John Hess - Chairman & Chief Executive Officer John Rielly - Senior Vice President & Chief Financial Officer Greg Hill - Executive Vice President & President of Worldwide Exploration & Production Jay Wilson - Investor Relations

Evan Calio - Morgan Stanley Paul Cheng - Barclays Capital Arjun Murti - Goldman Sachs Neil McMahon, Sanford Bernstein Robert Kessler - Simmons & Co Mark Flannery - Credit Suisse Blake Fernandez - Howard Weil Paul Sankey - Deutsche Bank

Thank you very much. Good morning everyone, and thank you for participating in our third quarter earnings conference call.

Our earnings release was issued this morning and appears on our website www.hess.com. Today’s conference call contains projections and other forward-looking statements within the meaning of the federal securities laws.

These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. With me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President of Worldwide Exploration and Production; and John Rielly, Senior Vice President and Chief Financial Officer.

I will now turn the call over to John Hess.

Thank you Jay and welcome to our third quarter conference call. I will make a few brief comments, after which John Rielly will review our financial results.

Net income for the third quarter of 2009 was $341 million versus $775 million a year ago. Our results were negatively impacted by sharply lower crude oil and natural gas selling prices, and lower marketing and refining margins, which more than offset the positive impact of higher crude oil production volumes.

For the third quarter of 2009, exploration and production earned $397 million. Crude oil and natural gas production averaged 420,000 barrels of oil equivalent per day, which was 16% above the year ago quarter.

This increase resulted primarily from higher production from the Shenzi field in the deepwater Gulf of Mexico, and the Malaysia-Thailand joint development area, and the resumption of production from the Gulf of Mexico that was shut in during last year’s third quarter due to Hurricanes Gustav and Ike. As a result of strong year-to-date production performance, we have raised our full year 2009 production forecast to a range of 400,000 to 410,000 barrels of oil equivalent per day, versus our previous estimate of 390,000 to 400,000 barrels of oil equivalent per day.

With regard to exploration, drilling is continuing on Permit WA-390-P in the North West Shelf of Australia, where Hess has a 100% interest. We have now completed nine wells and expect to drill the remaining seven wells of the program by mid 2010.

In Libya, the Stena Forth drill ship is expected to arrive soon on location in Area 54, where Hess is the operator and has a 100% working interest. We intend to perform a drill stem test of our 2008 Arous Al-Bahar discovery, which encountered 500 feet of gross hydrocarbon column, and also drill a down dip appraisal well to delineate the prospect.

Turning to marketing and refining, we reported a profit of $38 million for the third quarter of 2009. The weak economy continued to have a negative impact on both margins and volumes.

Refining margins at our HOVENSA joint venture refinery were significantly lower than the prior year quarter, as a result of lower distillate crack spreads and narrower light/heavy crude differentials. Marketing results were weaker than the year ago quarter, reflecting lower margins and volumes.

Retail marketing gasoline volumes on a per site basis were down 6%, while total convenience store revenue was up 12%. In energy marketing, electricity and fuel oil sales were higher, while natural gas sales volumes declined year over year.

The improvement in crude oil prices and increase in our production volumes during 2009, have enabled us to fund most of our capital and exploratory expenditures with internal cash flow. We remain committed to maintaining our financial strength, so that we have the capability to fund the future growth of our reserves and production.

I will now turn the call over to John Rielly.

Thanks John. Hello everyone.

In my remarks today I will compare third quarter 2009 results to the second quarter. Third quarter 2009 consolidated results amounted to net income of $341 million compared with $100 million in the second quarter.

Turning to exploration and production; exploration and production operations in the third quarter of 2009 had income of $397 million, compared with $215 million in the second quarter. The third quarter included after tax income of $89 million, relating to the resolution of a royalty dispute on production from certain leases subject to the US Deep Water Royalty Relief Act, while the second quarter included after tax charges of $31 million.

Excluding the items affecting comparability and earnings, the after tax components of the improvement in results are as follows: Higher crude oil selling prices increased earnings by $108 million. Lower sales volumes reduced earnings by $55 million.

Lower exploration expense increased earnings by $81 million. Higher operating costs, including DD&A, reduced earnings by $76 million.

All other items net to an increase in earnings of $4 million, for an overall increase in third quarter adjusted earnings of $62 million. In the third quarter of 2009, our E&P operations were under-listed compared with production, resulting in decreased after tax income of approximately $35 million.

On a year-to-date basis, production and sales are approximately equal. The E&P effective income tax rate, excluding items affecting comparability between periods was 38% for the third quarter and 49% year-to-date.

The effective tax rate was lower in the third quarter due to the mix of income from varying tax jurisdictions, and our under-listed position in the third quarter. The E&P effective income tax rate for the full year, excluding items affecting comparability between periods, is now expected to be in the range of 47% to 49%.

In early October 2009, the US Supreme Court decided it would not review the ruling by the Fifth Circuit Court of Appeals, relating to royalty relief under the Deep Water Royalty Relief Act of 1995. During the period from 2003 to 2009, the corporation accrued royalties for the contested leases.

Following the Supreme Court’s decision, the corporation recognized an after tax gain of $89 million in the third quarter of 2009. The pretax income of $143 million is included in other non-operating income.

Approximately $7 million of the after tax gain related to 2009 operations. Turning to marketing and refining; marketing and refining operations had income of $38 million in the third quarter of 2009, compared with a loss of $30 million in the second quarter.

The third quarter included a benefit of $12 million due to an income tax adjustment relating to our refining operations. Excluding the item affecting comparability, results of refining operations amounted to a loss of $15 million in the third quarter, compared with a loss of $26 million in the second quarter.

The corporation’s share of HOVENSA’s results after income taxes, amounted to a loss of $30 million in the third quarter compared with a loss of $46 million in the second quarter, primarily reflecting improved margins. Port Reading earnings were $16 million in the third quarter, compared with $19 million in the second quarter.

Marketing earnings were $35 million in the third quarter of 2009, compared with a loss of $13 million in the second quarter, principally reflecting higher margins in retail operations. Trading activities generated income of $6 million in the third quarter, compared with income of $9 million in the second quarter.

Turning to corporate, net corporate expenses amounted to $33 million in the third quarter of 2009, compared with $26 million in the second quarter. Net corporate expenses were higher in the third quarter, primarily due to higher bank facility fees and timing of expenses.

After tax corporate expenses in 2009 are estimated to be in the range of $145 million to $150 million, excluding items affecting comparability. Turning to cash flow; net cash provided by operating activities in the third quarter, including a decrease of $557 million related to changes in working capital was $534 million.

The principal use of cash was capital expenditures of $604 million. All other items amounted to a decrease in cash flow of $36 million, resulting in a net decrease in cash and cash equivalents in the third quarter of $106 million.

We had $957 million of cash and cash equivalents at September 30, 2009, and $908 million at December 31, 2008. Our available revolving credit capacity was $3 billion at September 30, 2009.

Total debt was $4.379 billion at September 30, 2009, and $3.955 billion at December 31, 2008. The corporation’s debt to capitalization ratio at September 30, 2009 was 25.2%, compared with 24.2% at the end of 2008.

This concludes my remarks. We will be happy to answer any questions.

I will now turn the call over to the operator.

I had two questions; my first question John is regarding capital structure. I know your opening language has softened over the last few quarter introductory comments, and omitted here in your opening comments that you just made was regarding potentially accessing the debt or equity markets, which was a potential overhang and a concern for some investors.

Clearly as market conditions have improved, commodity markets have improved, your cash flows have improved. I mean is it safe to say that in a reasonable price band in the commodity, that this potential overhang has largely been mitigated or was there any other additional element that maybe I didn’t appreciate with regard to increased capital spending into 2010 etc.?

It’s a fair question. Obviously the financial condition and some headwinds we were facing in the last few conference calls of lower prices, and I would say fairly uncertain financial markets weighed on our mind in terms of how we would fund our future growth.

Obviously since then the oil prices improved, as well as the financial markets. So as a consequence, as we look forward, we feel pretty good that the majority of our future funding requirements will be met from cash flow from operations going forward, but we will also continue to do what is required to ensure our balance sheet is sufficiently strong to fund our growth of reserves and production for the long term.

So as a consequence, we will always have as an option redeploying capital internally through asset sales or maybe even bringing partners in for some of the exploration prospects that we have as they mature, and also raising new capital externally in the form of debt or equity. As you know, we accessed the public debt market in the first quarter for $1.25 billion.

All this is on the table, and I think that’s the real takeaway.

And my second question if I may, in the last conference call we talked about potential unitization of Pony and the discussions you have with Knotty Head partners, ongoing yet premature. This morning lynxes announced that they’ve finally taken delivery of a rig, with results in its delineation well expected in the second quarter of 2010.

Would it be fair to assume that it is going to be after those parties have figured out what they have, that we would expect some potential decision regarding unitization of those blocks, meaning it’s something in a mid 2010 type of event?

Thanks Evan, this is Greg. No, that’s not the intention at all.

The discussions are ongoing as we speak. We’re getting very close to final agreement.

We’re drafting agreement documents, so the timing of actual unitization is not contingent on the results of the well. We will have an equity re-determination later after the results of the well are known, but those two are not contingent on each other.

I think this is first for Greg. Greg, on Bakken, I know that you guys have been doing some additional drilling.

Can you give us an update in terms of what the program may look like in 2010 regarding about the CapEx or the number of rig? Also is there any operating data you can share with us in terms of the reserve per well, production per well, after the initial 30 day job and also the CapEx per well type of information?

Yes, thanks for the question Paul. Where are we now?

We’ve got 135 wells in the ground. We’ve got three rigs operating in the Bakken.

We’re in the middle of our 2010 budget and operating plan exercise, so we haven’t yet finalized our plans on the Bakken, but what I will say is, what we plan to do is significantly step up activity there. I believe in our recent meetings with you, we told you that we are planning to take the Bakken up to about $1 billion investment program over the next four or five years, and a 10 rig program.

So that’s kind of what we’re contemplating. Now, obviously we will ease into that, feather into that over say an 18 month period and get up to that 10 rig level.

So that is currently what we’re contemplating now, but we have not finalized that yet with our Board.

So should we assume that next year we may be talking about five to six rigs, and you’re talking about $500 million tie up investment?

Yes, I think that’s a good assumption. I would go north of that a bit.

So I think we’ll ease into it, get up to six or seven rigs by the end of the year. So it could be as much as $800 million or so in investment next year.

And I presume that that should allow you to grow the Bakken production from currently about 10 to maybe about into 15 or so?

I won’t give you that detail yet. As we said, and as in our investor handout, what we contemplate doing is growing the Bakken to about 80,000 barrels a day over a five year period.

Greg, is there any additional data you can give about the Espirito Santo Basin? Where are we in terms of the drilling?

When are we going to be complete on that well?

So we just completed that well literally. We’re now pulling riser and pulling anchors.

So that well has been completed. As you said, it is an Espirito Santo well, so it is a post-salt well; it is not a pre-salt well, as is the BMS 22 block.

We’re complete on the well, and we encountered noncommercial quantities of hydrocarbon, so the costs associated with that well will be expensed in the fourth quarter. We are the operator of the well.

We farmed it down, so we only had a 30% working interest in the well.

Along that line Greg or maybe this is for John, you have some very large exploration acreage that you have 100% interest, like in Ghana and in Libya Area 54. What is the overall logistic view from the corporation in terms of farming those down?

When will be a good idea to farm down to de-risk yourself or do you think that because there is opportunity there, that you really want to hold onto the entire 100%?

I think on both of those cases, we’re in the midst of processing seismic and finalizing our plans there. So I think it is premature to talk about what our commercial strategy is going to be.

The way we approach this is we look at every well individually, we look at the risk profile, and make an informed decision on whether we want to farm down or not.

I know I’ve taken up enough time. Two final quick questions; one, in Australia, seven wells you’ve already drilled.

Can you tell us how many of them is a success and how many was dry? And the last one will be for John Rielly; for the $89 million royalty resolution gain, I missed that, you said some of them is for 2009 operations.

How much is that? Thank you.

So turning to Australia, just for clarity we have nine wells done now between last year’s program and this year’s program. Recall we drilled four last year.

One was a dry hole. We’ve got five under our belt this year, one of which is a dry hole, which John will address in terms of the exploration expense this quarter.

So the total program so far, eight wells are a success, three from last year and five from this year?

Yes, we’ve got nine in the ground, and two have been declared dry holes or non-commercial.

And then Paul, from your question on how much of the royalty relief was in 2009, $7 million after tax was related to 2009 operations.

My question is on your unconventional gas strategy. You entered the Marcellus this quarter with a venture with Newfield; can you talk about where you see your interest in unconventional gas over the years?

Do you want to really build that up and enter a number of these plays or you are focused on the Marcellus? I’m just trying to see how much interest you have long term in that slight change in strategy.

Thank you.

Thank Arjun. I think you set some context first.

So our thinking about this is, if you take the long view and you look at where the energy mix in the world is going to come from in the future, clearly unconventional is going to play a big part, not only in oil, but also in gas. So we feel we need to build a position in both of those areas.

Now in unconventional oil, obviously we’ve got the Bakken, and we felt like to round out a portfolio we wanted to build a position in unconventional gas. That’s going to be confined right now to the Marcellus.

As you have seen in the press, we partnered with Newfield for up to 140,000 acres in the Marcellus with them. They will operate, and then we will make an informed decision as we learn about the Marcellus and the areas where we are, as to whether we want to go bigger or smaller or whatever.

So that is kind of where we are.

I guess unconventional gas in the US is one of those things where it seems like the most successful companies are exclusively focused on it, and I just wondered if it is really something for the majors to do on a part time basis, one project depending on the portfolio. You’ve obviously taking an entry level position here, but that’s probably where more of the question is.

Can this really be part of the majors? I’m going to use the phrase of part time basis, where it’s one of many projects you have?

Yes, well I think it can, because if you look at what we’re doing on the Bakken in terms of completion techniques and all that, it is very similar, and we’re being very successful in the Bakken. So I don’t think there is anything unique about unconventional gas that you have to be 100% focused on it.

Again, in the Marcellus we’ve taken a good partner, a proven unconventional gas player in the form of Newfield. So we feel like we’ve got a good mix and a good partner there.

Really, it’s a question around the Bakken again. If you look at your upcoming expansion program, I think what you were trying to do is get enough oil service contracts in place to begin with to do that program, which would require at least some idea of upfront CapEx associated with that program.

Can you give us an idea of the sort of numbers you were thinking about in terms of the CapEx outlook for the next few years, maybe next five years on the Bakken? Then secondly, I don’t think you explicitly said that you were not going to do an equity issuance.

Is there something you can categorically say over the next six months or so, given where we’ve got to with oil and gas prices, to take that sort of risk out of the market? Thanks.

Let me address the Bakken question, and then I’ll turn it over to John for the equity question. As we said on the Bakken, we haven’t finalized our plans with the Board yet, but what we are contemplating is taking the Bakken up over time, so over about an 18 month period to a 10 rig program, which would equate to about $1 billion a year.

So our plans contemplate a $4 billion to $5 billion spend over the next four to five years in the Bakken. Next year it will probably be around $800 million, although we haven’t finalized our plans yet.

So you can assume $800 million walking up to $1 billion a year thereafter, and the production that follows that will be a peak rate of 80,000 barrels a day at the end of five years. So that’s currently what we are contemplating for the Bakken.

And Neil, a fair question, oil prices obviously have strengthened our financial ability to fund our capital requirements from internal cash flow. As we go forward, even though the need on CapEx which we’ll define in the January call further for 2010, the need for that will be met for the most part by internal cash flow, we’ll always keep the option of asset sales, and we’ll always keep the option of accessing the markets for debt and equity.

So those options are going to be there, but the majority of our needs will continue to be met by internal cash flow.

Maybe John, just put it another way, since it is a major issue, that’s right there. Is there a sort of oil prize that you could give us, that if we had a blended price of $65, $70 per barrel oil equivalent, is that what you would foresee as sort of safety level when you look forward, including the expansion in the Bakken for assessing that you’re going to be able to fulfill your capital needs from your ongoing operations, just to get a handle on it?

Yes, of course. Obviously $60 is better than $45, and $80 is better than $60.

So these higher prices have helped our financial position, to fund our growth requirements, and yet at the same time we are going to keep the options ahead of us in terms of asset sales and accessing the markets externally in terms of debt and equity, because it would be foolish of us to do otherwise.

Just want to circle back to the potential for farm-outs of your acreage, and going back to Ghana, I recognize that you still were running through the seismic, and I assume you plan on poking a hole there in 2011. Just conceptually though, assuming you were approached by a major before that point, with that major interested in farming into the acreage, would you be willing to farm down your interest there or do you want to wait until you’ve actually got drilling results no matter what before de-risking that block?

I think in all of these Robert, the first thing is we have to get our homework done. So we’ve got to get our 3D seismic fully processed, then we’ll understand the risk profile of the well itself.

So that will give us a piece of data and then we can figure out whether or not what our commercial strategy will be, based upon the risk profile of the well. Now I will tell you, there is nothing that really scares us about Ghana.

If you look at a development concept, it’s an FPSO. Its things we’ve done in Equatorial Guinea.

So you have to ask yourself, what does a partner really bring, and so that’s how we think about these things. What is the risk profile of the well, do we need a partner, can a partner bring something unique to the party, and certainly, how much capital will it take, and do we need a partner just to share that capital?

But we are not in a position to say one way or the other yet, until we get all the seismic reprocessed on that block.

A couple things; first, on the lifting variance John, and its potential implications on the foreign tax rate, is it safe to assume that you were very, very heavily under-lifted in Libya, and that that is what accounted for the abnormally low international tax rate?

That is clearly part of it. Libya was I guess the second country with the most under-lift, and the other one was Norway.

So our two highest tax countries, Norway and Libya, is where the predominance of the under-lift were and that’s what drove the rate down.

Okay. I was hoping we might get a little bit of a performance update on Shenzi.

Initial indications were that it was exceeding by about 20% estimated plateau rates. I would also appreciate some clarification as to whether the DD&A rate on Shenzi is exceedingly high, and thus accounted for the significant step-up in US DD&A in the quarter.

Mark, I’ll start with the DD&A. The DD&A rate for Shenzi is clearly higher than our portfolio rate, and that is what is driving DD&A up.

Again it’s typical. It’s not like it’s unusual for Shenzi.

It will come down over the life of the field, but you’ve got the high capital from the development starting up with the low reserves that are initially booked, and then as performance comes in, the rate will come down, but you’re absolutely right, that is what is driving the DD&A rate. Now on the flip side, Shenzi is a very low cash cost field.

So if you’ve noticed, especially in the US, you can see where our cash costs per barrel are coming down and that’s what Shenzi is providing for us. So overall when you look at it from our cash costs and our DD&A, I’d given unit cost guidance of between $27.29.

Year-to-date right now, our unit costs are running at $27.30 and what’s going to end up happening is, on the cash side we’re actually going to be coming below our guidance, again due to cost reduction efforts and the increased production from Shenzi, and we will be at the higher end of our DD&A, or probably above the top of the range of the DD&A rate due to Shenzi, but overall, we’re going to come in in our guidance.

John, can you be just a little bit more specific in terms of the numbers? What does the full-field DD&A rate look like on Shenzi or what was the full-field development cost, and how does that compare to the rate that you were accruing at in the third quarter?

I’m sorry Mark, we don’t give specific rates out on a field. We don’t get to that kind of individual field kind of economic data, but what I will tell you, I mean our DD&A rate that’s running $15.60 during the third quarter, Shenzi right now is above $20.

It’s running above $20 and will be coming down as the field continues to perform and we book more reserves.

Okay, John if I could, just one more, it looks like after adjustment if my arithmetic is correct, and that’s always subject to question, that the R&M, refining and marketing tax rate in the quarter was exceedingly low, am I missing something?

No, you’re not missing anything. So if you adjust as you said for the income tax adjustments, the rate is still low, and what we have Mark, one is some small adjustments as you get to the smaller income levels, it drives it.

We also have income from our St. Lucia terminals, and down there we are not charged income tax on that income down at St.

Lucia. We have other throughput costs and things like that that we pay, but the income tax, we have a holiday down there at St.

Lucia, and that drives down our income tax rate at lower income levels.

I have a question on HOVENSA. Could you maybe comment on what you’re doing operationally there in terms of continuing to idle part or all of the plant, and are you seeing any pickup in recent weeks in the economics available to HOVENSA which might make you change what you do in the fourth quarter?

From my understanding Mark, no, the reduction in rates, be it in the crude units or the coker, are purely a function of the poor refining economics that existed in the third quarter and continue to exist today. So no, we don’t see a material change right now.

My question is actually back to the Bakken. I’m just curious, as the program ramps up over time, what kind of transportation issues you foresee, and how that might impact differentials and realizations going forward.

Thanks.

Yes Blake, obviously in the Bakken, that is an issue for all of the operators, and we’re in the midst of developing a very detailed and comprehensive transportation strategy to get the liquids out of the basin. So I can’t comment too much more than that, because it is a bit competitively sensitive, but suffice to say we’re on it, and we’re looking at multiple options to get our crude out.

If I could kind of go back to the cash breakeven or the oil price breakeven question, looking at your summary cash flow, you’ve got about $534 million, including working capital changes or cash flow, and then around about $700 million if I include dividend payments of cash out. So extensively you’re, whatever that is, $170 million cash negative in the quarter.

Would it be unfair then to say that you’re not breaking even at $68, which is the average oil price for the quarter, because I shouldn’t be adding in some working capital issue or there is some other issue that makes that an unfair comparison, and if we could look back over the year, it’s been fascinating so far as you’ve had $50 in Q1, $60 Q2, arguably about $70 Q3. Can we use that as a way of iterating back towards where we think you do break even cash-in, cash-out, and could I then also confirm that you are using $60 as a planning assumption, which I think has been a prior statement, but I’m not sure if it’s still correct?

Thanks.

Sure. Just to go over it, and yes, I would say there are some unfair comparisons in the numbers.

I would not include working capital. So for instance, it will turn around, and we had a big working capital decrease this quarter that was $557 million.

So let me just give you cash flow from operations. So our cash flow from operations was close to $1.1 billion in the third quarter, and that is up from $700 million in the second quarter.

So we’re getting the benefit from the higher prices. When you look at our CapEx, and you pull the $668 million that is capital spend, that also double counts the exploration expenses.

So really, you have to pull out $64 million of exploration expenses that are included in that spend. So for the quarter, with working capital, we were just over $100 million from a deficit standpoint, but as I said, there’s $557 million of working capital change in there, and I know some of that is clearly going to turn around in the fourth quarter.

So our cash flow, actually from our operations is quite strong, and if you want to say from a breakeven standpoint, we were clearly cash flow positive from an operations standpoint and CapEx this quarter.

Yes, that’s absolutely fair enough. I know there’s obviously a big cost issue also underlying all this, but if we were to go back to Q2 John, knowing that you know the numbers off the top of your head, could you provide us how the same numbers looked in Q2?

Sure. We had $700 million of cash flow in Q2, and you have to pull out $100 million of exploration expenses that was already in our net income number and is in that capital spend number.

So we had $700 million of cash flow from operations, and had $685 million of capital expenditures, so again, basically breakeven then in the second quarter.

I think we got the answer, but of course the costs are going to be an issue, which I guess we could talk more about if we had more time. If I was to keep pressing on that, just the planning assumption, is that still 60?

We certainly have 60. We certainly test for lower prices.

We also test for the strip. So it’s a range of prices we look at to test the resiliency of the investment opportunities we have.

So it’s not an iron clad one number deterministic. It’s obviously risk business, and part of the risk is price, and we formulate that in our investment decisions, but I think one takeaway that you can get is that, now that we’ve sort of gone through this very difficult period of oil prices, as well as financial markets, we will start looking at investing for growth in 2010, and the specifics of that capital program, no later than the January call we’ll be able to give you more specifics on our program for next year.

Yes, but you have seemed to be and I think almost directly saying, that you expect CapEx to be up somewhat, all things equal I guess is the way to control that next year John?

Obviously, with what Greg was saying with the Bakken, that in and of itself will drive the number higher.

Yes sure. The year-to-date is actually behind your guidance, if I’m not mistaken, on CapEx.

Is there going to be a big jump in Q4, or are you just running behind?

We’re staying with our $3.2 billion of capital spend, and including our exploration spend, and we are staying with out guidance. We’ve always had our fourth quarter was a bit backend loaded in our CapEx plans.

I was told I was the last question, so I’m just going to keep going on if you don’t mind. The volumes, you did have a big under-lift here obviously, and you’ve then raised your guidance, but it still seems you are behind, assuming that you get the under-lift back in Q4, it still seems to be conservative full year guidance, given that we’re pretty close to knowing what the average has to be.

You would have to step volumes down for Q4 to be within the range that you have given.

No. I mean again, with everything we’re seeing right now, and again, the under-lift that doesn’t come into our consideration for our production guidance.

So we’re sticking with that 400,000 to 410,000 of production guidance now for the full year.

The under-lift doesn’t count?

The under-lift is the way we record revenue. So when you hear production, like the 420,000 barrels of production, that is literally the barrels that we produce in the quarter.

However we didn’t sell all those barrels. We were about 2 million barrels short, a little over, I guess 2.1 million barrels short on sales of those barrels.

So that affects our revenue line; however when you hear our production numbers, that is always the amount of production that is produced from our fields.

Yes, that makes perfect sense. Then if we were to look into 2010 on the volume side, I think it’s a 3% to 5% volume expectation, or is the fact that we’ve sort of advanced the volumes going to put you towards the bottom of that range?

Are there any implications to your view for 2010?

A fair question Paul; we’ll give that number, what our guidance for 2010 is, in January.

Right okay, but essentially we’re still working off a 3% to 5% volume target?

I just said we will give you our guidance for 2010 in January.

I just wanted to close the loop on the Shenzi performance. Are we still looking at about 120 a day gross on the platform as we speak today?

Yes. Certainly on a net basis in the quarter, Shenzi was operating between 35,000 and 40,000 barrels a day net, and it averaged 38,000 for the quarter.

So Shenzi is performing very well and continues to do so. Obviously, how long the peak lasts, all that depends upon the influence of the aquifer and we are monitoring pressures daily, but so far so good.