赫斯 (HES) 2013 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2013 Hess Corporation earnings conference call. My name is Matthew and I will be your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session toward the end of the conference. (Operator Instructions) As a reminder, this call is being recorded for replay purposes.

And now I would like to turn the call over to Mr. Jay Wilson, Vice President of Investor Relations. Please proceed, sir.

Thank you, Matthew. 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's Annual and Quarterly Reports filed with the SEC.

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 and Chief Financial Officer. I will 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 Greg Hill will provide an operational update, and John Rielly will review our financial results.

As most of you are aware, our management team and Board of Directors have been in the process of undertaking a multi-year transformation of Hess Corporation into a more focused, higher growth, lower risk, pure play E&P company. We are successfully executing our plan, and are gratified by the results of our first-quarter adjusted earnings of $669 million, which, from last year's first quarter of $509 million, represents an increase of 31%.

We achieved these results even after the loss of production from the sale of our interest in the Beryl, Schiehallion, and Bittern fields in the United Kingdom North Sea, as well as the downtime associated with the Valhall redevelopment project in Norway. This accomplishment, in the context of our continuing transformation, bears testimony to the focus, commitment, and hard work of our dedicated team of senior managers and employees. While we will get into the financial details behind these results later, I would like to spend the next few minutes reviewing the progress we have made toward becoming a pure play E&P company.

On March 4 of this year, we announced the final steps of this strategy with three overarching goals. One, that we continue to reshape our upstream portfolio and exit our remaining downstream operations. Two, that the proceeds from these divestitures be allocated both to fund the Company's future growth and provide substantial current returns to shareholders. And three, that Hess deliver on its forecast of 5% to 8% compound average annual growth in production.

In just the seven weeks since this announcement, we have made substantial additional progress toward achieving these goals. Let me start with an update on our divestitures.

Both the Azerbaijan and Beryl asset sales were closed in the first quarter, yielding after-tax proceeds of $880 million and $440 million, respectively. We agreed to the sale of our acreage in the Eagle Ford Shale play in Texas for $265 million, relieving our Company of approximately $500 million of capital expenditures over the next several years. On April 1, we announced an agreement to sell 100% of Samara-Nafta in Russia to Lukoil for $2.05 billion. Hess has a 90% ownership position in Samara-Nafta.

Last week, Lukoil received the consent of the Russian Federal Antimonopoly Service to acquire the asset. We expect to close this transaction within the next week.

Work is also underway on the divestment of our upstream assets in both Indonesia and Thailand, as well as the processes to exit our downstream terminals, retail, energy marketing, and trading businesses. We will apply the proceeds from our recent divestitures, including Russia, to reduce debt and strengthen our balance sheet, so the Company will have the financial flexibility both to fund its future growth, and also to direct most of the proceeds from additional asset sales to return capital directly to shareholders.

We expect the $4 billion share repurchase plan to begin in the second half of this year. In addition, we will increase our annual dividend to $1.00 per share beginning in the third quarter of 2013.

Lastly, we are continuing to make excellent progress toward delivering our production growth forecast of 5% to 8% per year compounded annually. To that end, net production from the Bakken shale oil play in North Dakota, our principal engine of growth, averaged 65,000 barrels of oil equivalent per day in the first quarter, an increase of 55% over the year-ago quarter. We continue to forecast Bakken production this year to average between 64,000 and 70,000 barrels of oil equivalent per day.

Our average well costs from drilling the Bakken in the first quarter was $8.6 million, a decline of 36% from the first quarter last year, and a continuation of a steady downward trend since the beginning of 2012. We believe our operating performance in the Bakken ranks among the best.

In the emerging Utica Shale play, we continue to execute our appraisal program and remain encouraged by the results. In addition, the Valhall field redevelopment is complete, and our focus is on the drilling campaign to increase production. We also continue to advance our development projects at Tubular Bells in the deepwater Gulf of Mexico, and the North Malay Basin in the Gulf of Thailand. And we will submit our appraisal plan for offshore Ghana to the government in the second quarter. Greg will further elaborate on our operating results in a moment.

As you can see from this brief overview, we are making substantial progress toward our goal of becoming a pure play E&P company. However, there is still much to do. With the commitment of our people and their focus, we are confident that we will continue to successfully execute our program and deliver value to our shareholders.

With that, I would now like to turn the call over to Greg Hill, who will bring you up-to-date on some of the operational details behind these results.

Thanks, John. First I'd like to comment on the recent changes to our portfolio announced on March 4, and then I'd like to provide an update of our progress in executing against our three-pronged growth strategy of unconventionals, exploitation, and focused exploration.

As John mentioned, we've taken numerous actions this quarter to ensure our portfolio is focused on higher growth, lower risk assets. During the first quarter, we announced that we had reached agreements to sell our interest in several non-core assets, including ACG, Beryl, and the Eagle Ford, and began the process to divest our assets in Indonesia and Thailand. On April 1, just after quarter-end, we also announced an agreement to sell Samara-Nafta in Russia. We expect to close the Samara-Nafta transaction in the second quarter for net proceeds of approximately $1.8 billion, generating an after-tax gain on sale of approximately $900 million.

The ACG and Beryl transactions resulted in gains of $360 million and $323 million, respectively. While we incurred an after-tax loss in the fourth quarter of 2012 of $192 million related to the sale of our Eagle Ford position, we were not able to establish a core acreage position there, and will now be able to reallocate approximately $500 million in future capital expenditures to higher return opportunities in our portfolio.

Following these divestitures, roughly 80% of our remaining reserves in production will be confined to five principal geographical areas. These five areas can be described as long-lived, good margin areas with low risk growth that leverage our capabilities and competitive advantage. The opportunities within these five areas reflect our three-pronged strategy for future growth through, one, unconventionals, with growth driven primarily from the Bakken and Utica; two, exploitation, with growth driven by Tubular Bells, Valhall and North Malay Basin; and three, focused exploration in areas such as Ghana. This balanced strategy underpins our forecast of 5% to 8% compound average annual growth in production.

Now let me turn to our progress in executing against each leg of this growth strategy. Starting with the first element of our strategy, unconventionals, we continue to make excellent progress towards our mid-decade goal of achieving net production of 120,000 barrels of oil equivalent per day from the Bakken. First-quarter net production was 65,000 barrels of oil equivalent per day, up 55% from the first quarter of 2012 and in line with our previous guidance for 2013.

As a result of our transition to pad drilling, as previously discussed, production will be relatively flat through May, as we continue to build inventory of drilled but not completed wells. But production will increase substantially in the second half of 2013, as we ramp up our completion activity. We remain confident in our 2013 Bakken production forecast of between 64,000 and 70,000 barrels of oil equivalent per day.

In terms of individual Bakken well performance, we are focused on driving high returns, which, as you know, is a function of both well costs and well productivity. Well costs for the first quarter averaged $8.6 million per well, down 36% from $13.4 million per well in the first quarter of 2012, and down from $9 million per well in the fourth quarter of 2013. The continued quarter-end-quarter reduction in cost has been driven by our application of lean manufacturing techniques. Our productivity continues to be the highest in the industry, as 10 of the top 25 wells in the North Dakota Bakken play in 2012 were Hess wells. Therefore, considering well costs and productivity, coupled with higher margins from our infrastructure, we believe we are one of the most competitive Bakken operators and there is much more optimization to come.

During the quarter, we brought 30 wells onto production, of which 21 were Middle Bakken and nine were Three Forks. For the full year, we expect to bring approximately 175 wells on production, with two-thirds targeting the Middle Bakken and one-third targeting the Three Forks. Our Tioga rail facility ran at capacity in the first quarter, delivering an average of 53,000 barrels per day to higher value markets. Our Tioga Gas Plant expansion project is on schedule to be commissioned at the end of 2013, which will enable us to capture more value from our own gas and third-party volumes.

In summary, our long-lived, high-margin Bakken asset continues to deliver relatively low-risk growth that leverages our capability and competitive advantage. Operational performance is firmly on track, as our team continues to focus on execution, capital efficiency and profitable production growth.

Turning to the Utica, the appraisal of our acreage continues and we are increasingly encouraged by our well results to date. In the first quarter, four wells were drilled, seven were completed, and five were flow-tested. Three of the five tested wells were operated by Hess. On our 100% owned acreage, we tested two wells during the quarter. The Capstone 2H9 well in Belmont County tested at a rate of 2242 barrels of oil equivalent per day, including 42% liquids, and the NAC 4H-20 well in Jefferson County tested at a rate of 7.5 million cubic feet per day of dry gas.

On our joint venture acreage, we tested the Jeff Co. 1H6 well in Harrison County at a rate of 1432 barrels of oil equivalent per day, including 20% liquids. Also, as previously announced, the Athens 1H-24 well, also in Harrison County, was tested in late 2012 with a rate of 4230 barrels of oil equivalent per day, including 59% liquids. Although still very early days in the appraisal phase, these well results are encouraging. In 2013, we and our partner, CONSOL, plan to drill approximately 30 wells across both our 100% owned and joint venture acreage.

Turning to the second element of our strategy, exploitation. Progress continues at Tubular Bells, Valhall, and North Malay Basin. At our 57% owned and operated Tubular Bells development, in the deepwater Gulf of Mexico, our first production well was drilled during the first quarter and encountered 146 feet of net pay, which is 46% higher than pre-drill prognosis. We are currently drilling the second production well, and facilities construction is on schedule for field startup in mid-2014 to deliver 25,000 net barrels of oil equivalent per day of high-margin production.

At the BP-operated Valhall field in Norway, in which Hess has a 64% interest, the field's redevelopment project completed, and the operator resumed production on January 26. In the first quarter of 2013, net production was 5000 barrels of oil equivalent per day, as the operator began to ramp-up facilities and resolve routine startup issues. Full-year 2013 net production from Valhall is forecast by the operator to be in the range of 24,000 to 28,000 barrels of oil per day, which we believe will come in at the lower end of this range.

Looking forward, our primary focus is to work with the operator to grow production over the coming years, leveraging the Chalk Reservoir drilling and completion capability we have developed in South Arne in Denmark. Two drilling rigs are working in the field currently, with the goal of bringing six new wells online during 2013.

In Southeast Asia, we continue to demonstrate our project execution capability. In the Malaysia-Thailand joint development area, we installed our eighth wellhead platform in the first quarter on time and on budget. At North Malay Basin, we installed the jacket and topsides for the early production system in April, and plan to start development drilling at mid-year. The project is on track to commence first gas in the fourth quarter of 2013 at a net rate of approximately 40 million cubic feet per day. We also continue to advance full field development, scheduled for first gas in 2016, which will increase net production to approximately 125 million cubic feet per day.

Turning to the final element of our strategy, focused exploration, we announced in February our seventh consecutive discovery in Ghana, Pecan North #1. Drilling performance in Ghana has been top quartile, with costs for the last three wells, which were drilled in 6000 to 8500 feet of water, averaging $40 million per well. Discussions regarding the appraisal plans for the block are ongoing with the Ghanaian government.

In closing, we are on plan with respect to both our strategic positioning and operating performance. I will now turn the call over to John Rielly.

Thanks, Greg. Hello, everyone. In my remarks today, I will compare results from the first quarter of 2013 to the fourth quarter of 2012. But before I begin, I want to highlight some changes we have made in our first-quarter earnings release and supplemental data.

As a result of the Corporation's previously announced plans to divest its downstream businesses and complete its transformation into a pure play exploration and production company, we have presented the after-tax downstream results for all periods as discontinued operations. With this change, we now operate with two segments -- an Exploration and Production segment, and a Corporate and Other segment, which is primarily comprised of corporate and interest expenses.

As a pure play E&P company, we have made various changes to the financial and operating data in the earnings release. For example, in the income statement, our previously reported production expenses have been split into two lines -- operating costs and expenses, and production and severance taxes. In the operating data, we provided quarterly sales volumes in addition to a more detailed breakout of production volumes.

Finally, as we have done in the past, we have filed our supplemental earnings presentation on our website. We have added quarterly operational data for the Bakken and pro forma E&P results for 2012 and 2013 to the supplemental presentation. The pro forma information presents our results as if our asset divestiture program had all been completed effective January 1, 2012, so that we can present a historical comparison of the performance for the remaining portfolio.

Turning to consolidated results, the Corporation generated consolidated net income of $1,276,000,000 in the first quarter of 2013, compared with $374 million in the fourth quarter of 2012. As a result of progress in our transformation, there are a number of special items in the quarter. Excluding the items affecting comparability of earnings between periods, the Corporation had earnings of $669 million in the first quarter of 2013, compared with $409 million in the previous quarter.

Turning to Exploration and Production, E&P had income of $1,286,000,000 in the first quarter of 2013, and $325 million in the fourth quarter of 2012. Excluding items affecting comparability of earnings between periods, E&P had income of $698 million in the first quarter of 2013, and $431 million in the fourth quarter of 2012. First-quarter results included after-tax gains totaling $683 million related to the sales of our interest in the Beryl and ACG fields. First-quarter results also included an after-tax charge of $67 million for employee severance costs, and a non-cash income tax charge of $28 million as a result of a planned divestiture. Fourth-quarter 2012 results included net after-tax charges of $106 million from items affecting comparability of earnings between periods.

Excluding these items, the changes in after-tax components of the results were as follows -- higher realized selling prices increased earnings by $148 million; lower exploration expenses improved earnings by $94 million; lower operating costs increased income by $57 million; the mix of sales volumes decreased earnings by $17 million. All other items net to a decrease in earnings of $15 million for an overall increase in first-quarter adjusted earnings of $267 million.

Our E&P crude oil operations were overlifted compared with production by approximately 300,000 barrels in the quarter, which increased after-tax income by approximately $10 million. Our E&P cash operating costs were $21.20 per barrel of oil equivalent for the first quarter of 2013, and our guidance range for the full year remains $21 to $22 per barrel. Depreciation, depletion, and amortization expenses were $19.28 per barrel for the quarter, and our guidance range remained $19 to $20 per barrel for the full year.

The E&P effective income tax rate, excluding items affecting comparability, was 42% for the first quarter of 2013, which was below our guidance, due to the startup of production from the Valhall field. The full-year E&P effective income tax rate is still expected to be in the range of 46% to 50%. We have Brent crude oil hedges covering 90,000 barrels of oil per day at a price of approximately $109.70 per barrel that are in place for the remainder of 2013.

Turning to Corporate and Other, corporate expenses were $44 million in the first quarter of 2013 compared with $43 million in the fourth quarter of 2012. Corporate expenses in the first quarter of 2013 included an after-tax charge of $11 million for employee severance costs. After-tax interest expense was $66 million in the first quarter of 2013 compared with $67 million in the fourth quarter of 2012.

Turning to Marketing and Refining, which are now classified as Discontinued Operations, Marketing and Refining earnings were $100 million in the first quarter of 2013 and $159 million in the fourth quarter of 2012. As a result of ceasing refining operations at the Port Reading facility in February, first-quarter 2013 results included after-tax income of $137 million relating to the liquidation of LIFO inventories, partially offset by after-tax charges totaling $64 million comprised of accelerated depreciation and other shutdown costs. In addition, an after-tax charge of $43 million was recorded for employee severance costs related to our plan to exit the Corporation's downstream businesses. Fourth-quarter 2012 results included net after-tax income of $71 million from items affecting comparability of earnings between periods.

Turning to our financial position, we are applying the proceeds from our asset sales program in order to have the financial flexibility to both fund growth and provide current returns to shareholders. To fund our growth, we have committed that the proceeds from divestitures would be sequentially applied to, first, repay short-term debt of approximately $2.5 billion. Second, to provide a $1 billion cash cushion. Third, to fund the 2013 cash flow deficit; and four, to return cash to shareholders by repurchasing up to $4 billion of shares.

In addition, as John has stated earlier, the Corporation will increase its annual dividend starting in the third quarter of 2013. Subsequent to our March 4 announcement of our transformation to a pure play E&P company, S&P, Moody's, and Fitch all maintained our mid-BBB rating. Following the completion of the sale of our Russian subsidiary, Samara-Nafta, we will be able to repay all remaining outstanding short-term debt and begin building our cash cushion. As John has mentioned earlier, we expect to begin our share repurchase program in the second half of this year, as further planned asset sales are completed.

During the first quarter of 2013, the Corporation generated net cash from continuing and discontinued operations of $819 million. The cash provided by operations, together with proceeds from asset sales of $1,326,000,000 and cash on-hand, were used to fund $1,521,000,000 of capital expenditures and repay $752 million of outstanding borrowings. We had $444 million of cash and cash equivalents at March 31, 2013, and $642 million at December 31, 2012. Total debt was $7,376,000,000 at March 31, 2013 and $8,111,000,000 at December 31, 2012. And the Corporation's debt to capitalization ratio was 24.7% at March 31, 2013, compared with 27.7% at the end of 2012.

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

(Operator Instructions) Doug Terreson, ISI.

Congratulations on your results. (multiple speakers) So, I wanted to see -- I had a strategic question -- I wanted to see if we could get an updated view on Australia, in light of the recent commentary that Woodside is no longer going to seek third-party gas for its Pluto development. And then second, the next steps are planned for the other position in one of the Beetaloo Basin in Australia. So two Australia questions.

Yes, thanks, Doug. On your first question related to the offshore position in Western Australia, 390-P, recall we are negotiating with three different parties for liquefaction of that gas. And so, there's other parties besides Woodside in the mix. And both discussions are continuing with the parties.

For the second thing, on the Beetaloo Basin, we're in the process of processing the new seismic that we just shot, and then we have to make a drill-or-drop decision by mid-year. And so that's where we are in the process.

Mid-year '13?

Yes.

Thank you.

Roger Read, Wells Fargo.

I guess following up on your Bakken expectations, can you walk us through maybe right now -- I mean, are we seeing production actually declining into the month of May, I mean, kind of reflecting depletion rates? And then, obviously, as wells come on beginning in May, all the way through the end of the year, production ramps up and could exceed your level? Or 70,000 is really as good as it gets in 2013? I'm just trying to understand the moving parts there.

Yes, I think -- thanks, Roger. I think as we announced previously, as a result of our switch to pad drilling from held-by-production drilling, you build inventory of drill but not completed well. So your completion rate is lower than what it was last year. So as a result of that, your production for the first five months of the year is flat to slightly declining.

In the first quarter, our production was 65,000. For the next couple of months, that could decline just a little bit, so it will be flattish. And then as we put wells on completion, as we move the completion spreads in, our completion rate really doubles the last half of the year. So our production is very much backend-loaded for the year. As we said in the opening remarks, we feel confident of a range of 64,000 to 70,000 barrels a day.

Okay, thanks. And then on Ghana, what -- is there a timeline we can think about there in terms of -- okay, obviously great success story on the exploration front; you start working with the government here -- I mean, I say start working; you already have been, but -- any expectations for when something might occur there that you could talk about, in terms of a future development plan or anything like that?

Sure. I think -- so there's two things that we have to do. The first thing, which is the most important piece of business right now for us, is to get the approval -- appraisal program approved by the government. That has to occur by mid-year. And so we're in the process of having those discussions with the Ghanaian government. In parallel, we are also doing predevelopment studies. Now, once we get the appraisal program approved by the government, then we have a two-year clock to get our appraisal activities done. So that kind of lays out a time frame for you. Lots of appraisal activity over the next couple of years; predevelopment studies in parallel; and then we aim to make a decision, obviously, after that appraisal period is done.

Okay, thank you.

Eliot Javanmardi, Capital One Southcoast.

Just a question -- you spoke about it in the last quarter, your expectations for your Middle Bakken Wells and the EURs. I want to say the range between 600,000 to 700,000 barrels equivalent. Are you seeing something along those lines with that range in the Middle Bakken? And also, I don't know if you can, but could you give us maybe a percentage acreage split on what you have in the Middle Bakken and Three Forks?

I think, as we said in our opening remarks, we plan to drill about one-third of our wells in the Middle Bakken this year. Right? And two-thirds of the wells this year will be -- or sorry, one-third Three Forks, two-thirds Middle Bakken wells this year. Regarding your question on EUR, the range is still valid. You know, the EURs in the first quarter that came out of the wells that we drilled were in the low [600,000's].

Very good, thank you very much for that color. Last question, then. With the increasing appraisal likely for Ghana, should we expect the exploration budget to -- exploration and appraisal budget to swell a bit in the coming years versus where we are now?

No. I think as we've guided previously, this [500,000] to [600,000] level is where we want to keep that budget. So we're going to fit -- live within those means.

Excellent. And lastly, on the Utica well, the Capstone well, could you -- was there a timing duration you guys could give on the results that you provided there? If not, I'll just leave it at that. Thank you.

Yes, on the Utica Wells, we are trying to give comparables to what all the competitors are giving. So that these are early time tests, right? Typically 24 hour kind of tests, right?

Sure, sure. Thank you very much.

Okay. Thank you.

Doug Leggate, Bank of America.

Greg, on the, I guess, the commentary around the Utica and the Bakken, a couple of questions, if I may. First of all, on the Bakken, what portion of your acreage is prospective for Three Forks? And if you could maybe help us with how the activity level there might accelerate, given that you're now starting to go to the Three Forks? And I guess a similar question on the Utica in terms of pace of development. I've got a follow-up, please.

Yes, Doug, I think as we previously discussed, the Three Forks underlies the majority of our acreage, you know. And the acreage we consider core, this 550,000 to 650,000 acres, a lot of that is underlined by the Three Forks. Regarding the Three Forks, we have -- at the end of 2012, we had 52 wells in the Three Forks. By the end of this year, we'll have another 65 or so in the Three Forks. So that gives you a sense of where we are. And again, our drilling program, one-third Three Forks this year, two-thirds Middle Bakken.

So I guess what I'm really trying to figure out is, if you've essentially doubled your locations then if you're saying the Three Forks underlies most of the acreage. So what does that mean in terms of pace of development? I mean, 175 wells seems fairly modest, given the opportunity set.

Yes, I think, Doug, on the Three Forks, while it underlies all our acreage, we still have to do some appraisal of that. Just like everyone else, I think there will be really good parts of the Three Forks which we've seen, and there may be some not-so-good parts of the Three Forks. So that's really what we have to figure out in our drilling program this year and next year, is how much of that is really, really prospective. Our focus this year, obviously, in 2013, is capital efficiency, so we are going in and drilling some of the best locations in the Three Forks, as well as appraising some of the other acreage.

Okay, got it. Sorry, the same question for the Utica in terms of, are we at the point where you're ready to talk about a development plan yet? Or it's still too early?

No, Doug, it's -- gosh, it's still too early. I mean, to put it in context, if you add up 2012 and 2013, we've drilled 11 wells in '12 and '13 so far, and we've only tested 10. So clearly, we've got a lot more drilling to do. We plan to drill about 30 wells this year. So at the end of this year, we'll have about 42 wells under our belt. And contrast that to the Bakken, of course, where we have over 600 wells. So, it's still early days in the Utica, but we are encouraged by the results so far, particularly in Belmont, Jefferson, Harrison Counties.

Got it. Thank you. My quick follow-up is for John Rielly. It's on operating costs guidance, John. Does that still include Russia? And can you, now that you've got a deal in Russia, can you give us an idea of what the OpEx would look like ex-Russia? And I will leave it there. Thanks.

Sure, Doug. And just to let you know, Doug, we do -- it's on our website now in that supplemental presentation, we have pro forma results up there, showing what the portfolio would look like with Russia out, and Indonesia and Thailand, all the assets sold as if it went back to the beginning of 2012.

But just to give you an answer to your questions here, if you're looking at 2013, what we expect from overall, first on a revenue per barrel, our revenue per barrel will go up over $5.00 a barrel because of Russia exiting the portfolio. So first, you get that higher uplift then on the revenue line. When it comes to cash costs, we see that basically from a guidance standpoint being relatively flat for the full year, pulling out all those assets. In the first quarter, for example, I told you the portfolio had a cash cost of $21.20. On a pro forma basis with the assets sold, it would have been $21.08.

Now, when it gets to DD&A, when you start removing some of these assets from DD&A, they have a lower overall DD&A rate than the portfolio. So we expect, I would tell you, the guidance then on the DD&A would be about $4 higher from an overall portfolio standpoint. And then, for example, in the first quarter, I said the DD&A rate for the total E&P assets were $19.28. For the first quarter, pro forma basis would be $22.45.

So, that's our costs guidance. And just to round it off, to give you all the guidance, on a tax -- what we see from a tax rate standpoint is somewhere around -- from a portfolio standpoint -- between 100 and 200 basis points higher. And we have some of the UK assets, obviously, with tax rates higher than the portfolio, but Russia and Azerbaijan being below it. And that's why the tax rate then effectively goes up. And then we expect, again, as we have said, that our cash margin overall goes up $5.00 per barrel.

Got it, very clear. Thanks, John.

Sure.

Arjun Murti, Goldman Sachs.

Just a few follow-up questions. Just on the Utica results, it just sounds like it's liquids-rich-y type gas at this point, mostly NGLs. If you can confirm that? And any comments on maybe the black oil potential of the Utica -- maybe you've not drilled that part yet, but any thoughts there would be very helpful. Thank you.

Yes, I think, in -- particularly in Belmont, Jefferson and Harrison Counties, we're in that liquids-rich part of the play. As you move east, as we've said before, in our Marquette acreage, then you move more into the dry gas as the Point Pleasant plunges deeper to the east. Regarding the oil activity in the West, so far, I would say the results are disappointing. It's like the Eagle Ford oil window, you know, you get shallower and the reservoir just doesn't have the energy required.

That's very helpful. Thank you. Any update on Pony? I don't think I heard an update there.

Yes, Arjun, Pony, we're continuing to feed, and we'll continue feed through this year. And we are aiming for a sanction decision, both us and the partners, in 2014.

And we can add four years from sanction to startup, something like that?

Yes, that's probably a reasonable expectation.

That's great. Thank you so much.

Evan Calio, Morgan Stanley.

On your statement, you expect to begin the $4 billion buyback in the second half, I mean per your ordering of priorities in the opening comments, should we assume that you go to work only after you've paid down $2.5 billion of debt and built the $1 billion cash cushion?

Yes, that's correct. And as I mentioned, we actually expect the -- our Russian asset sale to close fairly soon. And with the proceeds from that, we will have fully paid off our short-term debt at that point, and actually will be starting to build that cash cushion. So what we're saying that the second half of the year is, as these next asset sales come in, we're going to be in this position to be able to start buying back shares.

Right, so then if -- so if you assume to work in the buyback in the second half, you're assuming that some number of Indonesia, Thailand or terminal sales are completed by year-end? Is that fair?

That is fair.

Okay. And do you -- can you give me a -- just the cash -- the operating cash flow in the quarter? Or just going to tell me what the working capital adjustment is?

Yes, the working capital was approximately $600 million in the first quarter. I mean, typically, in the first quarter, we have a very high working capital, as you saw, compared to the first quarter. I've already started to see some of that turn in April, and we expect, like usual, the majority of that to turn by the end of the year.

Great. And then lastly for me on Valhall, can you discuss the ramp in 2013 or where the exit rate was in the quarter? And are you still on track for your -- the average guidance of [24, 28] through '13? Thanks.

Yes, Evan, as we said in our opening remarks, the operator forecast a range of [24 to 28]. We think we'll be at the low end of that range. First-quarter production averaged about 5000 barrels per day. Just as a reference point, production reached about 16,000 barrels per day by the middle of April. In addition to just the routine ramp, I'll say in the flesh production associated with that, you also have the drilling rigs in there with our aim to get six wells drilled this year. So there will be some backend contribution from those wells also.

Great, appreciate it.

Paul Cheng, Barclays.

Hey, Greg, when you say Valhall, say BP is [24 to 28], is that the gross number or your net to you?

No, no. That's net to us, Paul. Thank you. I should have clarified that.

Okay. Net to you. Okay. And on Ghana, is it too early that you give a rough estimate of what you think may be the total recoverable resource of the seven discoveries? And also do you have a rough estimate on the liquid and gas split on those resource base?

Yes, Paul, it is too early to give a resource estimate for one reason. We're not allowed to speak about resources without the approval of the Ghanaian government. And they have not allowed us to do that until we get done with our appraisal plan. So, that's the reason.

Okay. How about say in terms of the split between the liquid and black oil, and NGL and natural gas? Are you allowed to talk about that?

No, we can't do that yet either, Paul. But clearly, with our seven discoveries and a number of them black oil, the predevelopment studies are focused on the black oil.

And going on the -- in Bakken, is there a rough estimate kind of number [that ore] and any, say, trend you can guide us that what is the cash operating cost right now? And how that may look like in 2014?

Paul, there is no difference, actually I think, from basically what we have been guiding there in the Bakken right now. So, including production and severance taxes, in North Dakota, when you put that together with our Bakken operating costs, the cash costs right now are just slightly below our portfolio average in the Bakken.

John, when you say the portfolio average, you're talking about US portfolio or total company portfolio.

The total company portfolio.

Right now is [90] below total company?

I'm sorry?

Right now is [slightly] below total company?

Yes, yes, it is.

And then how about a target for 2014?

Well, again, as production begins to ramp up, then obviously, then you can take those fixed costs going over more barrels. So we see a declining cash cost per barrel, we'll be focused on that, as well as just as the maturity of the reserve bookings and the additional wells coming on will be a slow decline in the DD&A rate as well.

But you're not going to be willing there to give us some numbers? You say it declined by [2 bps, 3 bps] average for next year comparing to this year? (multiple speakers) Or anything like that you can provide?

No, not at this point. I mean, first of all, we -- from guidance on next year and what we are doing with capital, and what wells we're going to drill and all that, I mean, it's still very early for us to be able to do that. What we can say is, as we know our production is going to ramp up to 120,000 barrels a day, as we said, in mid-decade. So clearly, we can tell from that standpoint that it will just be -- the costs will go over more barrels. As Greg is saying, has just alluded to our well costs on our drill and complete are coming down.

So, again, we've been basically focused in driving down operating costs, well costs. And so both cash costs and DD&A costs will decline over time, but I can't give you specific guidance on that.

And John, how about in terms of on a pro forma basis there, how is your CapEx going forward may look like, just as something that you can give some light?

Yes, sure. So first of all, then again, on the pro forma data that we included in the -- on the supplemental presentation, so on a pro forma basis, the capital was -- capital and exploratory expenditures was $1,405,000,000 versus our total portfolio of $1,613,000,000 in E&P. So it gives you some type of range from that standpoint.

We've given guidance that, on a pro forma basis, our full-year capital would be $6.2 billion. So, that's with all the assets out of the portfolio essentially effective at the beginning of the year. We clearly are giving guidance that our capital will have a five-handle -- can I call that? -- in it. So we'll have a [five] at the start of it. So our capital will be in the $5 billion range next year. I just can't give you any further guidance at that point. And with that driving that down, we expect with our portfolio and the enhancement of the cash margin, that we will be driving towards a balance between cash flow and capital spend in 2014. And then beyond that, we expect to be able to become cash-positive.

Greg, in Bakken, have you guys start testing on the downspacing to 160 and so far what's the result on that?

Yes, we have, Paul. So we've done an awful lot of work in downspacing. And I think that the Bakken will be downspaced. That's clear from the pilots that we've run. The one thing I will say is, the degree of downspacing will depend upon where you are in the field. And so, for higher productivity areas, you probably don't need to downspace as low as you might in some of the lower productivity areas of the field. So, the answer is, it depends on the degree of downspacing, but there will be downspacing potential in the Bakken.

Final one. Since that majority of your acreage is in the Three Forks, when do you think it's going to reach the inflection point you started during the majority of the well in Three Forks and not in the Middle Bakken?

Well, gosh, Paul, we've got 2500 well locations to drill, and even more if you consider infill. And our approach (multiple speakers) --

In the Middle Bakken.

No. In Middle Bakken and Three Forks combined. And then if you downspace and infill lower, in some parts of the field, obviously, that number is going to go up. We are prioritizing wells based on highest return, and also in pads, where we can capitalize on the efficiencies -- right? -- of being on the pad. Say, drilling Middle Bakken wells, we'll add a couple Three Forks since we're there on the pad. Right?

But, as I said, I think, to Doug, we've got 52 Three Forks wells in the ground at the end of 2012. We'll have 65 more at the end of this year, so we'll have a good understanding of the Three Forks. In addition to that, we have 30 cores in the Three Forks. We've done a major study of the Three Forks, including all of the Three Forks production data that exists from the NDAC as well as our own data. So we have a pretty good understanding of Three Forks. It's going to be a good play for us.

Thank you.

Robert Kessler, Tudor, Pickering, Holt.

I had a follow-up question on Stampede or Pony. You had characterized this as being too early, I think, previously, to consider divestment of that asset. And I was curious what you need to see in order to possibly put it in the development queue? I know you've got pre-FID work ongoing. Is this more of a commercial kind of cost structure delineation that you need to accomplish? Or is there more actual drilling you need to do to better understand the resource before deciding to sell?

No. I think this project will be at its maximum kind of value point at sanction, right? And so, at that point in time, we'll know all the costs because feed will be done. We have a good understanding of the subsurface already. It's a combination of our data plus the partner's data. And at the end of the day, the decision will be focused on returns.

Greg, with a good understanding now of the subsurface, how many barrels do you expect to recover for Stampede?

We haven't said that yet, only because we haven't got all the development studies done. That's part of the feed process, right? We will announce that at the point of sanction, obviously.

And then unrelated question for me -- retailed investment. Have you gotten any further on that in terms of the form that investment may take? Are you considering a spin-out, an IPO, or an outright sale to a third party for cash?

You know, we're looking at all options to maximize shareholder value. And as I said, in all of our downstream divestitures, the sales processes are well underway.

Great. Thanks very much.

Edward Westlake, Credit Suisse.

This is Scott Willis on for Ed. I was just wondering, as far as the international asset portfolio, is there going to be further rationalization of that portfolio in the future, beyond the assets already announced?

You know, we gave a lot of study between our leadership team, our Board and advisors on the optimum portfolio to, hopefully, create a portfolio that will generate a lot of returns to our investors. And that's this focused liquids-rich portfolio that is lower risk with the 5% to 8% compounded average annual growth rate. So, there are no current plans for any other divestitures there. It's a dynamic business. Obviously, we'll always look at opportunities as we move ahead to continue to refocus and strengthen our portfolio, but there are no current plans beyond the ones we've already announced.

Okay, thank you. And then just on reserve replacement looking kind of longer-term, even past Ghana, could you just talk a little bit about where you think that reserve replacement could come from?

Well, I think if you look at our portfolio in this 5% to 8% compounded annual growth rate that we've talked about, certainly, we'll be able to replace all of that in the five-year period, and some. Right? And obviously, that comes from the Bakken, Utica, Ghana, North Malay Basin, T. Bells, all of the developments that we've announced.

Okay. Thank you.

Pavel Molchanov, Raymond James.

I just wanted to ask about two international exploration areas that I don't think you've touched on yet. First, Kurdistan -- I think you had two commitment wells for this year. Any status update on that?

Yes. So, we are currently mobilizing drilling rigs to begin drilling in the back half of 2013 in Kurdistan.

Okay, in the back half. Have you identified sites up for those?

Yes, we have. We've got both locations picked. They're in the process of building locations, roads, et cetera, to mobilize the rigs.

Okay. And then on your legacy acreage in France, obviously, the unconventional stuff is out of the picture right now. But are you still planning to do some conventional work this year?

Yes, in fact, we've finished one well. And the rig is moving to the second well. The first well, we cut almost 400 meters of core, so we got a lot of core out of the well. And now the core is off to be studied. But so far, it looks good. And the rig, as I said, is moving to the second well.

Okay. And is this oil or gas?

Oil.

Okay. I appreciate it, guys.

Thank you for your questions, ladies and gentlemen. I would now like to turn the call over to Mr. John Hess for the closing remarks.

Thank you. In closing, I'd like to say that we are excited about the opportunities for Hess and our shareholders. You've just heard how well we did in the first quarter, both operationally and in terms of our strategic repositioning. We are on track to complete our transformation into a pure play E&P company, and are also making steady progress towards increasing our future production at a compound average annual growth rate of 5% to 8%, as forecast on March 4.

Just as importantly, we expect to begin returning capital to shareholders, as John Rielly talked about, in the second half of this year as a consequence of these actions. We also have a wonderful opportunity to add a world-class slate of new and independent Directors to our Board.

John Krenicki is the former Vice Chairman of GE, former President and CEO of GE Energy, and a partner at Clayton, Dubilier. Kevin Meyers was the Senior Executive ConocoPhillips that led their US E&P business, transformed it, and spearheaded development of their US unconventional plays. Fred Reynolds is one of the best CFOs in corporate America. He created tremendous value at CBS and later Viacom, transforming those companies and making them leaders in returning capital to shareholders, and is Lead Independent Director at AOL.

Bill Schrader is the person BP put in charge of its best and most valued E&P assets, including ACG and Azerbaijan, BP exploration Angola, TNK-BP in Russia. And Mark Williams is well-known as one of the best oil and gas executives in the industry. He was on the Executive Committee of Royal Dutch Shell, and has spent two-thirds of his 33-year career in the upstream and midstream businesses.

Their objectivity and counsel have already been a tremendous addition to our Company, and all of us at Hess look forward to continuing to benefit from their extensive experience in the future. Finally, I'd like to thank our shareholders for their thoughtful input and continued support. Thank you very much.

Thank you, John. Ladies and gentlemen, thank you for joining today's conference. This concludes the presentation. You may now disconnect. Have a good day.