赫斯 (HES) 2014 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2014 Hess Corporation conference call. My name is Crystal, and I will be the 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 the conference over to your host for today, Mr. Jay Wilson, Vice President of Investor Relations. Please proceed, sir.

Thank you, Crystal. 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. These risks include those set forth in the risk factors section of Hess' annual and quarterly reports filed with the SEC.

Also on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

With me today are John Hess, Chief Executive Officer; Greg Hill, President 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 you all on our first-quarter conference call. I will make some high-level comments on the quarter and the progress we are making in executing our strategy. Greg Hill will then discuss our E&P operations, and John Rielly will go over our financial results.

Our results this quarter demonstrate the continued execution of our plan to drive cash-generative growth and sustainable returns for our shareholders through a focused portfolio of world-class E&P assets.

In the first quarter, our growth assets performed well, with higher production from Valhall and North Malay Basin. In addition, current Bakken production levels are in excess of 80,000 barrels of oil equivalent per day following completion of the Tioga gas plant expansion. Tubular Bells is on track for first oil in the third quarter, and well results from the Utica shale play are encouraging. Overall, we remain very enthusiastic about the prospects for our Company in 2014 and beyond.

With regard to our financial results, net income for the first quarter of 2014 was $386 million, or $446 million on an adjusted basis. Adjusted earnings per share were $1.38, compared to $1.95 in the year-ago quarter. Cash flow from operations before changes in working capital was $1.4 billion.

Compared to the first quarter of 2013, our results were impacted by asset sales, which reduced production by 77,000 barrels of oil equivalent per day, and the shut-in of production in Libya, which reduced production by 23,000 barrels of oil equivalent per day.

Net production in the first quarter averaged 318,000 barrels of oil equivalent per day, or 297,000 barrels of oil equivalent per day on a pro forma basis excluding divestitures. This represents an increase of 11% from pro forma production of 268,000 barrels of oil equivalent per day in last year's first-quarter, excluding Libya. This improvement was driven by higher production from the Valhall Field in Norway and North Malay Basin in Malaysia.

Regarding the Valhall Field, in which Hess has a 64% working interest, net production averaged 37,000 barrels of oil equivalent per day in the first quarter. This compares to 5,000 barrels of oil equivalent per day in the year-ago quarter when production was restarting following the completion of the multi-year field redevelopment project. Two wells were brought online in the first quarter, and facility uptime and reliability have continued to improve.

In Malaysia, net production from the North Malay Basin, where Hess is the operator with a 50% interest, averaged 40 million cubic feet per day in the first quarter. The early production system commenced in October of last year and will maintain production at current levels through 2016.

Full-field development is ongoing and should result in net production increasing to 165 million cubic feet per day in 2017. Net production from the Bakken averaged 63,000 barrels of oil equivalent per day in the first quarter. The Tioga gas plant commenced startup operations on March 23 and began residual gas sales on March 25.

Production from both the field and the plants increased through April, and, as I mentioned earlier, current net production from the Bakken is in excess of 80,000 barrels of oil equivalent per day.

Our full-year 2014 production forecast remains 80,000 to 90,000 barrels of oil equivalent per day. Our Bakken team continues to drive our well costs lower. In the first quarter, drilling and completion costs averaged $7.5 million, a 13% savings from the year-ago quarter. In addition, our wells continue to be more productive than the industry average.

In the deepwater Gulf of Mexico, development of the Tubular Bells field, in which Hess has a 57% interest and is operator, remains on schedule to achieve first oil in the third quarter. During the first quarter, the spar and topsides were towed out and installed on location. Three producing wells have been predrilled with pay counts coming in above expectations. As a result, we plan to drill a fourth producer in the second half of this year.

In terms of divestitures, on April 23 we announced that we completed the sale of our exploration and production assets in Thailand for $1 billion, based upon an effective date of July 1, 2013. The divestiture processes for our retail marketing and trading businesses are well advanced.

Also, we continue to make progress in our plans to monetize our Bakken midstream assets in 2015, most likely through an MLP structure through which Hess will retain operational control while maximizing the value of our infrastructure investment.

Regarding our share repurchase program, through April 29 we have repurchased 14.3 million shares for $1.1 billion in 2014. Since commencement of the program in August of 2013, we have repurchased 33.6 million shares for $2.7 billion.

In sum, we are pleased with the progress we continue to make in our transformation to become a pure-play E&P Company. We are confident that our initiatives have positioned the Company to achieve 5% to 8% compound average annual production growth through 2017 off of our 2012 pro forma base and to generate free cash flow post 2014 based upon $100 Brent.

In addition, the strength of our balance sheet provides the financial flexibility to fund this cash-generative growth that will deliver strong, sustainable returns for our shareholders.

I will now turn the call over to Greg.

Thanks, John. I'd like to provide an operational update and a review of the progress we are making in executing our E&P strategy. Starting with unconventionals, in the first quarter net production from the Bakken averaged 63,000 barrels of oil equivalent per day.

While the severe winter weather in the first quarter delayed the start-up of the Tioga plant by approximately three weeks and deferred bringing new wells online, the Bakken team has done an outstanding job of getting us back on schedule. First gas was introduced to the Tioga plant on March 23. First residue gas sales commenced on March 25 and ethane recovery on April 23. Also, we brought 24 new wells online in April, compared to 30 wells in the first quarter, and current net Bakken production is in excess of 80,000 barrels of oil equivalent per day.

In the second quarter, we forecast net Bakken production to average between 75,000 barrels and 80,000 barrels of oil equivalent per day. Our full-year 2014 Bakken production guidance remains at 80,000 to 90,000 barrels of oil equivalent per day.

Drilling and completion costs continue to be reduced, with first quarter averaging $7.5 million per well versus $8.6 million per well in the year-ago quarter and $7.6 million per well in the fourth quarter of 2013. And the productivity of our wells continue to be above industry average.

We are continuing with our downstaging pilots of 17 well pads, having 13 wells per drilling spacing unit with 7 wells in the middle Bakken and 6 in the Three Forks to allow us to determine optimal spacing across the play. Early field results are encouraging. We are also conducting pilots on 2 pads, with an even tighter 17-well-per-DSU configuration, with 9 wells in the middle Bakken and 8 in the Three Forks.

By the end of this year, we expect to have sufficient data to provide updated guidance for well spacing, production, drilling locations and resource potential.

Turning to the Utica, the appraisal and early development of our 43,000 core net acres in the Hess CONSOL joint venture continues; and we are encouraged by well results to date, with rates averaging 1800 barrels of oil equivalent per day with 59% liquids based on 24-hour tests.

In 2014, absent CONSOL, plan to drill some 30 to 35 wells across our joint-venture acreage. In the first quarter, we drilled 8 wells, completed 3, and tested 1 well in the joint-venture acreage.

In the offshore, progress continues at Valhall, North Malay Basin and Tubular Bells. At the BP-operated field in Norway, in which Hess has a 64% interest, net production averaged 37,000 barrels of oil equivalent per day in the first quarter. Two producers were brought online following workovers, and facilities' reliability have been considerably improved. Full-year 2014 net production from Valhall is forecast by the operator to be in the range of 30,000 to 35,000 barrels of oil per day.

At North Malay Basin in the Gulf of Thailand, where Hess has a 50% working interest and is operator, first-quarter net production continues at 40 million cubic feet per day through the early production system and is expected to remain at this level through 2016.

Contracts for the central processing platform for the full-field development will be awarded in the second quarter, and we continue to advance our full-field development project, which is expected to increase net production to 165 million cubic feet per day in 2017.

At our 57% owned and operated Tubular Bells development in the deepwater Gulf of Mexico, the spar and topsides were installed on schedule during the quarter. And we are on track with field start-up in the third quarter of 2014, with net production building to 25,000 net barrels of oil equivalent per day.

Due to the positive results from the wells drilled to date, we intend to spud a fourth producer midyear, which is expected to be brought on production in the first quarter of 2015.

At the Malaysia Thailand joint development area, there's a 30-day planned shutdown commencing in early June for work associated with booster compression tie-ins. As a result, net production from this asset is expected to be curtailed by approximately 11,000 barrels of oil equivalent in the second quarter.

Companywide production on a pro forma basis, and excluding Libya, is forecast to average between 295,000 and 300,000 barrels of oil equivalent per day in the second quarter of 2014. And our full-year 2014 forecast on this same basis remains 305,000 to 315,000 barrels of oil equivalent per day.

In terms of exploration, in the deepwater Tano/Cape Three Points block in Ghana, in late March we successfully farmed out a 40% license interest. Hess will retain a 50% license interest in operatorship. Our new partner will pay a disproportionate share of the cost during the appraisal phase to earn their interest in the block. Appraisal drilling is expected to commence in May beginning with a downdip test on the time to discovery.

In Kurdistan, where Hess has a 64% license interest and is operator of the Shakrok and Dinarta blocks, we completed drilling at the Shakrok-1 well. We plan to perform production tests over multiple intervals in Jurassic-age reservoir, which was the primary target of the well. In May, we plan to spud the Shireen well on the Dinarta block.

In closing, in this quarter we have continued executing against our plan and delivering key milestones including those on Tioga, Tubular Bells and North Malay Basin. We see increasing upside in our high-quality acreage position in the Bakken, where we continue to drive top-quartile operational performance and leverage our infrastructure advantage. And finally, we are entering a key phase of exploration in Kurdistan and appraisals in Ghana.

I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the first quarter of 2014 to the fourth quarter of 2013. The Corporation generated consolidated net income of $386 million in the first quarter of 2014, compared with $1,925,000,000 in the fourth quarter of 2013. Adjusted earnings were $446 million in the first quarter of 2014, compared with $319 million in the previous quarter.

Turning to exploration and production, E&P had income of $508 million in the first quarter of 2014 and $1,029,000,000 in the fourth quarter of 2013. E&P adjusted earnings were $514 million in the first quarter of 2014 and $436 million in the fourth quarter of 2013.

The changes in after-tax components of adjusted earnings were as follows. Higher realized selling prices increased earnings by $46 million. Lower operating costs increased income by $56 million. Lower exploration expenses improved earnings by $15 million. Lower sales volumes decreased earnings by $12 million. All other items net to a decrease in earnings of $27 million for an overall increase in first-quarter adjusted earnings of $78 million.

Our E&P crude oil operations were under-lifted compared with production by approximately 1.1 million barrels in the quarter, which decreased after-tax income by approximately $35 million. The E&P effective income tax rate, excluding items affecting comparability, was 39% for the first quarter of 2014 and 38% in the fourth quarter of 2013.

Turning to corporate and interest. Corporate and interest expenses, net of income taxes, were $89 million in the first quarter of 2014, compared with $115 million in the fourth quarter of 2013. Adjusted corporate and interest expenses were $81 million in the first quarter, down from $108 million in the fourth quarter. The decreased costs in the first quarter were a result of lower interest expenses and reduced employee-related costs.

Turning to downstream. The downstream businesses reported losses of $33 million in the first quarter of 2014, compared with income of $1.011 billion in the fourth quarter of 2013. Adjusted earnings were $13 million in the first quarter, compared to an adjusted loss of $9 million in the fourth quarter of 2013, reflecting improved trading results.

Turning to cash flow. Net cash provided by operating activities in the first quarter, including a decrease of $248 million from changes in working capital, was $1,158,000,000. Net proceeds from asset sales were $1,237,000,000. Capital expenditures shares were $1,444,000,000. Common stock acquired and retired amounted to $1,043,000,000. Repayments of debt were $333 million. Common stock dividends paid were $79 million. All other items amounted to a decrease in cash of $22 million, resulting in a net decrease in cash and cash equivalents in the first quarter of $526 million.

Turning to our stock repurchase program. During the first quarter, we purchased approximately 12.6 million shares of common stock at a cost of approximately $1 billion, or $79.33 per share, bringing cumulative purchases through March 31 to 31.9 million shares at a cost of $2.54 billion, or $79.53 per share. We've continue to buy back our common stocks, and through April 29 total program-to-date purchases were 33.6 million shares at a cost of $2.68 billion, or $79.84 per share.

We had $1,288,000,000 of cash and cash equivalents at March 31, 2014, compared with $1,814,000,000 at the end of last year. Total debt was $5,576,000,000 at March 31, 2014, down from $5,798,000,000 at December 31, 2013.

The Corporation's debt to capitalization ratio at March 31, 2014 was 18.7%, which was improved from 19% at the end of 2013.

Turning to second-quarter 2014 guidance, I would like to provide estimates for certain metrics. For the second quarter, E&P cash operating costs per barrel of oil equivalent are estimated to be in the range of $22 to $22.50 per barrel. The expected increase in cash costs per barrel over the $21.11 in the first quarter of 2014 is primarily related to lower production volumes following the asset sale in Thailand, as pro forma cash costs were $22.17 in the first quarter.

E&P depreciation, depletion and amortization expenses per barrel are estimated to be in the range of $28 to $28.50 for the second quarter. The increase from the $25.19 per barrel in the first quarter of 2014 is primarily due to higher production volumes in the Bakken, lower volumes at the JDA due to a planned shutdown, and the impact of selling assets in Thailand which were not being depreciated while classified as held for sale.

Full-year 2014 unit cost guidance of $20.50 to $21.50 per barrel for cash costs and $29 to $30 per barrel for depreciation, depletion and amortization expenses remained unchanged.

For the full year 2014, the E&P effective tax rate is still expected to be in the range of 37% to 41%, and the second-quarter rate is expected to be in the range of 37% to 39%.

The estimate for corporate expenses in 2014 remains in the range of $125 million to $135 million after taxes, and after-tax interest expenses are still estimated to be in the range of $225 million to $235 million.

Second-quarter corporate expenses are expected to be in the range of $35 million to $40 million, and interest expenses are expected to be in the range of $50 million to $55 million.

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

(Operator Instructions) Evan Calio, Morgan Stanley.

Earlier in the week, there was a retail acquisition I saw (inaudible) as 14 times forward EBITDA. It was a utilization reminder of MLP structure for wholesale fuels business and ability to characterize some of that retail site value as wholesale fuel and, thus, MLP qualifying income. So, my question is have you examined the potential MLP value in your retail assets, and do you consider that potential value when you consider the value in the sale process? And I had a follow-up. Thanks.

Yes, Evan, as you well know, our divestiture process for our retail business is well-advanced. We certainly are prepared to move forward with a spin, and at the same time we are conducting a parallel process to look at all of our other options including outright sale. And the process is well underway.

Okay, well, the transaction certainly highlights the value there. Can you share a tax basis in the retail?

What we are going to do, Evan, is anything related to disclosures on that would come through future SEC filings. So should we pursue the spin option. So, again, I think as John said, we're well advanced in the process, and that's where we want to be right now from a disclosure standpoint.

Fair enough. Can you just give me the US tax basis on the electric JV interest sale? Or is there tax implications there?

Sure. The gain on sale on that transaction will be limited.

Great. And maybe at the risk of a similar response, on potential [MLPable] assets and not -- I'm not asking in EBITDA figures, but can you discuss any potential assets outside of the Bakken which is clear that may qualify -- Gulf of Mexico, for instance, with Tubular Bells platform investment? Or anything that's outside of the Bakken would be helpful.

Our clear focus right now is focusing on our Bakken midstream assets. And that's where our efforts are going right now. And we are still on track, I think, on the guidance that we've been saying. So by 2015, we look to have a monetization event relating to those Bakken midstream assets. We plan to get SEC filings in place here in the second half of the year for that.

Over time, yes, we have other midstream assets in our portfolio that could ultimately be dropped into that, but that will be at a later point.

Great. Maybe lastly if I could, just on Tioga. Can you just remind us of third-party volumes we should expect there before you fully fill the plant? Just so I could kind of understand that.

I could give you a sense of current volumes right now, Evan. Right now, the plant in those rates are about 120 to 140 million cubic feet a day. And roughly 70% of that is Hess-operated production and 30% is third-party. So obviously as we ramp our production up, our volumes will go up. But our plan is to fill that plant to capacity of 250 million cubic feet a day as rapidly as we can.

And then we're also looking at ways to de-bottleneck that facility to further increase capacity to 300 million cubic feet or higher.

Oh, okay. Great. I appreciate it. Good quarter, guys. Thank you.

Ed Westlake, Credit Suisse.

Just a very quick follow-on from Evan's conversation on retail. And, again, you may not give this -- but you had, I think, 13 million in the downstream in the first quarter. Do you have a number for what was sort of retail-only EBITDA within that?

Same thing (technical difficulty) of the divestiture process.

Understood. Okay, a question for Greg, then, on the downspacing. We've been tracking some of the other sort of downspacing tests in the industry, and some of them started a little bit earlier so we've got a bit more data. We find that the EURs are in the sort of 400 MBOE range, i.e. slightly lower than where the original wells would be. But obviously you get a saving in terms of the costs.

So I'm just getting a sense of do you see this playing out as a sort of just an area where you can add inventory but the returns will fall, or is this an area where you think you can actually sustain the current levels of returns? And if that's the case, do you see yourself throwing more rigs at the play once you've got this downspacing tests, your own tests, finished? Any color there would be helpful.

Yes, okay great. Yes, thanks, Ed. I think, first of all, it's early days for us. We've got 17 well pads planned with these 13 wells per BSU, so that's 7 and 6; 7 in the middle Bakken and 6 in the Three Forks.

Early field results, although limited, are very encouraging. We're seeing very little interference in those wells. So I think there's a good chance that if that continues, these will be very, very high-return wells just like the current wells are.

We're also doing a two-well pad that has 17 per DSU, so that's a 9 and 8. But those will come a little bit later in the year.

And then maybe in terms of the geology, how much of your acreage do think is in the sweet spot for doing the downspacing? Obviously, not all of the acreage has the middle Bakken and Three Forks potential.

Yes, I think that depends. That's why we're doing 17 well pads. Because we are going to try and spread those around the field. Because obviously in other areas, say on the anticline where you have a lot of natural fracturing, you might see higher interference in that area of the field. So that's why we're putting these pads all around the field to try and really assess where could we apply this. Right?

Yes, okay. Thank you.

Doug Leggate, BOA.

I've also got a, I guess, follow-up first on the Bakken. I guess I would probably slightly disagree with Ed's conclusions there on the downspacing given what Continental has been doing. But my question to you guys is, you're drilling half your program this year on downspacing tests. So I would -- I guess, Greg, what I'm kind of thinking is you're managing to your inventory in terms of drilling activity. If it turns out that the 7 and 6es work, but yet your current plan is 5 and 4s as I understand it, what does it do to your activity levels in terms of future planning, future rig activity and ultimately production targets out of the Bakken?

Well, I think, as we've said, Doug, our current plan, which is 5 and 4, has 150,000-barrel-a-day target or peak in 2018, with 1.1 million barrels -- or billion barrels recoverable. Obviously, if we go to 7 and 6, that number is -- all -- those numbers are going to go up because the number of operated drilling locations will go up as well.

And so I think you can do the math and figure out that things will go higher. And what we haven't done yet is determine what rig pace -- if this is successful, what rig pace will we prosecute on that acreage. We'll make that decision at the end of this year, and that will be part of our business planning as we go forward in 2015 plus.

Great. Thanks. My follow-up, I guess, is Canada-related because it relates to the strength of your cash flow. John Hess, I guess the philosophical question here is you've got midstream spending in Tubular Bells that kind of falls off this year. It seems that on a pre-working capital basis, your run rate is about $5.6 billion [streets] below that, and you haven't even had to drill through the second half of the year. So just kind of looking at the cash flow is very, very strong. You're selling more assets. Your buybacks clearly look like that is conservative. So can you prioritize for us the use of cash as you look beyond perhaps the current year given all of those moving parts?

Sure. Well, you know, the first priority will be to invest for future growth, with our balanced approach among unconventionals exploitation and exploration to underpin the 5K percent average growth rate going through to 2017; and obviously want to position beyond that.

Obviously, as we move out and our low-risk, cash-generative growth increases, there will be more money to consider then besides which we put in investing for growth to increase cash returns to the shareholders. So when we get there, obviously, that will be a priority as well.

John, when would you anticipate making a decision on the buyback authorization? Because it looks like you're going to chew through the $4 billion fairly short order.

Doug, that decision will be made when the ultimate decision is made for do we spin or sell our retail business. And then the $4 billion share buyback authorization, that's when we would be focused on do we increase it or not.

All right. Thanks a lot. Appreciate the answers.

Guy Baber, Simmons & Company.

I had a question on the offshore portfolio. But you guys obviously had a very strong offshore production this quarter at both Valhall. And then despite some down time early in the quarter, it looked like Gulf of Mexico did pretty well also.

So I was just hoping you could provide some incremental detail around the strong Gulf of Mexico output. Specifically, what drove that? How sustainable might that be as we think about the rest of the year? And has production, in fact, been better than what you expected internally?

And then at Valhall, can you just talk a little bit about confidence in the sustainability of some of the improvements to uptime and reliability at that asset just given its importance to your overall outlook?

Yes, let me talk about Valhall first, and then I'll go to the Gulf of Mexico. So in Valhall, we've established regular executive-level engagements with BP management all the way up to Bob Dudley. And we're actively progressing an agreed plan between our two companies.

And we're encouraged by the progress that BP is making. In Q1, we saw two producers brought online following workovers, and facilities' reliabilities have been considerably improved. So they've worked through a number of the issues after the redevelopment startup that was dragging the reliability down.

So we're cautiously optimistic that that can be sustained. The high reliability because it's brand-new kit -- it's brand-new equipment out on the platform.

Regarding the Gulf of Mexico, the big increase, of course, quarter on quarter was at Llano, followed by Conger. Now, that was -- if you recall, Shell had a pipeline go down for 22 days in December. That all came back in January. The Llano contribution is actually from the Llano-4 well that was brought on in very late November. So that's a sustainable volume going forward.

And as we mentioned, Valhall was at 37, so that's good performance from Valhall as well.

Okay, great. And then I had a follow-up just on -- I just wanted to run through the 2Q production guidance again. I think you mentioned it would be flat effectively quarter on quarter, but you do have a pretty significant ramp up in the Bakken of 15,000 barrels a day.

I apologize if I missed this, but did you mention any major turnaround activity for 2Q that would be offsetting, or is they are just an element of conservativism embedded in the guidance?

So let me just kind of walk you through the math. Thanks for the question. So if you look at [297,000], which was the first-quarter 2014 pro forma production, you can add about 18, which is Bakken and some minor growth in South Arne. And then you have to back off about 11,000 to 12,000 barrels a day due to the planned downtime in JDA. So we are taking that JDA facility down in June to do some tie-ins for the booster compression. So that's where you get that offset of the growth in the Bakken and the small amount in South Arne. And then there's some other very small differences.

Okay. Thank you.

That gets you to around [300,000], which is the upper end of the guidance on the 2Q 2014 pro forma.

Okay, great.

Roger Read, Wells Fargo.

I guess could we talk a little bit more about the Utica just in terms of -- it's a reasonable increase, the number of wells. There have been a number of other players in this space taking write-downs and backing away.

Could you just sort of walk us through what -- obviously we have the details here in the presentation, but kind of walk us through what you're seeing in terms of liquids production there. Are you seeing anything in the way of oils, strictly condensate, and then the process of moving that out of there at this point?

Yes, so let me put some context on it first. We are continuing to delineate the play and improve our understanding of our core JV acreage position. So we're very encouraged by our findings to date, which show that the majority of our -- that 43,000 core net acres that we have in the have in the JV is located in the play's wet gas sweet spot.

Now, recall we have a very high net revenue interest here, about 95%, which really turbo-charges the economics. And net acreage is largely held [prior] production or owned in fee. And so then if you look at where we're at in the appraisal process, though, we've drilled to date -- so this is inception to date -- we've drilled about 42 wells. However, we've only tested about 15 so far. So we're still pretty early, but the well results are very encouraging.

If you average all those well results in that kind of wet gas area, it's about 1,800 barrel equivalents per day; and the liquids rate that we quoted in our remarks in the opening. So, very high liquids rates; very good rates. So we remain encouraged.

Okay. And then in terms of where the, I guess, liquid and condensate side of that is moving. I mean, I know it's not huge numbers just yet. But is it staying local, or are you having to shift it somewhere else?

Yes, no, it's being moved to various markets. Right?

Okay. And then my last question on the exploration side -- or I guess now it's moved to appraisal in Ghana. You got the appraisal wells -- as I understood it from previous discussions, there may be some additional agreements that go with the Ghana government. Any update of where we are there? Or how should we think about the timeline of Ghana assuming a reasonable success rate out of the appraisal program?

Yes, I think -- you know, as we said in our opening remarks, the rig is going to show up mid-May. And then we'll prosecute the appraisal program. So by year end, we should have a good understanding of what we have in the appraisal program in Ghana.

And then beyond that, is it a negotiation with the Ghana government? How should we think about the process working from that point?

Well then, after that you have to file a development plan with the government assuming that you go forward. And, yes, there will be some negotiation in that development plan, but that would be the next step. So that would be a 2015 item that we'd get our development program through the government.

Okay. Thank you.

Paul Cheng, Barclays.

Maybe to Greg, first one on Ghana. You're talking about from (inaudible) your partner going to pay a disproportion on the appraisal program. Can you give us some idea that what is up to?

We can't yet. That's confidential -- commercially confidential with the partner.

I see. So you can't disclose who is the partner also, I presume?

No, we can't. Not yet.

Not yet, all right. All right. And the -- I think that when you're talking about Valhall for the full year, you're talking about 30, 35. In the first quarter, you did 37. Does that mean that we have some major downtime in the second or third quarter? It doesn't look like your second, so should we assume that third quarter they're going to have some meaningful maintenance downtime?

Yes, there will be some seasonal downtime in the North Sea every year in third quarter. And then you'll have some normal decline at Valhall as well.

Yes, I see. And maybe this is for John Rielly. John, when I'm looking at the first-quarter exploration expense -- I know that this is close to impossible item to be really precisely predict, but should we view that as somewhat of a [normal] nice run rate going forward? Because that is much lower than what we typically experienced or that normally expected from the Company over the last several years.

So, in the first quarter, there was very limited dry-hole expense in there. The only thing that was in there was the non-commercial portion of the Kurdistan well, the Triassic section, so there was only a $10 million dry hole in there.

So from outside of that, you could call it typical tape of run rate there. But we are drilling. There is going to be exploration drilling that's continuing in Kurdistan; it's continuing in Ghana.

So just like you said, Paul, it's very difficult to predict exactly what the expense is going to be. Clearly, our expenditures are staying around that $550 million level that we set for the full year, and it will just depend on the success of the wells.

And I think previously the assumption is that you guys would decide on whether it's a spin or a sell sometime in the second quarter. Are we still looking at the same time line for that now that that time line may have changed a little bit?

No, I think what we would rather do is -- we are well advanced in the divestiture process, and we'll make the announcement when we're ready to make the announcement.

Okay. And that for two final questions. For John Rielly, on the -- when you're talking about the DD&A going up in the second quarter because of higher Bakken production, and we look at it in ballpark estimate, seems to suggest that the Bakken unit DD&A may be around in the $35 plus. Is that on the ballpark correct so that we can use it to estimate? In the future, what should we assume the DD&A as Bakken production go up?

We haven't been specific on that, Paul, outside of saying that the Bakken DD&A is above our portfolio average. And it is a good bit above the portfolio average. So -- and just to remind you, our cash costs, though, on the Bakken outside of a quarter like this with the gas plant being down, its run rate for the cash costs are in line with our portfolio average or a little bit below.

And so, again, you've got to look at where we are in the process of developing the Bakken. Obviously, volumes are going to begin here to ramp up, so that volume ramp up will continue to lower our cash costs in the Bakken as well as we continue to produce out and get more performance history in there; and our DD&A rates will come down over time as well.

Do you have any idea when that the (inaudible) [DD&A] and Bakken you [broke] will start to trend the other way going down?

I don't -- it will start just slowly each year. So starting in 2015 and 2016; again, as we begin to do that, it will just start to slowly trend down. And you know where our Bakken D&C costs are getting to and the EURs on the wells. So, ultimately, it will track down to that with the inclusion of infrastructure costs.

Okay. A final one. On the gas plant, have you guys -- I presume you're saying that 70% of the gas is Hess operated, but that 30% is outside. So how the NGL extraction economics? Is that based on the fee base or that you take the commodity risk by buying the gas and then you get whatever that you can sell for dry gas and NGL? Can you help us understand a little bit on the economics how that works?

Sure, so, again, first we'll do it from a Hess standpoint and then third-party. So on the Hess standpoint, obviously, the economics are just taking liquids out and getting better pricing for the liquids versus the gas or the wet gas running through the system. So that increases our economics. And you'll see the flow-through of that on our NGL production and the prices that we get. So you'll see that in the press release.

As far as third-party coming in, all contracts are different. And so you run on percentage of proceeds type contracts where you'll get a certain portion of the liquids that come out that come to Hess that we then sell and get that revenue -- not production, we get that revenue associated with that. There are other contracts where some is a percentage of proceeds; some as fractionation fees. So, we get it up; you'll see that actually in our revenue line -- not in our production lines, but just on our revenue line for E&P.

And as we're preparing this for an MLP listing next year, is it any particular strategy from the management standpoint that whether you want to move a contract one way or the other to become more fee-based? Or that you're still okay there with more or sort of take on the commodity progress given that the two revenue streams have a very quite different on the multiple.

You are absolutely right, Paul. So the economics that I just talked about in the commodity exposure is what Hess will maintain and continue to maintain post an MLP-type transaction. The MLP revenue will be solely fee-based, and the MLP will charge. Even though the contracts will work for Hess and Hess will maintain all the commodity exposure, the MLP will not have that commodity exposure. It will just be fee-based.

Okay. Thank you.

(Operator Instructions) Paul Sankey, Wolfe Research.

There's been a tremendous number of moving parts here. Could I just ask you -- and forgive me if you've already said some of these things. But could you just repeat what your full-year CapEx expectation is for 2014 and, to any extent that you can, look forward beyond 2014 as to what you think the run rate for the Company will be? Could you additionally talk about where you think the optimum level of leverage is in terms of debt, debt to capital, et cetera? You know, whether that's changed over time or whether there's a number that we can just think of.

And then could you just talk a little bit about the mechanics of the buyback, which is to say, whether it's just a rated buyback, an opportunistic buyback? Anything you could add. Thank you.

Sure, so first [bank] was the E&P capital guidance. It is $5.8 billion; that is still the number, and obviously we'll track it as we go throughout the year. I think the next thing you asked was about our leverage or our debt to capital (multiple speakers) -—

Well, sorry to interrupt, I just wondered whether there was any sort of indication of what CapEx should be.

Sorry, Paul. So on a go-forward basis, the guidance that we have been saying is that post 2014, with our capital expenditure profile, we will be free cash flow positive. So we really don't go out and give long-term guidance on where that capital level is, but it's going to be in a range like that of the $5.8 billion. But we're not going to be specific on that right now.

The leverage target is not a change for us. The way we think about it is we want to maintain a solid investment-grade credit rating. And so any leverage metrics that we look at are to continue to achieve that solid investment grade, which is BBB+ at least. And then I think you the last question --

Which dividend and -- I guess I didn't throw in dividend, but I will now. So dividend and buyback. The buyback was just whether it's a rated kind of ongoing or an opportunistic type approach. And then any comments you can make on where the dividend might go from here in terms of the big increase you had last year and what you aspire to do with it going forward. Thanks.

And so we're going to continue -- as you've seen with our stock buyback, we have a disciplined approach to the buyback. And that is depending on market conditions. And we plan to continue that disciplined approach.

I think, as John Hess said earlier, we will update, post the announcement of the retail transaction, whether it's a spin or it's a sale on where our authorization is for the stock buyback. So we're going to continue that way.

And then as far as dividends go, as you know, we did increase the dividend last year. And John had mentioned it, as we looked at our free cash flow going forward and we have excess free cash flow as production increases, we will be looking at additional current returns to shareholders at that time.

Great. Thank you. And then another long-term one and I'll leave it there. You've learned a lot, obviously, from a very aggressive process of restructuring. Are we now looking at the terminal points of Hess? Do you have an idea of what the optimal balance of the assets and overall Company will be? Or can we see this is an ongoing under-revision type process? Thanks.

As you know, Paul, with the completion of our Thailand sale, we've pretty much completed our portfolio restructuring that we announced a year ago on March 4. Retail and [headco] are the only two remaining for this year, and they are well underway.

Obviously, let's not forget the Bakken infrastructure. That will be a monetization event next year above and beyond anything that we're doing this year. But with the transformation to a pure-play E&P substantially completed, our focus going forward is going to be on operations, driving our low-risk, cash-generative growth and sustainable returns from our portfolio. And any further portfolio reshaping would just be part of the normal course of business of business operations.

Great. Thank you, John.

Jeffrey Campbell.

I wanted to ask you going back to the Bakken, these stack tests that you're doing. Do you model the Three Forks as for discrete zones as do some producers in the play, or do you think of it in another way? And having said that, what portion of the Three Forks are you landing in the stack zone tests that are upcoming?

Yes, so we have put wells in the second bench of the Three Forks as well as the first bench of the Three Forks. So we do see some potential in the deeper benches of the Three Forks.

Now, as I've said before, ultimately the decision is going to come down to economics. So does the incremental recovery from putting a well in each bench to justify the cost of doing that well? Or can a single well access the majority of the reserves anyway? So that's really going to be the question that we're doing. We're planning our tests to help us answer that question.

Regarding the Three Forks in general, we estimate that 60% to 65% of our acreage, core acres, will be prospected for the Three Forks.

Okay. Great. That's helpful. Turning to the Utica quickly, I looked at the first-quarter 2014 well announcement from your partner. And I was just wondering -- bearing in mind that these wells are line-constrained, would you qualify the performance of the first-quarter 2014 wells as on average with your other wells that you've published results on (multiple speakers) accounting for (inaudible) constraint?

Yes, again, I think we are continuing to delineate the play. And I wouldn't want to say that those wells were the same as other wells. Because, again, in our delineation, we are finding some variation in those well rates. And so, no, I wouldn't say those are typical results.

Okay. Thank you. And the last one that I'll ask -- well, actually I wanted to ask one other Utica question quickly. Can you give us any idea of what your current well costs are and what those might look like a year from now?

Yes, so the -- we're still in the appraisal mode. Therefore, the costs of our wells are still pretty high as we are gathering extensive core log and technical data. And, plus, we continue to experiment with lateral lengths, stage count and frac size to really try and figure out what are the optimum development plan here.

But what I will say is over the past 12 months, we've achieved about 50% reduction in per-foot drilling costs and a 30% reduction in per-stage completion costs. So on a per-foot and per-stage basis, we're seeing the same things happen that happened in the Bakken as we gain efficiencies in our drilling and completion costs, and we expect that trend will continue.

And then those efficiencies you are gaining, are you are ready drilling on pads? Or are they still stand-alone wells that you are seeing these efficiencies on?

We are. We are drilling on some pads. We've got three rigs operating, and some of those are on pads.

So is it fair to qualify the reductions that you just identified as being somewhat pad-related, or is it -- should we think of it another way at this point?

No. It's both pad-related and efficiency-related.

Okay, great. And the last question I wanted to ask was a little bit more high-level. As you are preparing to examine production and continue drilling in Kurdistan, what's your current take of the progression to be able to export Kurdistan product over the next 12 to 18 months? Thank you.

I think we are continuing to develop our commercial strategy on Kurdistan as we speak.

Greg and I were in Kurdistan about a month ago -- and leave it to the Kurdish government to give you updates on their export plans -- but the physical capacity is there to export to Turkey. And we're pretty confident that we have a commercial discovery that can be developed. We'll be in a position to be able to export the oil.

Okay, great. Thank you.

Pavel Molchanov, Raymond James.

First back to the Utica, you've been seeing over the past year that the earliest full-scale development could begin as the first half of 2015. Any changes to that time table?

No. I think that's our strategy now is to figure out what the full-scale development plan will be in 2015. And that's why we're still experimenting a lot with lateral length and frac stages and proppant loading and all those things you do to try and figure out what the optimum is.

Okay. And then on exploration expense, obviously, you can't really guide to it. But I think in Q1 the $119 million was the lowest quarterly number in three, four years minimum. That's not going to be the norm going forward, that run rate, is it?

No, it's -- I'd mentioned it earlier. It's because we had a very limited dry-hole expense in there. Is about $10 million related to the lower Triassic section of the Kurdistan well. And so that's the only dry-hole expense in there. We obviously are drilling in Kurdistan; the next well is about to spud. And then we've got drilling in Ghana. So it's very difficult to predict but, yes, it should be higher.

All right. Appreciate it, guys. That's all for me.

Thank you, ladies and gentlemen. That concludes today's presentation. You may now disconnect. Have a great day.