 2007. When you look at this year's reserves as compared to last year's, the number has remained relatively neutral. The nature of the reserves has changed as the Company has focused in the central area, more liquids-rich and oily. We have a much better understanding of the reservoirs now. The Company plans to drill seven to nine wells this year, which we feel will complete the picture. Two of those wells have already reached TD.

The 3P number is still out there, over 5 Tcf equivalent. Which means as we continue to drill out this asset, reserves can continue to move. The 5 Tcf equivalent is a quantified upside. As an example of what I am saying, one of our recent wells, LEC 2 has confirmed to our logs the continuity and aerial extent of the sizable TAGI oil field discovery, which is not in the Company's year end reserves, and which Shane O'Leary will speak to shortly.

First Calgary's profile is changing. The exploration risk has been mitigated, the reserves risk has been mitigated, with the amount of drilling that has taken place, there's a much higher degree of rigor associated with the reserves and upside still remains. The commercialization risk has been addressed with the approval of the exploitation license agreement for MLE, probably the single most important achievement in the history of First Calgary. The marketing risk has been addressed and First Calgary will achieve a fair market price for monetizing gas.

Cost control is a major challenge for the industry right now and I can assure you our project team is doing everything possible to focus on this. Fortunately, our production sharing contract includes a rate of return type of mechanism, such that the net present values of future revenues is less sensitive to changes in capital cost. What's left? We need to finance the facility and build it. So on that note, please let me hand it over to Chief Operating Officer O'Leary to get into some detail, and then Chief Financial Officer, van der Welle to talk financing.

Thank you, Rick. In my section I will be covering our drilling activity on the Block, the reserve numbers for 2006 and how they compare with 2005. Highlight what is emerging as an exciting oil development in the central area in the TAGI formation and I'll also provide an update on MLE commercialization. I'll then turn it over to John for the finance update. I might point out that if they're not there now, shortly there'll be some slides on our website that you can follow along with for the presentation, which has lots of maps and makes it easier to follow the story line.

To date, STP has drilled 24 wells on the block and we're currently drilling two appraisal wells in the central area field complex or CAFC as we call it, and we have testing ongoing in the CAFC and MLE areas. Drilling costs have been reduced from around $2,500 a meter to $1,500 a meter as we continue to learn and become more efficient. We have now tested a cumulative 283,000 BOEs per day from our wells on the Block. This is not a measure of sustainable production, but it is an indication that we have some prolific deliverability from the reservoirs we tested.

Looking specifically at 2006 drilling activities, we've drilled nine wells in 2006 in the CAFC and ZED ER areas and conducted a total of 54 production tests which have added 48,000 BOE per day to our cumulative test volumes. In addition, 2006 program was noteworthy for the following reasons--Firstly, prior to 2006 our thinking and that of the reserve evaluators was that the central area was largely a collection of gas reservoirs. The 2006 program has redefined the reservoir and fluid parameters, reservoir fluids are more liquids-rich than the MLE fields and in some cases we are dealing with oil reservoirs. In total now, our reserves are about 50/50 gas and liquids. Secondly, following the 2006 program, we now know where we want to focus going forward. The TAGI and the lower Devonian F62 reservoirs will be where we concentrate our appraisal and development activities. Thirdly, the 2006 program enabled us to retain a 314 square kilometer area for a two-year appraisal period, long enough to complete our evaluation of the discoveries and file a development plan to hold the areas into development.

Now let me turn to the DNM 2006 reserve evaluation. DNM is assigned 1P of reserves of 1.2 Bcfe, about 20% higher than in 2005, 2P of 3.8 Tcfe, essentially unchanged from 2005, and 3P of just under 9 Tcfe which is a reduction from 12 in 2005. The 2006 reserve assessment is based on an additional 9 well bores and 55 well tests over the previous year's evaluation that was based on only 7 wells. TASE increased and proven reserves is primarily due to the TAGI zone and [MZO] and LES areas. The significant amount of new test data there will from 2006 drilling DNM decreased CAFC probable reserves in some areas due to recalibration of reservoir parameters, in some cases representing a 50% reduction in net pay. In addition, the LEW2 well decreased the aerial extent of the LEW field due to the biological pinchout of the key reservoir.

Although we added a lot of 2P reserves with other wells, particularly in the LES area, the net affect is the overall 2P number did not move much year over year. However, the 2P number is considerably derisk compared with the 2005 number, just because of the sheer volume of data available this year to make the assessment. Now in a minute or two, I will discuss some of the 1Q 2007 activity, which will have a very positive affect on 2P reserves in 2007, but could not be considered by DNM for 2006 due to the December 31, cutoff. And these welled TD'd after December 31.

Tcf and MLE possible reserves decreased from 12 to 9 Tcfe due to recalibration of reservoir parameters and removal of noncommercial reservoirs from reserve status. A key component of this was the F63 horizon being removed from our numbers at the request of FCP, since it is no longer considered commercial and a focus for the Company. Based on the work done in 2006, we can conclude that the CAFC is economic and scoping of a development plan for the area has been completed and we intend to file a development plan for the CAFC by year end 2007.

I might also touch on the net reserves for a minute, the 1P net reserves, net being what we actually are entitled to and what we get to keep increased from 240 Bcf to 313, that was the 1P, about a 30% increase. The 2P increased from 677 to 777 Bcf, about a 15% increase. And the 3P was virtually unchanged at 1.3 Tcfe. The reason why the net reserves increased is our cost profiles changed, they increased as we included export pipelines under the arrangement we had with Sonatrach. Previously we were looking at a tariff type of an arrangement. They are now included as a project cost, as well as general inflation in the overall cost of the project. But with the type of contract that we have in Algeria, which is sort of a rate of return-based contract, you actually get rewarded for spending more. You get to earn a rate of return on additional capital. So our net reserve increased for that reason. To summarize, the focus areas in the CAFC going forward are the TAGI -- the oil pools and gas pools in the LES and MZLN areas and the Lower Devonian pools.

Now let me give you an update of some of the 1Q 2007 work in the TAGI that give that has been a very pleasant surprise for us. The LEC 2 and LES 6 wells drilled in '07 have encountered an average of about 25 meters of net pay in the TAGI horizon, which together with the LES 3 well is delineating what we think is a 100 million barrel resource pool -- recoverable resource pool in the LES structure using a P50 metric. You'll recall that the LES 3 well tested at normalized rates of about 5,500 barrels a day and about 6 million cubic feet a day. By contrast, DNM is assigned a 2P number to LES of 50 million barrels, but again, they were not able to use the LEC 2 or LES 6 wells due to the December 31, cutoff date.

It's a similar story in the MZLN structure, where we also see at least 20 million barrels of TAGI recoverable resources on a P50 basis. So together with LES, we believe we have a 120 million barrel recoverable resource development potential on a P50 basis. Our 2007 appraisal program we'll be drilling additional wells into the TAGI to confirm this potential. The significance of this is that it represents a second anchor project to the 230 million barrel MLE development. So we now have two key developments we can pursue.

It shouldn't be a surprise that we have a large TAGI discovery. There are billions of barrels of TAGI oil development on trend with our Block in the Berkine Basin. If you look at a map, you'll see it extending down to the southwest and it looks like we have our TAGI pool as well.

Now let me turn to an update on commercialization. You will recall, at this time last year we set two critical objectives to achieve, conclude the Gas Marketing Agreement and get approval for the development plan and the exploitation license. As you know, we were able to achieve both of these. The FEED, front end engineering and design for the project has been bid and we expect to award the contract to one of the contractors in April or second quarter. FCP and Sonatrach are currently reviewing and evaluating the bids in Algiers as we speak.

We hope to award the EPC by the end of the year, 14 large EPC contractors have expressed an interest in participating in the EPC tender. A key decision we're working on right now with Sonatrach is how big do we build the plant? And there are several factors impacting the decision on plant size. Obviously, we have to address the reserves from the central area. There's also a compelling cost argument to build bigger now. We can double the capacity from 200 to 400 for only 30% more cost, so from 977 million to $1.3 billion. We do have the option of adding a second train later, but by doing so, instead of building it now, it would cost us an extra $140 million. So obviously it makes more sense to build the larger train now.

There's also a strategic component. There's something in the order of 20 to 50 Tcf in the Berkine Basin, meaning that over time as 405b reserves decline, there'll be plenty of third party processing opportunities from off the Block. There are also exploration areas around our Block that we are hoping we can secure rights to and have discussions with Sonatrach around this that we can fill in and keep the plant loaded in the future. So obviously we'd like to build a larger plant than just for MLE volumes.

We are in discussions with Sonatrach, and I expect shortly we will agree on a plant size that's somewhere in the order of 3 to 400 million cubic feet a day. Then, of course, in the future, we can always add additional trains if the 3P reserves are proved up, or if off Block third party gas opportunities can be advanced. I should mention that the DNM 2P profile supports us building a 400 million a day plant today, but we have not made that decision yet. We are still working that with Sonatrach.

Maybe just a quick word about the strategic component. As I mentioned, we're in a Basin with a lot of gas. Most of this gas is reinjected now for pressure maintenance to produce more oil. First Calgary is the only foreign company that has gas rights in the Berkine Basin. And therefore, it will be the only ones that can operate with Sonatrach, the export pipeline that ties into the grid 140 kilometers to the west.

Eventually, as these other fields blow down, as I mentioned, there'll be thinker party processing opportunities. Right next door to us on the Burlington Block, they are currently reinjecting 200 million cubic feet a day, we could easily bring that gas over to our plant, produce an extra 15,000 barrels a day of liquids and send the gas back for reinjection to their fields. We don't have any discussions going on with Burlington, I just suggested that as one of the -- I just suggest that as one of the opportunities we have to highlight what I consider to be the strategic component of this gas plant. As they say, build it and they will come. This is a key piece of infrastructure that's going into the Berkine Basin and I don't expect to ever see this plant operating at anything but capacity for the thirty-year production license that we have.

A few words about the Gas Marketing Agreement and I will turn it over to John to discuss financing options. The deal we have currently with Sonatrach is for 200 million cubic feet a day from the MLE field, but the agreement has been structured to increase the annual contract quantity as the central area is appraised. In discussions I've had with senior Sonatrach marketing management, they've told me that they will take whatever we can deliver. It's just a question of proving up reserves and both agreeing that we can support a plateau, a higher plateau over a ten-year period.

The pricing of our contract is indexed to European refined products. We cannot divulge the gas price because of confidentiality, but we have or will have shortly on our website plotted for you IEA data, which shows historical European gas prices, average pipeline delivered gas in Europe, average delivered LNG, and the Spanish CNP price, which is a price that large industrial users pay for gas in Spain. I can't tell you the price formula or price, but if you take these average European prices and take off the transportation cost to go from our Block to the market, which is roughly about $1, you'll get very close to what our wellhead net back price is. And we are paid a netback price under our take or pay arrangement with Sonatrach.

So in summary, commercialization is on track for the MLE field being the 230 million BOE anchor project going ahead. We expect to have initial gas volumes of between 3 and 400 million cubic feet a day with about 70,000 barrels a day of liquids. The CAFC has a 120 million-barrel oil equivalent recoverable resource development that's emerging, additional appraisal will be focused on this in 2007. The 2007 DNM will be positively impacted by this TAGI discovery, as we can already see from 1Q 2007 drilling. The CAFC is very liquids-rich. Approximately 65% of our revenues in the future will come from liquids in the central area. And in 2007 operations will focus really on two things, execution of MLE with an EPC target of fourth quarter, awarding of an EPC in the fourth quarter of 2007, and appraisal of the TAGI pool. I'll now turn it over to John who will discuss the financing options.

Thank you, Shane. In my remarks today, I'm going to cover three areas. I'm going to pick up on the DNM valuation. Secondly, I'm going to talk about where we are with our financing plan for the development of MLE. And then thirdly, I'm going to offer some thoughts and a bit of an update regarding the windfall tax which was announced by the Algerian government last year.

So starting firstly with valuation, as you know in the results that we have just published, there is an independent valuation which matches the reserves categorization by independent recording engineers DeGolyer and MacNaughton. Firstly, some words on the assumptions of this valuation. Oil price used in the valuation that we highlight is the year-end price for 2006, which was approximately $59 per barrel as a Brent oil price, which is broadly similar to the price that was the case at the end of 2005. So when I comment on the way the valuation has moved, there is no oil price impact or change in oil price impact, should I say, underlying this. The gas price, of course, very important.

Shane has offered thoughts on the gas price, so I won't repeat those, although I would point you to the annual information form, which the Company will be filing before the end of this month in Canada on SEDAR. And that has in it a gas price alongside the oil price which DeGolyer and MacNaughton have used as their forecast case valuation. To give you a point of reference from that, at a $60 Brent oil price the netback price, the wellhead that we will receive is approximately $5.10 per thousand cubic feet. Which we consider, as Shane has said, to be a very competitive price and relates well to the market in which we have to refer to in terms of where our gas may indeed ultimately be sold by Sonatrach.

On the capital expenditure side, the cost -- and I'm going to focus here on the 2P, the proved and probable case. The costs which DeGolyer and MacNaughton have assessed are approximately $2.2 billion gross, of which First Calgary's share is 75%, so approximately $1.7 billion. This is for the Block development, I would emphasize, which embraces the reserves outside of the MLE area, which is the first stage of development.

The costs have indeed gone up a bit from last year, from 2005. The equivalent number to the $2.2 billion reported a year ago in this presentation was $1.4 billion. And the rationale, as Shane has already covered, it's an inclusion of export pipelines. It's a better worked up number for costs and incorporated cost escalation, which has occurred in the industry across the board. However, as has already been said, under the production sharing mechanism, this project is exceedingly insensitive to CapEx as a result of the additional volumes of oil and gas that we get to keep in remuneration for investment.

So moving on to the actual NPVs, the net present values that DeGolyer and MacNaughton are reporting. These are summarized in the press announcement that went out earlier today. I was going to focus particularly on the 8% and 10% discount rate values and in particular on the proved and probable reserve base. Obviously, the choice of discount rate is an important item and there are factors that need to be taken into account in choosing what is the appropriate cost of capital to define the rate. The industry and the market often focus on a 10% discount rates, as you know.

From my point of view, looking at the specific financing of this project, we are looking at financing a substantial portion as I'll come on to discuss in a moment with project finance, and we have been advised indicatively by Citibank, our project finance advisory bank that we could expect to pay something like 250 basis points or 2.5% over U.S. dollar LIBOR, which currently stands at approximately 5.3%. So adding those two together, you can see that certainly a portion, a significant portion of the funding of the project will be at approximately an 8% cost of capital. So I would like to focus on the 8% NPV. Although we will be disclosing a range of different discount rate valuations.

At the 2P level, the new end of 2006 valuation works out at about $1.45 billion U.S. net to First Calgary. This is down somewhat on last year, but is a considerably firmer number for the reasons of the derisking that Shane has already identified. A little calculation here. If one takes that valuation and adds to it the financial resources in the Company as at the end of last year, then at the converted into a share price, this would work out as approximately C$8 per share or in sterling terms, approximately 3.50 pounds per share, both of which are considerably higher than the current share price. Also, on valuation, as Shane has already said, this DNM value does not include the additional TAGI oil that has emerged as a result of testing and so on since the end of the year and furthermore, the strategic value, the first mover status, if you like, that we will ultimately seek to benefit from as the builders of this in the first plant and pipeline in this region of the Berkine Basin.

I now propose to move on to financing. Obviously, some fairly significant financing required. But first of all, would like to just comment about the year 2006 and the immediate financial position for 2007 as in the results it says we ended last year after having spent approximately $160 million of capital expenditure on the drilling program in the central area with cash balances of about $109 million or working capital after taking account of net-net creditors of $83 million, as a say of working capital at the end of 2006.

Moving forward to 2007, we have a capital expenditure program of approximately $150 million planned. This comprises the up to nine wells -- appraisal wells on the central area. It includes testing of those wells. It also includes seismic activity planned in the central area, the FEED engineering work, which is getting underway, as Shane described, and also the purchase of certain long lead items, which are necessary given the lengthy lead times toward this year to be ready for the time then, to be consumed in the MLE development project.

The big financing requirement is in relation to the development as a whole. For the MLE development, we are looking at a First Calgary share of costs at the 75% share of total costs that we pay amounting to approximately $1 billion. Now, I've already mentioned that we are working with Citibank on the project finance and that work is proceeding well. We have had a loss of interest in this project, the project itself is a highly attractive project on its economics, it's also attractive in what it is, being a source of gas supply into Europe and working with our partner, Sonatrach, and with Sonatrach as the counter party to the gas marketing agreement, this is a highly attractive and financeable investment in upstream.

Citibank have considerable experience of working in Algeria where they have been involved in project finance, in other infrastructure projects, such as in the telecoms, water plants, and cement plant areas. Our project will be the first upstream financing in Algeria, and this makes it a particularly attractive proposition for lending banks, because it represents an opportunity, a first up opportunity to invest in infrastructure upstream in a country where they have no other direct investments of this type. It's worth bearing in mind that this project, as in the D&M projected cash flows underpinning the valuation generates in excess of $500 million or $0.5 billion per annum net to First Calgary before capital costs. So revenues minus operating costs and other costs of the project are over $0.5 billion annually net to First Calgary Petroleum.

Now, the project loan will not, of course, cover 100% of our funding requirement, that would be most unusual. So we are obviously considering other sources of finance. The situation today is that this is a work in progress, it's not necessary for me to fully define the source of finance at this stage, and we are looking at the complete range of financing alternatives from other debt through to equity and obviously there are other types of innovative financing instruments and so on which could form part of an overall financing package.

Suffice it to say, though, in assessing what is the most appropriate capital structure for this investment, it is strongly our intention and governing criterion by which we measure this to ensure that there is a maximization of returns to current shareholders. That is the governing blends if you like, through which we view alternative financing sources. It's really, I would say that it's work in progress. My time line for the financing is to ensure that all the finance is in place either in the form of cash at bank or commitments that are drawable for the project by the end of this year in-line with the timing that we plan to sign the major engineering procurement in construction or EPC contract by the end of 2007.

Now I'm going to move on, just briefly, and update you on the third subject, which is the windfalls profit tax. As you may know, there was an announcement last summer that Algeria was intending to introduce a windfalls profits tax, and in early December last year, the detail was published by way of a government decree. The industry has been assessing and continues to assess how this tax will be applied in practice. For our own part, we have been notified by the authorities of the relevant section of this new legislation, which will apply, and in our case, it looks like the rate of tax will be 5% to revenues and that is indeed the lowest rate as the range of rates are between 5 and 50% set according to thresholds of First Calgary's share of production.

We have been -- advised would perhaps be too strong -- but we have heard informally that there is a continuing consideration that's going on in the country as to whether this tax will apply to gas revenues, and there's a good chance it will only apply to liquids revenue, though this is yet to be confirmed. If we find that we are subject only to liquids revenue being the subject of tax, as obviously we hope to be the case, then half of our revenue would effectively be taken out of the tax and in effect this would become a 2.5% rate of tax on First Calgary's gross revenue stream. This is much better than we had thought, but obviously we wait to hear the confirmation.

So in summary, I would like to say that we feel overall that the valuation that has come through in these results from DeGolyer and MacNaughton is significantly derisked for the factors which Shane has already outlined, it's a much firmer number. As I've already shown from those value metrics provides a solid underpin to the Company's valuation. On the financing plan, things are progressing very well. It's very definitely not a case of worrying about where the money is going to come from, it's more a case of optimizing the structure to ensure that we maximize returns for current shareholders. Thank you. I'm now going to pass it back to Rick.

Thank you, gentleman. Let me in summary just touch on the highlights, if you would. First Calgary has had significant drilling success. We've drilled and completed 24 wells on the Block to date. We have a significant amount of production behind pipe, 283,000 barrels oil equivalent cumulative flow test rates, 48,000 of which were added in 2006. We continue to drill a central area, we continue to make new discoveries, the TAGI pool, for instance, which Shane discussed, 120 million barrels of recoverable resource.

DMLE development is underway. The commercialization declaration has been received. We have a Gas Marketing Agreement in place, the FEED process has started and we look to awarding the EPC for contracts in the fourth quarter. As John just said, project financing alternatives are being reviewed. We need to grow this company, so we have created a new ventures group looking to leverage off our technical and regional strengths. We have put the people in place to accomplish all these goals and we have strengthened both management and staff. We need your support. This is the end of our presentation and I would now ask the moderator to open the phone lines to questions.

Thank you, sir. [OPERATOR INSTRUCTIONS] Our first question comes from Mr. [Mehmet Khant]. Please state your company name followed by your question.

It's Mehmet Khant from UBS. Hi, gentleman. John, could you please touch base on the impact of windfall tax, 5% or 2.5% on the NAV that you just gave us. Could you just shed some light on that?

Mehmet, thank you. Well, this is so recent, this news, we're still evaluating it, but the structure of the tax is, as I believe you probably know, that it's not really a profits-based tax, it's a off the top royalty, in effect. So that 2.5% of gross revenues is not, unfortunately 2.5% of net present value. I think it would potentially have an impact of approximately 10%, or something like that. But we're still in the course of firstly, waiting to, as I said, to see what the actual outcome is and have this hopefully confirmed, but secondly, we're still doing our calculations. In broad terms, something of the order of 10%.

I have another follow-on question, if that's all right. Now, how much of this windfall tax is a concern for Citigroup, who is basically worked on your project financing. Is that time line important? They need to get bottom of this to find out that the impact of this could be detrimental to the project financing or the economics of the project? Do we have to wait for this windfall tax cloud to be cleared over us?

Well, it's a good point, Mehmet, actually. Obviously, we're all following the tax very closely. Of course, ideally, we would have certainty as to what this tax is going to be at the time of financing, and certainly that's our hope and expectation that we will have clarity on these issues before we actually launch a financing. However, I'm not necessarily personally of the view that this itself would prohibit the launch and become a critical path item. I think what would happen in reality, is if there was still uncertainty, we would have to assume the worst case. On this liquids and gas point, we probably would have to initially assume that the whole hydrocarbon stream is taxable and then build into the facility some kind of flexibility such that if it was clarified on a more favorable basis later, there would be some way of addressing this by increasing the quantum of available funds. So I think there are devices to deal with the uncertainty, if that was the situation when we get there. It's not a concern immediately at the moment and hopefully it will be clarified by the time that we get there.

[OPERATOR INSTRUCTIONS] Thank you. We have a question from Mr. Mehmet Khant. Please go ahead, sir.

Sorry, me again. Another question. The share price has been under such a huge pressure, again, if you're going to finance the project with, let's assume that two-third of the debt financing, that would put pretty good leverage on the balance sheet. How concerned Citigroup is about the share pricing? What do you do here to rescue the share prices, which based on your amount that you just did is trailing at a significant discount to NAV? What's the strategy here?

Well, obviously, the conversation and the work that's ongoing with Citibank is to focus on the debt, and the debt is not a function itself, of the share price. However, again, your comment is important as we look at the totality of financing. Obviously, we don't control the share price, as we've said already in this presentation, believe that the excellent progress that's being made with the commercialization and the go ahead with MLE and the work that's going on about to commence in the FEED work is going to reflect itself in the share price in due course because, obviously, as Rick and Shane have already said, this project is moving forward, it's being substantially derisked, a lot of the issues that were outstanding when we were given this conference call a year ago have been dealt with pretty much in-line with the plan that we've set out and logically and hopefully, that will be reflected in due course in the share price. But specifically, when I'm talking about the project loan with Citibank, I'm talking about the project loan, I'm not talking about the share price.

Okay, thank you.

Thank you. Our next question comes from [Jean-Pierre Lavilere]. Please go ahead, sir.

Thank you. First question, are you in talks for a new Block in Algeria? Hello?

Well, yes, we understood your question. What we are looking at, as I said, we've put together a new venture's group, and the new venture's group has a strategy where first we want to expand if we can off our knowledge base right in the Berkine Basin. So we do have some ideas immediately offsetting us and we're talking to people about that. We do have--.

Are you talking new venture, or are you talking outside of First Calgary or within?

No, no, no, everything we do is within First Calgary.

Was that your question?

Second question is, why not truck the oil from the LES 3 and ZED ER-1?

Why not what?

Truck the oil from the discovery of LES 3 and ZED ER-1?

We've looked at earlier oil options, including trucking, and we'll continue to look at those, but we've got quite a volume of oil and there's limits to how much you can truck. The attractiveness of doing that is to get some early cash flow, but there's real limits on how much you can actually evacuate with trucking because of the availability of tankage and trucks, and there's HSC issues and other things. What would work better for us is try and accelerate the main development, which includes now an oil development, which is somewhat independent of the gas plant. We can reinject -- we can reinject gas we produce and have an oil development before we have the gas plant onstream. We're looking at those things. As a pure trucking option of oil, we don't think that that's going to really work for us, although we haven't eliminated anything at this time.

Do you have a time frame for a decision?

Well, we're starting up the gas plant at the end of 2009--.

We know about that, but for the oil?

The oil. Well, first of all, we have to file a development plan, and we haven't finished appraisal. So we'll finish appraisal probably in the summer, October, something like that, and our goal is to file a development plan for the central area which will address any early oil option that makes sense at that time. And we have to get the development plan approved by the government. That's the time frame, is we file the development plan before the end of the year and the development plan will specify how quickly we can produce the oil.

Okay. Third question. When will you publish the '07 discovery? The new discoveries that you were talking about earlier today?

Well, we just indicated that we see the net pay on logs. We have not tested those wells yet, although we're very confident they'll test well, because there's a lot of similarities to the LES 3 well, which tested very well. As soon as we test those wells, we will be putting out a press release. Our usual operations updates that give our test results that are approved by Sonatrach.

Okay. So it's another three months?

Probably not that long.

Thank you.

Thanks.

Thank you. Our next question comes from Mr. Terry Peters. Please state your company name followed by your question.

Canaccord Adams. Good afternoon. I had one question was basically on getting early production from TAGI oil. I think you've addressed that and possibly looking at cycling schemes. But could you just remind me of the process that you see right now with respect to a decision on whether the gas plant could be expanded at this point in time? You obviously mentioned that you were in discussions with Sonatrach about that. What has to happen in order for that to occur, and does that -- do you continue with your FEED simultaneously and perhaps maybe towards the latter part of the year when you've done more appraisal work? Is that really when you would finalize the actual plant design?

No, we'll probably -- we'll go ahead with the FEED, the award of the FEED, and we probably have about six to eight weeks after the FEED starts before we have to fix the design on the plant size. So we have roughly two months. We already have a recommendation in front of Sonatrach. We've had several meetings with their technical staff, specifically addressing the size of the plant. Obviously, we have to make some projections before we have a development plan approved for the central area, because we're also including volumes of gas from the central area. But Sonatrach is on board with us. They don't see any advantage to building too small a facility. So we expect to get this resolved in the next month or two and we will fix the design of the plant at that time. But the FEED will not be hell up.

Okay. This is a follow-up. Will they at the same time recontract the amount of gas that they're going to take from you? And is it all under the same contractual arrangement that you currently have with respect to your pricing formula, et cetera?

They don't have to happen at the same time. As I've mentioned, Sonatrach wants more gas and they've indicated to us that when there's a sufficient comfort level with the reserve base to support higher plateaus, they will increase the ACQ of the contract. So they don't have to happen together. There's a certain comfort level you might get from fixing the ACQ before you make the decision on the size of the plant, but we're not concerned about that. Sonatrach wants to produce more gas. They derive most of the benefit from producing more gas and we're perfectly aligned in that respect.

Thanks. Not to belabor the point, but does that mean you will actually have an agreement, formal agreement with Sonatrach to build a larger plant when you put the pin in on finalizing the FEED? Prior to--?

It's a very -- they consider changing the size of the plant to be a design modification. It's not nearly as elaborate a process as was required to get the exploitation license. What it involves is a letter, basically, to [ALNAFT], the regulatory agency within the ministry saying we recommend that we do this. It's supported by Sonatrach and by the foreign company and then they ratify that and send you a letter saying it's approved. It's a very simple process compared to getting the development plan approved.

Okay. So if you go ahead with the larger plant, then that's the assumption or in reality is that you've got approval to sell additional volumes?

Implicitly, although we will, eventually we will also get the ACQ increased. Because if we get the ACQ increase, of course, it helps our borrowing capacity for project loans and so on.

That's what I was thinking, yes. Okay. Well, thanks very much. All right.

[OPERATOR INSTRUCTIONS] Thank you. We have a question from Mr. Frederike Kamphuis. Please state your company name followed by your question.

Frederike here at ING. I have a question regarding the tax again. You mentioned the 5% would like to be the worst-case scenario. Now, if I'm not mistaken, there's elections coming up in Algeria in May and then again in October. You feel confident enough in the political situation there at the moment to say that 5% would be the worst-case scenario?

John van der Welle just stepped away, this is Shane O'Leary. So I will attempt to answer your question. We have been told at various levels that the windfall profits tax will not apply to gas production. Now, as John indicated, we need to see that in writing. We need to see that clarified and if that is the case, if what we're being told is in fact what's ratified, then half of our revenue stream is not -- does not apply to the tax. The tax doesn't stream is not -- does not apply to the tax. The tax doesn't apply to half of our revenue stream. It would only apply to the liquids.

If you look at the tiers of how the tax applies, there is the first tier, is 0 to 20,000 barrels a day. The 20,000 barrels a day being your net entitlement. Which means what you get after your working interest and what you actually get from your production share. In order to meet the 20,000 barrel a day threshold to cross into the next tier, we would have to be producing over 80,000 barrels a day of liquids. We're very confident that if GAAP is excluded we will never get out of the 5% tier. So from our perspective, this tax was really directed at the oil producers and particularly the older contracts that were perhaps more generous than the more modern ones. We don't think we're the target of this and we're very confident that we're not going to suffer a big hit from this tax. Now, I don't think the elections have got anything to do with it because the tax has already been applied, whether it was for political purposes or not. It doesn't really matter.

The other thing that's worth pointing out, is we do have like everybody else in the industry a stabilization clause in our contract, which says that if a new tax is impose is imposed, that you will be kept whole in another area. Now, we are not leading the charge on that front. You've probably read in the press that some of the larger oil producers are threatening arbitration and other things. We will let them fight the battle on that one. That issue, by the way, is nowhere near resolved. I think it's going to take some time for this whole thing to settle down. We're quite confident when it does, it will not have a huge impact on us. Our liquids will probably be exposed to some of the tax, but only at the 5% level. Again, we're waiting for confirmation, just like everybody else in the industry.

Okay, thanks.

Thank you, sir. We have no further questions at this time. Please continue. My apologies. We have another follow-up question from Mr. Mehmet Khant. Please go ahead, sir.

Hi, Shane. I was wondering if you can answer on behalf of John if he's not back on just the time line for the project financing. Could you just walk through the -- to do your best estimate, just the time line as to when you expect to get -- hope to get the debt financing in place and then if equity financing and then when. And also, if you have been in talk, in conversation with some potential JV partners or some other form of financing? Could you just elaborate on that a little bit further?

Mehmet, this is John. Firstly, apologies to all listeners that I had to step out of the room momentarily. But in response to your question, Mehmet, really, I can't give you any more information other than what I have said in my remarks. The critical part for us is to ensure that the development financing is in place at the time that we signed the EPC contract. Because that is the point in time when we will commit to the construction and development activities as a whole and also the gas delivery obligations will be crystallized for us under the Gas Marketing Agreement with Sonatrach. So we would be imprudent, shall we say, not to have financing in place at that time and the project schedule is for that to occur by the end of this year, and therefore the financing needs to be in place by the end of this year.

So when you say financing, you mean you don't have to have the cash sitting on the balance sheet. You just need a commitment from--?

Well, that's right. The way these things work is that banks obviously -- if they're not financing the whole of the project, banks do look to there being certainty that the other sources of finance are in place and committed before they will permit drawdown. So it's really a combination of cash in the bank or other commitments which are considered to be acceptable and close to cash in the bank by the project lenders.

So, for example, if there's two sources, there's a source X and there's project finance, source X which makes up the balance between project finance and the total commitment has to be in place. Source X has got to be certain and the project finance from our perspective would need to be certain it that it is then drawable, it is committed and available before we as a company would want to proceed to sign the EPC contract. But we wouldn't actually draw it all down, because there's obviously a cost of carry in doing that. That project finance arrangement, you don't draw the cash in one lump and then deposit it, earning interest and then paying interest on the other side. What you would do is you would draw the cash under the project loan for the purposes of that project loan as a purpose test, obviously that's built into the loan structure and so as we spend the money on the development each month or by whatever range we ultimately agree, we will draw the necessary funds under the product loan. It's a mixture of cash in the bank, i.e. in the balance sheet, from source X in my example and the project loan being committed and available, but then not drawn until it's needed to be spent.

And the JV partnership, any potential out there or have you been talking to anyone?

We have had many approaches over the period that I have been at the Company since the start of last year of people who want to get involved in financing this project and this is from both financial-type players and also from industry-type players. We have taken the view that we should progress hitherto on the basis that we will source the financing from the best sources according to the criteria I said in my remarks of maximizing shareholder return and so that's what we are continuing to do. When we have a financing plan, we're not going to announce the plan to the world, we'll announce the execution as it occurs.

Okay. Thank you.

Basically, Mehmet, the bottom line is, you aren't going to get told everything in advance precisely because it's just not the way it works. We will determine the financing plan and then we'll announce what we're doing at the appropriate time and all the arrangements need to be in place by the end of the year, and that's it.

Thanks. The next question comes from Mr. [Alec Balfrey]. Please go ahead, sir.

Hi, Rick. It's Alec Balfrey, Haywood Securities Calgary. I just wondered what your current cash position and what your burn rate is a month on drilling?

That is information which is not going to be disclosed. We have a drilling program, we're operating in two rigs, I'm afraid I can't give you that because it's not in the financial results.

Okay, thank you.

Thank you, sir. We have no further questions at this time.

Thank you. Well, on behalf of First Calgary, I would like to say thank you all for listening to us and we do have a presentation which we are told is now on the website and obviously that will provide some additional pictorial color to the presentation that's been made today. On behalf of my colleagues, thank you very much.

Ladies and gentlemen, this concludes today's First Calgary Petroleum 2006 results conference call. Thanks for participating. You may now disconnect.