赫斯 (HES) 2012 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2012 Hess Corporation earnings conference call. My name is Chanelle and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn our conference over to Mr. Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, Chanelle. Good morning, everyone, and thank you for participating in our first-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, Worldwide Exploration and Production; and John Rielly, Senior Vice President, Chief Financial Officer. I'll now turn the call over to John Hess.

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

Net income for the first quarter of 2012 was $545 million. Compared to the year-ago quarter, our earnings were negatively impacted by lower crude oil sales volumes and higher operating costs, which more than offset the impact of higher realized crude oil and natural gas selling price. Exploration and production earned $635 million. Crude oil and natural gas production averaged 397,000 barrels of oil equivalent per day, which was roughly flat with the year-ago quarter.

Higher production from the Bakken in North Dakota, the Pangkah Field in Indonesia, and the Malaysia/Thailand joint development area, offset the impact of North Sea natural gas asset sales and natural field declines in Equatorial Guinea. In North Dakota, net production from the Bakken averaged 42,000 barrels of oil equivalent per day in the first quarter, compared to 25,000 barrels of oil equivalent per day a year-ago quarter. Thus far in April, net production from the Bakken has averaged 47,000 barrels of oil equivalent a day.

While we expect the monthly average to continue to increase throughout the rest of the year, we now expect the average for the full year may come in somewhat lower than our original estimate of [60,000] barrels of oil equivalent per day. As usual, we will update this estimate as well as our overall Company production forecast on the July conference call.

At the Llano Field in the deepwater Gulf of Mexico, the operator is currently performing a workover on the Llano number 3 well, which was shut in for mechanical reasons the first quarter of last year. We expect that production from this well will resume by the end of May. At Valhalla, Norway, field redevelopment is expected to be completed in the third quarter. Net production averaged 22,000 barrels of oil per day in the first quarter.

In Libya, net production averaged 18,000 barrels per day the first quarter and has averaged 21,000 barrels per day (technical difficulty). With regard to exploration in Ghana, on March 27, we spud the Hickory North well in the Deepwater Tano/Cape Three Points slot. This prospect is located 3.5 miles west of our Paradise discovery, and the well will test reservoirs similar to those found at Paradise as well as deeper targets.

Following completion of Hickory North, we plan to drill a prospect called Safili, a large structure located approximately 5.5 miles southeast of Paradise. as a result of recently signed farm-out agreements, which are subject to final government approval. Hess's working interest in the block will be reduced from 90% to 35%. Offshore Brunei, the Julong East well on block CA-1, in which Hess has a 13.5% interest, encountered hydrocarbons and the operator is currently evaluating the development. The rig has now moved to the southeast to spud the Dagas East well, which will test and offset the Gumasis Field currently under development on (technical difficulty) side of the border.

Later in the second quarter, we plan to resume exploration drilling in the deepwater Gulf of Mexico. Hess Deep, located in Green Canyon 507, is a Miocene prospect in which Hess has a 50% working interest, BHP has the remaining 50% as the operator.

Turning to marketing and refining, we reported net income of $11 million for the first quarter of 2012. The previously announced shutdown of the HOVENSA joint venture refinery was completed in the first quarter. As a result of the charts taken last quarter, there was no net income impact from HOVENSA's first-quarter operations.

Marketing earnings were $22 million compared to [$68 million] at last year's first quarter. Retail marketing faced rising wholesale prices during the first quarter, which puts pressure on fuel margins. Gasoline volumes on a first (technical difficulty) base were flat, while the total convenience store sales were down 2% versus last year's first quarter. Energy marketing earnings were lower than last year's first quarter as a result of significantly warmer weather this past winter.

With regard to asset sales, in the first quarter, we closed the sale of our interest in Snohvit Field in Norway for $132 million, and entered into an agreement to sell our interest in the Bittard Field in the United Kingdom, which is expected to close in the fourth quarter. Also in March, we announced that we have started the sale process for our St. Luther oil firm.

Additional asset sales are in progress, and we will provide updates as soon as details become available. We anticipate that proceeds from asset sales, along with internally generated cash flow, will fund the majority of our capital exploratory (technical difficulty) in 2012. Our principal focus this year continues to be on execution and the sustained profitable 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 results from the first quarter of 2012 to the fourth quarter of 2011. The Corporation generated consolidated net income of $545 million in the first quarter of 2012 compared with a net loss of $131 million in the fourth quarter of 2011. Excluding items affecting comparability of earnings between periods, the Corporation had earnings of $509 million the first quarter of 2012 compared with $394 million in the previous quarter.

Turning to exploration and production, exploration and production had income of $635 million in the first quarter of 2012 compared with $527 million in the fourth quarter of 2011. First-quarter results included a gain of $36 million related to the sale of the Corporation's interest in the Snohvit Field offshore Norway. Excluding the effect of the asset sale, the change in [assets-backed] components of the results were as follows. Lower sales volume decreased earnings by [$16 million]. Higher realized selling prices increased earnings by (technical difficulty). Lower exploration expenses improved earnings by $94 million.

Higher cash costs decreased income by $29 million. All other items [net] to an increase in earnings of $13 million, or an overall increase first-quarter adjusted earnings of [$72 million]. Our E&P operations were underlifted in the quarter compared with production, resulting in decreased after-tax income of approximately [$35 million]. The E&P effective income tax rate for the first quarter of 2012 was 40%, excluding items affecting comparability of earnings between periods.

Turning to marketing and refining, marketing and refining generated income of $11 million in the first quarter of 2012 compared with a loss of $561 million in the fourth quarter of 2011. Marketing earnings were $22 million in the first quarter of 2012 compared with $48 million in the fourth quarter of 2011, principally reflecting lower margins and volumes in retail operations. In refining, [core rating] operations incurred a loss of $6 million in both the first quarter of 2012 and the fourth quarter of 2011.

As discussed last quarter, HOVENSA reported losses of $592 million in the fourth quarter of 2011, which included an after-tax charge of $525 million due to the refinery shutdown. In the first quarter of 2012, trading activity generated a loss of $5 million compared with a loss of $11 million in the fourth quarter of 2011. At December 31, 2011, the Corporation had an accrued liability of $487 million for its share of future fundings (technical difficulty) shutdown of HOVENSA's refinery in St. Croix. The Corporation, along with its partner, fully funded their estimated commitments in the first quarter of 2012.

Turning to corporate, net corporate expenses were $38 million in the first quarter of 2012 compared with $40 million in the fourth quarter of 2011. Aftertax interest expense was $63 million in the first quarter of 2012 compared with $57 million in the fourth quarter, reflecting higher borrowings and bank facilities.

Turning to cash flow, net cash provided by operating activities in the first quarter, net of funding of the accrued liability to HOVENSA of $487 million, was $988 million. Capital expenditures were $1,878,000,000. Net borrowings were $889 million. Proceeds from asset sales were $132 million. All other items amounted to a decrease in cash of $86 million, resulting in a net increase in cash and cash equivalents in the first quarter of $45 million.

We had $396 million of cash and cash equivalents at March 31, 2012, and $351 million at December 31, 2011. Total debt was $6,978,000,000 at March 31, 2012 and $6,057,000,000 at December 31, 2011. The Corporation's debt to capitalization ratio was 26.7% at March 31, 2012 compared with 24.6% at the end of 2011.

This concludes my remarks. We'd be happy to answer any questions. I will now turn the call over to the Operator.

(Operator Instructions). Doug Leggate, Bank of America Merrill Lynch.

I've got a couple of questions, if I may. First of all, on the progression in your -- in production guidance, I wonder if you could help us reconcile what's going on there? Because basically, if you look at the latest, some public well got that from the state. It looks like your production is, in the vast majority of the wells you've drilled at least in the last six months or so, are coming in substantially better than the tight curve guidance that you gave us, I guess, last September.

So if you could help us understand how that reconciles with the potential risk of the [60,000 of the number] on how you expect that progression through the year? And I've got a couple of follow-ups, please.

Okay, thanks, Doug. I guess before I answer your question directly, let me just provide a little context on the Bakken. So the growth from the Bakken continues with our production averaging 42,000 barrels a day in the first quarter, which is up 11% fourth-quarter and 68% from the first quarter of 2011.

In the first quarter, we had 14 operated rigs running, we drilled 37 new wells and completed 52. So that means we currently have [142 34-plus] stage systems in the ground with 112 on production. 86 of these wells have been on production for at least a month and have an average 30-day IP of around 900 barrels a day. So, obviously, very encouraging results.

Now, although first-quarter production was a little lower than planned, due to a combination of factors which included changes in well mix, resulting from HPV requirements, and some permitting model mix, we continue to make progress drilling efficiency and remain on a very solid growth trajectory. And over the remainder of the year, Doug, we plan to add two more rigs, going from 14 in first-quarter to 16 and 17 for the balance of the year, and then modify our mix focus on drilling activity, higher productivity, and higher (technical difficulty) areas, while still meeting HPV requirements.

Now, as John said, while we expect the production to see an increase throughout the year, the average for the full year may come in somewhat lower than our original estimate of [60,000] barrels a day. As usual, we'll provide an update of that on our July conference call.

So, Greg, just picking up on some of your comments there, so the working interest in the wells you've been drilling early on in HPV are lower than what you're going to do in the second half of the year? Is that -- would you just describe there?

Yes, we're going to increase the working interest wells in the latter part of the year with what we're drilling (technical difficulty).

So can you give an indication as to what the difference is in the working interest between the early wells and the later wells?

No, I can't, Doug. I can't give you average between (technical difficulty). Suffice it to say it's going to be drilling (technical difficulty) wells.

Okay. I don't want to push this point too much, but the IP rates, Greg, appear to be substantially better on some of the more recent wells. Can you comment on what's changed there?

Yes. So, like my comments were around well mix, so as you know, we're an APB, Doug, which means that we're focused on getting acreage held by production rather than focusing on sweet spot. So not surprising, while in this mode, we expect to experience some variability in IPs first quarter. We drilled some areas which had somewhat lower IPs, but they still have very good economics.

Okay. My only other question really is on the CapEx. The first quarter number looks disproportionately high compared to the guidance for the year. Can you talk about -- are we looking at any acquisitions in there? How does it change your guidance? Or maybe was there an explanation as to why it's so front-end loaded? Now I'll leave it at that. Thanks.

Sure. Thanks. As you know, it's still early in the year, and as usual, provide an update to the capital [spend] guidance on the 2Q earnings call. Having said that, we are seeing upward pressure in scope in certain areas, as Greg just mentioned, such as the Bakken, where we'll be adding some rigs as we go throughout the year. And we're shifting to drilling the higher working interest areas, as well as in Tubular Bells, actually the Stena Forth (technical difficulty) Mexico.

So it's actually in like (technical difficulty) than we originally planned. So it's just an acceleration of spend into the year. Now, however, even with that upward pressure in capital, as John mentioned earlier, we still anticipate funding the majority of our 2012 capital program cash flow from operations (technical difficulty).

So the guidance is -- the $6.8 billion guidance, John, what does that look like?

We will update that on the second quarter conference call. But there is upward pressure on (technical difficulty).

All right. I'll leave it there, thanks.

Ed Westlake, Credit Suisse.

So just coming back to this back-end issue, I mean, how much of -- so, as you sort of move through HBP, are there any acceleration in terms of the timing of getting through to the end of that HBP, to give some confidence that in 2013, the performance is going to improve relative to the weaker performance in the first quarter?

Yes. So, Ed, again, we're increasing (technical difficulty) we're going up two rigs. We currently have 14; waiting on a couple newbuilds from (technical difficulty) old-style rigs. So we'll increase the well count. And we are moving back into higher productivity, higher (technical difficulty) in the areas (technical difficulty).

But to be, I guess, specific, if I look at some of the data, your wells seem to be down for longer periods than some of the competitors. So the actual calendar day sort of IP is lower than the tight curves. How are you going to close that gap relative to some of the other operators that we see up in North Dakota?

Not really familiar with what you're talking about. I will tell you that our data shows us very competitive with other operators in North Dakota.

The issue is that each well doesn't produce as many days in any particular year, according to the Dakota information, in any month, particularly in the first couple of months, which could be infrastructure, could be HBP?

Yes, I mean, it's early days, Ed. I mean, remember we're adding a lot of construction in North Dakota, much more than some of our competitors.

Okay. And then just a follow-on question on CapEx. How much is infrastructure spend as opposed to drilling spend in the Bakken this year?

We've been running about 400 million to 500 million on infrastructure-type costs in the Bakken. (multiple speakers) And obviously, as Greg said, we're building that out and then that will go down (technical difficulty).

And when do you think -- see that inflection coming?

Well, we should start seeing some reductions in 2013 on those (technical difficulty) costs.

Okay. Thanks very much, Greg.

Evan Calio, Morgan Stanley.

Thanks for taking my call. With the Bakken and CapEx a little more covered here, and congrats on the execution of the Ghana selldown with Statoil. Can you provide any color on the terms of the cap or on the promote? And is that likely to come into effect? And then with Hickory North spud in late March, we expect 60 to 90 days on that well. And is there any pre-drill piece that you could share with us?

Let me kind of take your questions in order. No, we don't provide any pre-drill estimates (technical difficulty) well typically. The rig, again, it will be about a 90-day well, [60] to 90 days, (technical difficulty) and whatnot. Regarding the deal, the terms are confidential of both deals because there are two partners (technical difficulty) block. The final government approval is still required, but both involve a combination of (technical difficulty) that pay a disproportionate amount of well costs (technical difficulty).

Okay. And if -- shifting gears to Brunei exploration, in Julong East to try and interpret the release and any color on whether that was commercial? Any color on what type of prospect that or Jongus East is? I mean, were these the offset structures to TK or Damaset or were they look-alikes like the first prospect?

So the first -- the last well we drilled was a discovery. Total is in the process of evaluating the results of the well which we believe is an offset to the TK Field. So I think it's best -- we're in the middle of evaluating. I think it's best for us to refer to the operator for (technical difficulty) but it was a discovery. Regarding the current well (technical difficulty) in its offset location (technical difficulty).

Okay. Could I just squeeze one last one in here. Maybe back to the Bakken I know realization is more discounted year-on-year in the first quarter. You should see some offsets in the second quarter and beyond. Can you update us on rail volumes in the quarter and where you're maybe now on takeaway capacity? Thanks.

Well, we just started up our rail facility and we're going to be moving about approximately 25,000 barrels a day of Bakken crude down to St. James, Louisiana. Spreads now between LLS versus WTI, plus the discount off of WTI to get it into Clearbrook or North Dakota or Western North Dakota, as the case may be. It is in about the $25 range, the [market] was close to the $40 range. Prior months, it was close to $20. So obviously, that margin upgrade that we get on about 25,000 barrels a day.

But we just started the rail facility in full force and we should be ramping up during the year to higher volumes. Our full capacity for all the railcars that we're going to have by the end of the year should be in the range of 50,000 to 54,000 barrels a day.

Appreciate the answers. Thanks, guys.

Arjun Murti, Goldman Sachs.

Just a couple more Bakken questions. The fact that you're doing a bunch of HBP drilling, is that in effect creating some bit of a backlog in terms of tying things in, maybe in line for a catch-up at some point in the future next year? And then, secondly, can you talk about where well costs are or trending on your Bakken wells? Thank you.

Yes, sure. Let me answer both those questions. First of all, let me just again reinforce there were two issues in the first quarter. So the first one was permitting issues, which really just reflects a huge amount of activity in North Dakota. So during the first quarter, we experienced delays in receiving permits in certain locations, which resulted in delays getting well contracts. So working with the state to resolve the issues.

And then my second comment was about well mix or your ATT mode, getting focused on acreage being held by production rather than focusing on the sweet spots before (technical difficulty) you're going to experience some variability in IT.

I think the final thing, Arjun, is when you're in HBP mode, you're essentially drilling the first well and pad. Right? So you have a lot more movement of manpower rigs and materials. And when you're in pad drilling mode, which is different than some of our competitors that are (technical difficulty). So those groups, we expect, once we return to pad drilling in late 2012 (technical difficulty).

That makes sense, Greg. Is there a backlog, so to speak, of stuff that needs to be tied in beyond some of the permitting delays you talked about?

There is. So we still have a backlog of wells to complete. That backlog is coming down, and we expect to be in the normal backlog. Normal will be 20 to 25 wells in the backlog just before your process, yes, work in progress.

Regarding -- you had one more question --?

Well costs.

Yes, you had one more question on well costs. A good number to use for 2012 is $10 million for drilling the completed wells. Our Q1 costs were a little higher due to a shortage of white sand profit. However, that issue is now resolved and we expect our cost to drop as we transition to full slide completion. So we're drilling the full 34 stage slide completion and we continue to achieve drilling efficiency gains. This quarter, our drilling days (technical difficulty) [seven]; in Q4, they were 30 days. (technical difficulty) as well. Getting better and better as we go to sliding fleet and HPP drilling.

That's great. On the Utica, any update on what you're doing there?

Yes, the Utica, I think -- I mean, we're still in very early stages of our (technical difficulty) in the Utica, with only two wells having been drilled and completed, both on our acreage and the (technical difficulty) acreage. So as we mentioned in our last call, we completed the Marquette well in Jefferson County the end of the year. That well flowed at an initial rate of 11 million cubic feet a day. It's currently producing 4.5 million cubic feet a day, and the reason is it's curtailed by pipeline capacity. So it's got much more potential than that.

Now our partner, CONSOL Energy, recently completed a well in Tuscarora County, which is 45 miles west/northwest of our Marquette wells that's currently under evaluation. We will commence our Hess-operated drilling program in mid-May.

That's great. And then just a final quick follow-up. Was there any material acreage acquisition costs in that 1Q CapEx? Or is it just the comments about scope and so forth that I think John Rielly had mentioned?

There were some, just the routine type acreage, fill-in acreage costs, but nothing overly significant.

That's great. Thank you so much.

Robert Kessler, Tudor, Pickering, Holt.

Just a quick follow-up on the Bakken. Of your, say, 42,000 barrels a day of net production, how much of that might be nonoperated?

We don't have that number right now, Robert. We can get back to you with that number.

Okay. Separately on Tubular Bells, can you just help me understand a little bit of the rationale for the strategy to sort of outsource the production facility, the Williams and this whole Stara FVS and a little bit of color around the structure of that arrangement?

Yes, Robert. That was, just to remind everyone on the call, that arrangement was actually done by BP. We -- recall in October 2011, we increased our interest to 57% from 40%, basically took over between us and Chevron, BP's interest. And that was the development concept that was underway at that time. And so we just continued on with the development concept.

Thanks, Greg. Is there anyway to provide some kind of overall cash costs for Tubular Bells, inclusive of the fee you have to pay for processing?

No, Robert, we don't go down to that level of detail at this point in time. And again, we have to wait to see if the development actually starts up as well.

Is it fair to say you're on the hook for a certain amount of payment, even if the wells are not brought online on time?

No. It goes post-development. So as production comes on, the facility effectively then gets paid off as part of the processing fee.

And I think Williams also references their comfort that they'll be carried through, say, hurricane disruption risk, which is certainly not inconsequential in the Gulf of Mexico for [up to six months] or so. How does that work? You still make payments to the operator of the facility even if you're not producing in that area?

Those type of terms actually we won't discuss on a call. That's kind of -- that's confidential at this point.

Okay. Thanks anyway.

Paul Cheng, Barclays.

Greg, can you share with us what is in Bakken your current cash lifting cost?

No, Paul, we don't break -- again, break that down. You can see obviously in the US that the Bakken is a good part of the production in the US, so it's built into those costs.

John, is the unit cash cost higher or about the same as your average US?

With the Bakken again, what we have right now is a ramp-up, so there's a lot of people, there's a lot of equipment and everything being done to support the growth that's going on there. So just like with the cash costs as well as on DD&A, where the initial DD&A rates are high. Because the reserve books lag the investment dollars, you will have that kind of higher cost type impact that will come down over time.

We understand, I just want to know that we need to look at a baseline and see that what kind of improvement we could potentially expect. If you can draw down to some of the -- your competitors in the basins, and maybe down to [five or six] are we, at this point, in the 20-plus or at the 15 or where -- I mean, what kind of improvement that we could expect from a cash flow standpoint going forward? You assume you indeed would be, once you move the debenture and be able to move down to the [kind of] cost curve as your best competitor. So we're just trying to get some better understanding.

Yes, Paul, I think we are one of the best competitors. We are pre-investing in infrastructure over $500 million on our Tioga gas plant to strip liquids out, and be able to capture the value from the natural gas. Most people don't have that or they have to pay a lot on tariff to get access to that.

The rail facility is already showing its wisdom of revenue upgrades. It's not just about cost, as you well know. And on the cost side, our people are very efficient. Obviously, the logistical challenge of the 14 and ultimately 16 rig program going lean manufacturing; HBP. It's going through the early phases of ramp-up in a very big operation and that creates some of the noise in the unit costs.

But we do see those stabilizing over time. And then last but not least, as we get more well production history, we will be booking more proved reserves, which will also help us in terms of the DD&A. So it's early stages of a major investment for our Company, creates some volatility and being able to predict both on the cost side and on the production side. But we're very confident that we're on a solid growth trajectory. And as we move forward in time, our unit costs will improve.

No, I understand that, John, but I just want to see if you can give us some number or some estimation that we can you use it as a base (technical difficulty) so that we can do some calculation ourselves what is the improvement that we could expect from a cash flow and earnings, from that operation over the next several years?

I think you will be able to see that, Paul, as we deliver results. So as we deliver results, I think you'll be more satisfied with the answer.

On the (technical difficulty) -- assume that economic permit, how quickly or what is the fastest that you can get ramp-up to the 50,000 -- 54,000 barrels a day? And what is the limitation in terms of the time it take to ramp it up?

It's a number of things. It's ability to offtake in a market. It back tested two of the trains we leased out I think of the nine train sets that we have until about August. So gradually you'll see a ramp-up from the 25,000 barrels a day now, ultimately to that 50,000 barrel a day number or higher by the end of the year.

So by the end of the year. So you're not going to be able to get that stage by the third quarter?

As I said, there will be a gradual ramp-up from 25,000 barrels a day right now to about 50,000 to 54,000 by the end of the year.

Okay. Can you give us an update on the Valhall?

Yes, Paul, this is Greg. Valhall production about flat. I mean the, as we said before, the VRD will be done this year. And so you can expect volume at Valhall to be about flat with what it was last year until we get that redevelopment program done. We do have -- we are doing some producer drilling this year, so we're anxious to see the results of that producer drilling as those wells come online.

Greg, are we still talking about in the third quarter the development startup?

Yes, the work on the redevelopment occurs in the third quarter.

Okay. On Utica, CONSOL, that well I think has been complete more than a month ago. Do you have any production number you can share?

The operator, you have to refer to the operator on that.

Okay. A final one on Libya. What was the sales being recorded in the first quarter?

In Libya, we did get a lift towards the end of March. So we had a lift in approximately a 600,000 barrel-type area. So we did have a significant underlift with Libya. We had an underlift of approximately 950,000 barrels for Libya in the first quarter.

So, John, should we assume that as you start catching up your effective tax rate or international [E&T] will be substantially higher because of Libya?

Correct. If you assume that lifting catch-up in equal production, that will increase that effective tax rate. And we'll get it up -- if lifting deephole production into the overall this is 44% to 48% effective rate range.

How much, I'm sorry?

44% to 48%. If Libya, if we get all our production lifting in catch-up. The other thing that Libya does then, it will help us on the unit cost. So from the unit cost aspect, our unit costs will go down $1 to $2 per BOE.

Is the 44% to 48%, is that total E&P or just international E&P?

Total E&P.

Total E&P. Do you have an estimate of your deferred tax applied in this year?

No. No, that's too early to be able to do that, Paul.

Thank you.

Paul Sankey, Deutsche Bank.

If I could ask about your cash flows, forgive me if you mentioned this, but is there any major working capital movements within that number that you gave?

The big movement was the funding of our HOVENSA commitment, so we had an accrued liability of $487 million related to the shutdown for HOVENSA. So we, along with our partner, funded our share. So we funded the $487 million to HOVENSA in the first quarter. Because there was a tender offer for the debt down there at HOVENSA and due to the timing of the liquidation proceeds from the inventory, and also the timing of shutdown costs. So we fully funded -- that was the biggest impact from the working capital standpoint. There were other positive impacts of working capital aside from that of approximately $240 million.

Okay, so the entire $487 million you just mentioned was within the quarter?

Was within the quarter (multiple speakers).

And then there's also the (multiple speakers) [240] positive?

Correct. And the (inaudible) -- so we do not expect any more funding for HOVENSA for the rest of the year.

I've got you. Can you give us a sense of the cash impact of the hedges in the quarter?

Sure. So, I mean, you saw the aftertax impact was $71 million in the quarter. So you can just divide that by the effective tax rate, so it's approximately $110 million to $115 million [pretax].

That's helpful, thank you. I was wondering, you gave a number for -- I believe you gave a number for infrastructure spend in the Bakken of about $400 million, just in the Q&A. Do you have a number for the spend, the overall CapEx in the Bakken for the year?

No, we don't have that number at this time.

So obviously, you just don't break it out, right?

Correct.

Okay. All right, I'll leave it there. Thank you very much.

Pavel Molchanov, Raymond James.

Thanks for taking my question. Well, no one's asked about downstream yet, so I thought I would do that. I just saw a news release from the EPA stating that you guys will be investing $45 million in pollution controls at Port Reading. Given that the refinery just seems to be kind of in perpetually in the red, I'm curious what the logic is to retain it and, in fact, invest more in the facility, rather than just do what you did with HOVENSA?

Yes -- no. As you know, Fort Reading is a much smaller refining complex than HOVENSA. As long as it generates acceptable financial returns, we'll keep running it. And as there are updates to be given on its status, we will give them.

Okay. What do you think needs to happen to get margins at that facility to an acceptable level? I mean, is it -- purely kind of crack spread issue or is there internal changes that could be made?

The biggest determinant is market conditions, which obviously, we have no control over.

Okay. Appreciate it.

(Operator Instructions). Faisel Khan, Citigroup.

I was wondering if you could -- maybe I missed this -- if you could give us an update on the Eagle Ford, what kind of well results have you had out of that Basin?

Yes, Faisel, this is Greg. Yes, thanks. So we have -- just recall, we currently have about 109,000 net acres in the Eagle Ford. And we drilled 38 wells, 29 completed and brought on production. Now of those 29, 22 wells have been on more than 30 days, and they delivered 30-day IP rates ranging between 250 and 650 barrels a day. So keep in mind the Eagle Ford is just like all of our unconventional plays; we're still very early in the appraisal mode on the Eagle Ford.

Okay. And what's the mix of black oil versus condensate versus NGLs and gas, or maybe just a liquids/gas ratio?

Yes. So we're -- with the current well mix, it's about 60/40. But part of our appraisal program is to move through different areas of the oil window, condensate window, et cetera. So that number is going to change over time as we appraise it.

Okay. And then just going back to the funding of HOVENSA, is all that capital related to debt? Or was it also related to environmental remediation sort of liability?

No. So, HOVENSA -- they had debt to be extinguished plus they had the overall shutdown costs. So at the end of the year, we had an accrual for $487 million for the totality of shutting down HOVENSA. So that was going to be the total amount that Hess -- and our estimate was that we were going to fund. So we put that in there. And it's for the debt and other related shutdown costs.

What happens to the inventory? How does that capital get -- come back to you guys?

Well, that inventory was -- the liquidation of the inventory was net in that estimate. Our estimate then was reduced by the estimated proceeds from the inventory.

Okay. So what happens from now on? Is it -- I guess you could turn the facility into a terminal, and then is there any value that you could accrue back from that sort of situation?

That is the plan right now, that HOVENSA will be turned into a storage terminal.

Okay. So kind of collective fee-based sort of revenue off of it over time?

Correct.

Okay. Okay, great. Thanks for the time, guys. Appreciate it.

Paul Cheng, Barclays.

On -- where are we in the Australian gas appraisal and supply agreement negotiation?

Yes, thanks, Paul. If the Jack Bates rig has returned on location there, and we expect to complete all of our appraisal work by mid-2012. So that's complete drilling of one well plus [two] tests. So test the well that we're drilling, plus then go back to the well that was previously drilled that we plan to test. Now in parallel, we continue these commercial discussions with the liquefaction partners, our aim is to complete those in 2012. And those are ongoing, Paul.

Great. In Bakken, what's the split in your liquid division back order and condensate? Is that the back off in your production in the liquid solid black oil or just condensate?

The majority is black oil. Approximately like you're getting like 85% to 90% black oil.

So it's black oil. And then in Eagle Ford, when you say 60/40, is that 60% condensate, 40% black oil? Or are you talking about between the liquid and gas mix?

No, it's 60% condensate, 40% black oil in that split. But again, Paul, remember we're in appraisal mode, so those numbers are constantly moving around as we move around in the play.

Okay. Thank you.

Ladies and gentlemen, that concludes the Q&A session. That also concludes the presentation. Thank you for your participation. You may now disconnect. Have a great day.