赫斯 (HES) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2016 Hess Corporation conference call. My name is Nicole, and I will be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

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

Thank you, Nicole. Good morning, everyone, and thank you for participating in our third-quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.

Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the risk factors section of Hess's 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.

On this morning's call, John Hess will make some high-level comments on the quarter and the progress we are making in executing our strategy. Greg Hill will then review our operations, and John Rielly will discuss our financial results. I will now turn the call over to John Hess.

Thank you, Jay, and good morning, everyone. Our Company has made important progress in maintaining a strong balance sheet and keeping a tight control on our spending while continuing to invest in future growth which we believe will create significant value for our shareholders. Over the course of 2016, we have materially reduced our spending in response to this lower-for-longer oil price environment. We now project our full year 2016 E&P capital and exploratory expenditures to be approximately $2 billion, down $100 million from our previous forecast, and more than 50% below 2015.

In addition, this month we will complete a $1.5 billion refinancing of higher coupon debt, extending our average maturities and lowering our average coupon rate. This transaction further strengthens our balance sheet and liquidity position and defers any significant debt maturities until 2027.

While we have reduced investment across our producing portfolio, we believe it is very important to continue to fund our growth projects in the Gulf of Thailand, deepwater Gulf of Mexico, and offshore Guyana. With regard to Guyana, we are very encouraged about the significant resource potential on the 6.6 million acre Stabroek block.

The Liza-3 well was successful, encountering approximately 200 feet of net oil pay and the same high quality reservoir encountered in the Liza-1 and Liza-2 wells. This result further confirms that Liza is a world-class resource and one of the industry's largest oil discoveries in the last 10 years. With this information, we now expect estimated recoverable resources for Liza to be at the upper end of the previously announced range of 800 million and 1.4 billion barrels of oil equivalent.

Predevelopment planning is underway, and we expect to be in a position to sanction the first phase of development in 2017. We believe Liza will offer very attractive economics at current oil prices.

In addition, we are in the early stages of evaluating the exploration potential on the Stabroek block. The drilling rigs will next move to the Payara prospect, located approximately 10 miles northeast from Liza, with results from this exploration well expected by the time of our next conference call.

With regard to our two other offshore developments, North Malay Basin in the Gulf of Thailand and Stampede in the deepwater Gulf of Mexico are on track to come online in 2017 and 2018, respectively. Together they will add a combined 35,000 barrels of oil equivalent per day and transition from being sizable cash users to significant long-term cash generators for the Company.

Turning to our financial results, in the third quarter of 2016, we posted a net loss of $339 million. On an adjusted basis, the net loss was $340 million or $1.12 per common share compared to an adjusted net loss of $291 million or $1.03 per common share in the year-ago quarter.

Compared to the third quarter of 2015, our financial results were negatively impacted by lower crude oil and natural gas sales volumes and selling prices, which more than offset the positive impacts of lower operating costs and DD&A. Net production was 314,000 barrels of oil equivalent per day, at the upper end of our guidance range for the quarter; while net production from the Balkan exceeded our guidance, averaging 107,000 barrels of oil equivalent per day in the quarter.

Our Bakken continues to deliver excellent operating results and returns in the core of the play that are competitive with the Permian and Eagle Ford. In the third quarter, drilling and completion costs averaged $4.7 million per well, 11% below the year-ago quarter, even as we transitioned from a 35-stage to a 50-stage completion design.

Our high-quality Bakken acreage, industry-leading drilling and completion costs, and advantaged infrastructure position our Bakken asset to be a major contributor to the Company's future production in cash flow growth. With the recent improvement in oil prices, we are making initial preparations to increase our drilling activity in the play next year. We will provide 2017 guidance, including capital and exploratory expenditures, as usual in January.

In summary, our Company remains well positioned for the current low oil price environment and for a recovery in oil prices. We have one of the strongest balance sheets and long-term growth outlooks among our peers, which we believe will deliver profitable growth and improving returns for our shareholders. I will now turn the call over to Greg.

Thanks, John. I would like to provide an operational update and review our progress in executing our strategy. In the third quarter of 2016, we delivered strong operating performance and advanced our offshore developments and exploration activities.

Starting with production, in the third quarter we averaged 314,000 barrels of oil equivalent per day, at the upper end of our guidance range of 310,000 to 315,000 barrels of oil equivalent per day, reflecting strong performance across our producing assets. As a result, we reconfirm our full-year 2016 production guidance of 315,000 to 325,000 barrels of oil equivalent per day, excluding Libya.

Turning to the Bakken, in the third quarter production averaged 107,000 barrels of oil equivalent per day compared to 106,000 barrels of oil equivalent per day in the second quarter and 113,000 barrels of oil equivalent per day in the year-ago quarter. We drilled 21 wells and brought 22 wells online in the third quarter.

For 2016 we now expect to drill approximately 70 wells and bring 100 wells on line. This compares to last year, when we drilled 182 wells and brought 219 wells online.

We currently have two rigs operating in the play, but as John mentioned, given the recent improvement in oil prices, we are making preparations to ramp up activity levels next year as prices recover. In the fourth quarter, we expect Bakken production to average between 100,000 and 105,000 barrels of oil equivalent per day, reflecting fewer new wells being brought online. For the full year 2016, we expect Bakken production to be approximately 105,000 barrels of oil equivalent per day.

Over the third quarter, we continued to optimize our completions from our current 50-stage design by successfully completing 53-stage and 57-stage wells, and we are trialing a 60-stage well this quarter. Even with these higher stage count trials, we still reduced our average drilling and completion costs in the third quarter to $4.7 million per well.

We expect the 50-stage completion design to yield a 7% uplift in EUR per well in the core of the play. Wells brought online of the third quarter are expected to deliver gross EUR per well of approximately 830,000 barrels of oil equivalent, and we anticipate this will approach 1 million barrels of oil equivalent in the fourth quarter. In the third quarter, average 30-day IP rates from our Middle Bakken wells increased to 899 barrels of oil per day from 811 barrels of oil per day in the second quarter, and we expect to see a further increase in the fourth quarter.

Moving to the Utica, net production for the third quarter held at 30,000 barrels of oil equivalent per day compared to 28,000 barrels of oil equivalent per day in the year-ago quarter and 29,000 barrels of oil equivalent per day in the second quarter of 2016.

Now, turning to offshore, in the deepwater Gulf of Mexico net production averaged 61,000 barrels of oil equivalent per day in the third quarter compared to 54,000 barrels of oil equivalent per day in the second quarter of 2016. At the Conger field, in which Hess has a 37.5% working interest and is operator, we started a workover to remediate a mechanical failure, as announced in our second-quarter call, and anticipate the well returning to production in the first quarter of 2017.

At our Tubular Bells field, in which Hess holds a 57.1% working interest and is operator, we will commence water injection this quarter and are currently completing a fifth producer that we anticipate bringing online in the first quarter of 2017. We will also replace a third defective subsurface valve in the fourth quarter and expect to have the well back online in the first quarter of 2017. As with other fields in the Mississippi Canyon area, Tubular Bells was also shut in for five days as a precaution for hurricane activity.

In Norway, the Aker/BP-operated Valhalla field, in which Hess has a 64% interest, continues to perform strongly, with net production of 31,000 barrels of oil equivalent per day on average in the third quarter compared to 19,000 barrels of oil equivalent per day in the second quarter of 2016 and 35,000 barrels of oil equivalent per day in the year-ago quarter.

At the Malaysia/Thailand joint development area in the Gulf of Thailand in which Hess has a 50% interest, the booster compressor tie-in was successfully completed during a planned shutdown. Net production averaged 24,000 barrels of oil equivalent per day compared to 36,000 barrels of oil equivalent per day in the last year's third quarter, reflecting downtime associated with the compression tie-in and reduced entitlement. In the fourth quarter we expect net production to be back above 30,000 barrels of oil equivalent per day.

Moving to developments, at the North Malay Basin in the Gulf of Thailand, in which Hess has a 50% working interest and is operator, we completed installation of the topsides at three remote wellhead platforms, which are part of the full field development project.

We also completed the drilling of three development wells. The project is on schedule for completion in the third quarter of 2017, after which net production is expected to ramp up steadily to 165 million cubic feet per day.

At the Stampede development project in the Gulf of Mexico, in which Hess holds a 25% working interest and is operator, we successfully lifted and set the topsides deck on the hull. All major lifts are now complete, drilling operations continue to progress, and first oil remains on schedule for 2018.

I would now like to move to Guyana, where Hess has a 30% interest in the 6.6 million-acre Stabroek block. On September 5, the operator, Exxon Mobil, spud the Liza-3 well, located approximately 2.7 miles from the Liza-1 discovery well. Liza-3 was drilled in 6,000 feet of water and reached a TD of approximately 18,100 feet. The well encountered approximately 200 feet of net oil pay in the same high-quality reservoir encountered during other Liza wells.

This reservoir sequence is also confirmed to have a common pressure regime with that and the equivalent reservoir interval found in both Liza-1 and Liza-2. Based on the positive Liza-3 results, we now expect estimated recoverable resources for Liza alone to be at the upper end of Exxon Mobil's previously announced range of 0.8 billion and 1.4 billion barrels of oil equivalent.

The operator then plans to drill an exploration well at the Payara prospect, located approximately 10 miles northeast from Liza, with results expected by late January. In parallel, we continue to progress predevelopment activities at Liza and expect to be in a position to sanction the first phase of development in 2017.

We remain excited not only by Liza, which is world-class in its own right, but also by the significant further exploration potential of the very large Stabroek block -- which, as a reminder, is the equivalent of approximately 1,150 Gulf of Mexico blocks.

In closing, I am very pleased with our team, who once again have delivered strong operational performance; relentless continuous improvement; and some key milestones and results, which we believe in combination will deliver one of the most exciting growth profiles among our large-cap E&P peers over the next decade and beyond.

I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the third quarter of 2016 to the second quarter of 2016. The Corporation incurred a net loss of $339 million in the third quarter of 2016 compared with a net loss of $392 million in the second quarter. Excluding items affecting the comparability of earnings between periods, our adjusted net loss was $340 million in the third quarter of 2016 compared with an adjusted net loss of $335 million in the second quarter.

Turning to E&P, on an adjusted basis, E&P incurred a net loss of $285 million in the third quarter of 2016 compared to a net loss of $271 million in the second quarter of 2016. The changes in the after-tax components of adjusted results for E&P between the third quarter and the second quarter of 2016 were as follows: higher realized selling prices improved results by $3 million. Lower sales volumes reduced results by $33 million. Lower exploration expenses improved results by $26 million. All other items reduced results by $10 million, for an overall increase in third-quarter net loss of $14 million.

In the third quarter our E&P sales volumes were the same as production volumes, and therefore the timing of liftings had no impact on our financial results. The E&P effective income tax rate, excluding items affecting comparability, was a benefit of 41% in the third quarter of 2016 compared with a benefit of 47% in the second quarter.

Turning to Bakken midstream, third-quarter net income of $13 million increased from $11 million in the second quarter, primarily due to lower operating costs and interest expense. EBITDA for the Bakken midstream before the noncontrolling interest amounted to $73 million in the third quarter of 2016 compared to $68 million in the second quarter.

Turning to corporate, after-tax corporate and interest expenses were $118 million in the third quarter of 2016 compared to $75 million in the second quarter. The third-quarter results include an after-tax charge of $50 million for the premium paid to purchase 65% of our notes due in 2019.

Turning to cash flow for the third quarter, net cash provided by operating activities before changes in working capital was $309 million. The net increase in cash resulting from changes in working capital was $23 million. Additions to property, plant, and equipment were $529 million.

Net borrowings were $731 million. Common and preferred dividends paid were $91 million. All other items resulted in a decrease in cash of $9 million, resulting in a net increase in cash and cash equivalents in the third quarter of $434 million.

Turning to cash and liquidity, excluding the Bakken midstream, we had cash and cash equivalents of $3.5 billion; total liquidity of $8.2 billion, including available committed credit facilities; and total debt of $6.7 billion at September 30, 2016. The increase in debt during the quarter was attributable to the partial completion of a refinancing transaction launched in September to improve the Company's liquidity position by purchasing higher coupon bonds, redeeming near-term maturities, and lowering go-forward interest expense.

To accomplish the refinancing, the Corporation issued in September $1 billion of 4.3% notes due in 2027 and $500 million of 5.8% notes due in 2047. The Company used $750 million during the third quarter to retire 8.125% notes with a carrying value of $670 million due in 2019.

In October, the Company will use $625 million to redeem $300 million of notes due in 2017 and to retire notes with a carrying value of $259 million due in 2029 and 2031. As a result of this refinancing, we have no significant debt maturities until 2027.

Pro forma for the notes purchased or redeemed in October, and excluding the Balkan midstream, our cash and cash equivalents were $2.9 billion, and total debt was $6.1 billion at September 30, 2016. Our pro forma debt to capitalization ratio was 24.5%.

Now turning to guidance, starting with E&P, cash costs for E&P operations are projected to be in the range of $17.50 to $18.50 per barrel of oil equivalent for the fourth quarter, which includes approximately $2 per barrel for planned workover activity through to replace defective subsurface valves at the Conger and Tubular Bells fields in the Gulf of Mexico.

Full-year cash costs are projected to be in the range of $16 to $16.50 per barrel, which compares to previous full-year guidance of $16 to $17 per barrel. DD&A per barrel is forecast to be $26 to $27 per barrel in the fourth quarter and $26.50 to $27 per barrel for the full year, which is down from previous full-year guidance of $27 to $28 per barrel. As a result, total E&P operating unit costs are projected to be in the range of $43.50 to $45.50 per barrel in the fourth quarter and $42.50 to $43.50 per barrel for the full year, which is down from previous full-year guidance of $43 to $45 per barrel.

The Bakken midstream tariff expense is expected to be $4.20 to $4.30 per barrel for the fourth quarter and $3.85 to $3.95 per barrel for the full year, consistent with previous guidance of $3.80 to $4.00 per barrel. Exploration expenses, excluding dry hole costs, are expected to be in the range of $75 million to $85 million in the fourth quarter and $250 million to $260 million for the full year, which is down from previous full-year guidance of $260 million to $280 million.

The E&P effective tax rate is expected to be a deferred tax benefit in the range of 36% to 40% for the fourth quarter and 40% to 44% for the full year of 2016, which compares to previous full-year guidance of 41% to 45%.

Turning to Bakken midstream, we estimate net income attributable to Hess from the Bakken midstream segment, which reflects our 50% ownership, to be in the range of $10 million to $15 million in the fourth quarter and $48 million to $53 million for the full year of 2016, which is up from previous full-year guidance of $40 million to $50 million.

Turning to corporate, we expect corporate expenses net of taxes to be in the range of $25 million to $30 million for the fourth quarter and $90 million to $95 million for the full year of 2016, which compares to previous full-year guidance of $100 million to $110 million. We anticipate interest expense to be in the range of $50 million to $55 million for the fourth quarter and $200 million to $205 million for the full year of 2016.

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, Evercore ISI.

John, you have indicated in the past, I think, that staying Brent prices near $60 would probably be needed for the Company to consider a more assertive spending profile. And within this context, some of your peers and semi-peers have taken a little bit of a different tack recently, and they have indicated that even if the oil price does increase, that their spending is not going to rise through 2020 with capital return to shareholders instead, and to reduce debt, et cetera.

So my question is how you guys are thinking about capital management over the medium-term, if we have a scenario whereby the oil price does recover? And whether you feel that the balance between returns on capital, and production growth, and financial flexibility requires adjustment in relation to the past decade? And if so, how should it change?

As you know, our strategy in this lower-for-longer oil price environment has been to preserve our balance sheet, preserve our capability, and preserve our growth options. So it is a balance. And we're about value, not volume. But with the recent improvement in oil prices, we are making initial preparations to increase activity levels once again in the Bakken next year.

We'll provide detailed 2017 guidance, including [Hapla] and exploratory expenditures, as usual, in January. But we are going to stay fiscally disciplined. It is the balance sheet that is premier here to fund through the cycle, the excellent growth opportunities we have, both short-cycle in the Bakken and longer-cycle in Guyana.

And as long as those opportunities offer superior financial returns to our shareholders, that will obviously command our capital going forward, with an eye to keeping the balance sheet in check as well as looking at, over time, offering competitive growth and increasing cash returns to shareholders as well.

So it's going to be a balance, and it's going to be a function of oil price.

Okay, John. Thanks a lot.

Doug Leggate, Bank of America Merrill Lynch.

John, I wonder if I could kick off with the Liza news this morning. With the step-out, the 2.7-mile step-out, similar thickness, it looks like, it looks like you have got a really shallow incline on this discovery, I guess. My question is: have you hit lowest known oil yet? Did you find your water contact? And if I may, my understanding is you are staying on the well to deepen the well. Can you talk a little bit about what you are looking for and what the next steps may be?

Yes, Doug. This is Greg. The well is still under evaluation. I mean, what we can say is that we found 200 feet of very nice quality oil sands, consistent with the sands at Liza 1 and Liza 2. So we are going to have to wait until the well is fully evaluated.

Regarding next steps on the well, you're right. We are deepening the well, sidetracking and deepening the well, going to some separate, but distinct, deeper sand packages.

I think the real takeaway there, Doug, to your point, Liza has gotten bigger. It is in excess of 1 billion barrels of oil equivalent and, we believe, offers very attractive financial returns at current prices. And that is the key point.

So just to be clear, you didn't find your water contact, or you did?

We will refer that question to the operator when ExxonMobil has their call on Friday. We have a bigger resource here than before, so you can draw your own conclusions from that.

Okay. Thanks. Quick follow-up, if I may. So you are talking about Payara by the next quarter's results. But that is three months away, and these are apparently taking 45 days to drill. What should I read into the timing?

Well, I think, Doug, first of all, we've got to finish the current deepening that we are on with the current well. So we are in operations right now in that well. We have got to finish that out. And depending on -- obviously what we find could dictate how long the well takes to complete.

And then we will move the rig over to Payara and begin drilling at Payara. There again, depending on what we find will dictate how long it actually takes to finish the well.

Okay. Last one for me, very quickly. Follow-on to Doug's question, actually, about the Bakken. I understand you're going to give guidance, John, early next year, but I am just curious what your objective is, because you are still seeing declines in the field. Are you looking for stability, or are you looking to grow the Bakken next year? And I will leave it there. Thanks.

Yes, Doug, it is going to be a function of financial returns. We said that until oil prices approached $60, it didn't make sense to accelerate volume for its own sake.

But we see with the current improvement in oil prices for next year, that now we are making our plans to increase the rig count some. The exact definition of that -- we'll give guidance as we finalize our plans at the end of the year.

But the core of the core that we have, with the low drilling and completion costs, offer us returns that are competitive with the Permian and the Eagle Ford. So as oil prices have improved, we think it is going to make sense to really take a hard look at increasing our rig count for next year.

Okay. Thanks for taking my questions.

Brian Singer, Goldman Sachs.

Back to Guyana: could you just add a little bit more color on the Payara prospect -- how that compares versus Liza and Skipjack, and if there is any look on whether you would continue to go with one rig in Guyana next year, or whether there would be something greater than that?

Yes. I think regarding the rig count, we are still finalizing all of our plans and budget with the operator. So it is too early to be specific on that.

Again, with the Payara prospect, it is 10 miles northeast of the Liza-1 well. It's in a similar reservoir package that we have seen in Liza, but getting definitive beyond that -- let's just wait and see the results of the well.

Thank you. And then, shifting over to the Bakken, just a couple of follow-up questions on some of the capital allocations there.

Is the decision to move forward or to consider and prepare for accelerating activity there just simply in line with the approaching $60 commentary? Or has there been a more material improvement in returns or a reduction in costs that is more secular that is lowering that breakeven?

And then, very broadly, how do you (technical difficulty) spending of cash flow next year?

Yes. On the Bakken, it is more a function of price and value. But obviously with the improving cost performance that we have, as well as the expansion of our stages to 50 stages from 35 stages -- all of which we think, as prices improve, will offer very attractive returns on a short-cycle basis to our shareholders. And so that is why it is being given serious consideration. And finalization of the drilling rig program we'll give you -- and when we announce our budget for next year in January.

Brian, if I could just add a little more color around what John said, if you look at the well inventory that we have in the Bakken that generates a 15% after-tax or higher return, at $50, that is now over 900 wells. And to put that in context, that has increased by some 40% for that same $50 number last year. So as John said, as well costs have come down and our IP rates have gone up as a result of going to hire stage counts, we are sitting on a very high quality inventory of wells.

Thanks. And you may have said both these points, but did you say or could you say what the well costs and EURs would be associated with the 50-stage Bakken well?

Yes. I think as we said in our opening remarks, the EURs in the fourth quarter will approach 1 million barrels. The EURs in the Middle Bakken in the third quarter were just shy of 900,000 barrels.

And well costs continued to drop for this quarter. They dropped from 4.8 to 4.7, in spite of the fact that we had a couple of higher stage count trials, the 53- and the 57-stage count. So we continue to make those lean manufacturing continuous improvement gains on the wells, in spite of increasing marginally increasing stage counts.

Thank you.

Ryan Todd, Deutsche Bank.

Maybe one quick one on the Bakken, and then a follow-up somewhere else. In the past, you have talked about -- I guess trying to understand the trajectory for 2017 as well -- in the past you have talked about 3 to 4 rigs to maintain production flat in the Bakken. Is that still the case, or have the improvements you have talked about in terms of lowering costs and productivity improvements changed that at all?

Well, I think the three to four rigs is appropriate. I think the only thing we can say is that number has moved closer to three than four, but it is still in between three and four to hold production flat.

Okay. Thanks. And then if we think about activity, you mentioned in your comments the likelihood of reaching FID at Liza in 2017. What are the steps that need to be met between now and then in terms of -- I don't know, it is tough to say at this point -- in terms of additional appraisal wells and activity that needs to be done that we can watch for in terms of hitting FID next year?

No. I think that the biggest thing that needs to be done is really the completion of the feed work, you know, and getting bids back from contractors, all those things. And then, obviously, finalizing your final well designs and locations and all those. So it is just normal project progression to reach the FID point.

And I think the key point there is -- you know, obviously Liza is a world-class resource in excess of 1 billion barrels of oil equivalent. So we think we are at -- beyond the commercial threshold already at current prices.

Great. Thank you. I will leave it there.

Evan Calio, Morgan Stanley.

My first question: on Greg's opening comments, it sounded like the Bakken wells are showing progression in average 30-day IPs as you move to the 50-stage completions. You mentioned the middle Bakken 30-day IPs. What do you see on the Lower Three Forks?

And I note that in the context of your ops report that just filed that had 843 in the quarter for all ops wells. So I'm just trying to square the circle from what we are seeing in the third quarter and what we should see or expect in Q4 for that average 30-day IP.

Yes. Thanks, Evan. Really, the difference in the numbers I quoted and the third-quarter results is the mix of Three Forks wells. So this quarter had a higher proportion of Three Forks wells in it.

Those IPs in the Three Forks this quarter were around about 800 or so, and we also had an operational issue where we had some production curtailment due to some road restrictions that adversely impacted (technical difficulty) brought the average down on the Three Forks.

But that is why we gave you the Middle Bakken numbers. The Middle Bakken numbers were very strong -- less impacted by the production curtailment. So it was that mix it really caused the quarter-on-quarter reduction.

But as we said, in the fourth quarter we are going to see particularly Middle Bakken EURs approaching that 1 million barrel number in the fourth quarter. So we should have a very strong fourth quarter in terms of the EUR on the Bakken.

Right. And do you have an IP estimate for the Q4 total operated? I thought that you were guiding for 900 to 1,000. Is that something that we should expect?

Yes, we just said that that -- again, that should approach that 1 million barrels in the fourth-quarter IP rates.

Great.

Sorry. 1,000 barrels a day, 1 million barrel EURs. Yes.

Yes. Yes. Yes, yes, yes. And my second question is: there appears to be success with higher profit loading in the Bakken amongst your peers. I know you mentioned higher proppant loadings were less effective in your acreage before, yet -- what is it your current proppant load on that standard 50-stage completion? And are you planning to test any higher loads or kind of test that thesis in line with some other operators in the basin? Thanks.

Yes. Evan, we think of the Bakken as really two different areas. So in the core of the core, we believe that sticking with sliding-sleeve completions and increasing that stage count as high as you can practically go delivers the highest return.

Now, the proppant loading we are using in those areas -- again, the core of the core -- is anywhere from 80,000 to 110,000 pounds per stage. And that just really depends on where we are, because we have the data to kind of say it is better to optimize that between 80,000 and 110,000 pounds.

Now, as you move outside the core, we continue to evaluate other designs, which include slick water, plug-and-perf, high proppant volume completions. And what we ultimately decide there -- and we will begin testing some of those techniques -- whatever technique gives us the highest return per DSU, that is the one we are going to select.

And so the reason for the differences are simply because in the core of the core, you are on the flexure of the structure. So you have an awful high amount of natural fracturing. So you just need less of a proppant load. As you get outside the core, there is less of that effect. So that is what drives these different completions designs outside the core.

Great. Maybe one more, if I could. I know the Hawkeye started up in the 3Q; that affected the mix in the quarter. But any color on when that started and ramped up within the quarter, just to get a better view of what the forward run rate might look like on a mix -- a production mix in the Bakken?

Yes. If you look at the mix, again, the individual well GORs are unchanged. And so nothing is going on in the field from a GOR level. What has changed, though, is just the overall mix of production as we bring more wells -- gas and NGLs as we bring more of that into the plant. So previously, flared volumes were gathering additional previously flared volumes and putting those into the plant. So that is what is really going on with our mix.

When in the quarter was the start-up?

Hawkeye is coming in in phases. So it will be completed in 2017, and it really -- I wouldn't say anything in particular with Hawkeye itself. It is -- as Greg said, we are just continuing to hook up more and more of our pads where either they were previously flared and just hooking up to our own infrastructure -- and we even have small amounts that we hook up to other infrastructure as well, other third-party infrastructure.

And then that additional gathering is what is causing the gas rate and the NGL volumes to go up and just causing pure [math] on the percentages of crude. But as Greg said, there is no change of the mix at the well pad.

Great. Appreciate it, guys.

Ed Westlake, Credit Suisse.

Congrats again on Liza. It looks like a large aerial extent and lack of compartmentalization. I guess a couple of quick questions on Liza. What recovery factor have you assumed to come up with this sort of range?

Evan, we are evaluating a whole number of different scenarios on development. So it is too early to talk about that, Ed.

Right. It just seems that -- from the aerial extent, it seems larger, potentially, than even the range that has been given.

Yes. As John said, it is in the upper range -- upper end of the range that was quoted previously.

Okay. Gas content thus far?

Again, let's wait until the development gets sanctioned to be specific on exactly what the mix is. But it has got a very healthy GOR, which means it is going to have a good response from a recovery standpoint.

Okay. And then, switching topic -- and maybe this is more broadly strategic -- you're clearly creating value in Guyana at the pace which offshore exploration takes. You are seeing peers get rewarded from making acquisitions down in the Permian. Maybe just sort of from a strategic standpoint, talk a little bit about how you see the changing landscape and Hess's role in it, given the mix of onshore shale that you have, the excitement that people have about the Permian? And then you also have this offshore element.

Yes. No, thank you. I think the way we look at it is: obviously, we are always looking to optimize the value of our portfolio in the normal course of our business. However, with the robust portfolio of captured growth opportunities that we have, balanced between, I would say, the shorter-cycle Bakken, which is low risk and high return; with returns competitive with the Permian that you just talked about as well as the longer-cycle Guyana that we think will have world-class financial returns as well, acquisitions are low on our priority list.

Okay. Thanks. Very clear.

Paul Cheng, Barclays.

John, I think in the past that you guys have talked about this -- [sustaining] CapEx about $1.5 billion. Is that still the number, or that number has changed?

When we look at -- if you are asking, like, a sustainable CapEx level that we talk about for maintaining flat production, if you look at -- right now we are around, as John mentioned earlier, $2 billion of capital this year. With that we have North Malay Basin and Stampede coming online. And that 35,000 barrels a day comes online in 2018.

So when that comes online, from our production levels that we have, we'll basically be able to keep our production levels flat, maybe some slight growth when you are putting it in and spending that $2 billion. So I would say it is a range, right? You can do this, like, $1.75 to $2.4 billion type range of capital, all depending on your F&D costs that you have in a portfolio for us at our current production levels.

So we are producing 120 million, 130 million barrels a year. So you just use an F&D, and costs in that range to get you that general type of CapEx level.

Now, we can certainly lower that CapEx level and maintain kind of cash flow neutrality, if we wanted to do that. But that would affect your long-term production growth.

Sure. I understand. For next year, what is the remaining spending for Stampede and North Malay going to be?

Sure. So we went into the year basically with about $700 million on both of these projects as a budget: $375 million on North Malay Basin, $325 million on Stampede. The North Malay basin number will come down. So we will update you and give you the more specific number in January. But it is going to come down, because as we said, it is going to start production in the third quarter.

Now, the Stampede number will go up, because we have a second drilling rig coming into the field in January. And then once again, as we put our capital budget together in January, we will update you on the specific numbers.

But the combined is probably still pretty close to about $700 million, then, right? Because once you go down, your North Malay probably offset by the increase in Stampede, I presume?

Yes. You don't want to be specific, but it would be -- you know, it is going to be in that range again, just because it will be an increase in Stampede and a reduction on North Malay Basin. But obviously, once the third quarter starts, we are beginning to get cash flow out of North Malay Basin.

And that is really the key again for us, is this 35,000 barrels a day comes in in 2018. And they go from using $700 million of cash to generating cash. So we are getting that big cash flow inflection point for us coming in 2018 on.

Right. And just curious: in the $1.75 billion to $2.4 billion, whatever is that number that end up just on the 2017 budget, in the past, given -- particularly given that you have no sizable debt maturity until 2027, on a going-forward basis, that if oil price rise and your cash flow from operations thought to be in excess of that level, should we assume you will then sort of want a cash flow neutral model?

So whatever is the increase in the cash flow, exceeding that level will get popped back into the exploration or into the CapEx? Or that is not a totally good assumption?

It goes back to what John Hess had said earlier. There is a balance of how we would use the additional cash flow. So with our portfolio, you know we are oil weighted. So a $1 move in oil prices gives us, on an annual basis, approximately $70 million of additional cash flow. So we are in that position to really -- you know, with the recovery in oil prices, to benefit from it.

So what we will then do is go look at our short-, our medium-term, and our long-term growth options -- that we know we have some very good return opportunities there. But we will balance that with our balance sheet, in making sure that stays strong and providing returns to shareholders.

So it will be a mix. And we will continually look at that mix to optimize it as we move forward.

And two final questions for me. One, Utica: I am surprised that (inaudible) would explain the up sequential, given you are no longer doing anymore wells. Just, Greg, are you start seeing the decline over there? And what kind of decline ratio do we assume?

Paul, on the -- if we look at how we've been able to hold production flat, although we had a drilling break, we brought 14 new wells online in the second quarter and 9 in the first quarter. So you are seeing that, really, carryover of those wells that we completed in the second quarter -- those five wells, sorry.

So just to be clear, again, we brought 14 new wells online in 2016 -- 9 in the first quarter and 5 in the second quarter. So you are seeing some carryover there.

We anticipate the decline will come. And it will probably come -- in the fourth quarter and first quarter of next year is when we will start to see that decline.

If you continue not going to have any rig over there, what kind of decline rate should we assume?

Just take a typical type curve in the Utica, and you can predict pretty easily what that decline is going to be, Paul.

Okay. That's fine. All right. Thank you.

David Heikkinen, Heikkinen Energy.

That was helpful. I don't think you're going to get into these details yet, but the first phase of sanctioning at Liza: how would you describe phase 1? Or is it just too early in your feed studies to even get into the scope and size of the development of upwards of 1.4 billion barrels?

Yes. I think at this point, it is just too early. Obviously, as John said, the reservoir is in the upper end of the range, and we are doing all kinds of development studies to try and figure out the most optimum way to begin the development of the reservoir. So stay tuned. More to come.

And then with North Malay coming online next year, can you talk about the annual impact of amount of capital that you invested, and then the flip of amount of cash flow? I know it is a half-year basis, most likely, but like, what that does to operating costs, or just an absolute cash generation for the Company as that 50% comes online?

Sure. So when it comes online in third quarter, the North Malay Basin field itself will carry very low cash costs. So from a cash cost standpoint it is going to have a positive impact on our overall portfolio.

Now, the price is linked to high sulfur fuel oil there, and it is only on a month lag. So it is going to react to oil prices. And depending on where oil prices are, the amount of cash flow we get will increase or decrease, depending on what is happening with oil prices.

However, we do expect, then, as that is the third quarter coming in -- and then with Stampede coming on in 2018 -- I mean, I think the broader picture is we are utilizing $700 million of cash right now and not getting any cash flow back. In 2018, that flips. So we are getting at least a pickup of $700 million of cash flow from those two projects. And, again, depending on prices, how much excess cash flow we get -- you know, we will see as we get to 2018.

But again, that is why we are always looking and focus on keeping our balance sheet strong through 2017, because in 2018 we get this additional cash flow coming into our portfolio.

And then, just on a very detailed question, your fourth-quarter capitalized interest in G&A -- do you have an expectation for that?

It will be the same, because our capitalized interest right now is related to the Stampede project. So that will actually continue along until Stampede starts up.

Okay. Perfect. Thanks, guys.

Paul Sankey, Wolfe Research.

Firstly, just a hopeful one on Guyana. When could we expect first production based on an FID next year?

I think the best thing to do is refer that to the operator.

Thought that is what I might end up with. I understand. Could you talk a little bit about, firstly, your hedging positioning, if there is anything to add there?

Secondly, as far as I understand it, you are planning to accelerate activity next year but also maintain a strong balance sheet. And I assume that would mean spending within cash flows. Are you therefore assuming higher oil prices next year? Or how do I kind of square that circle?

Thanks.

Yes. The prices we are assuming -- and we would give further definition on that when we announce our budget next year in January -- is prices in the current range. Priority is going to keep the balance sheet strong, and our activity levels will reflect keeping that balance sheet strong. So further guidance and specifics we will give you in January.

Anything on hedging, John?

So right now, we do not have any hedges outstanding, and we continue to look at hedges on a regular basis. Then we will assess whether to add them, as we have done in the past, basically as insurance to ensure funding of our capital projects.

So then, as John mentioned, as we look in 2017 and seeing where prices are, if we begin to put more capital back to work or add more drilling rigs in the Bakken, we will be considering adding hedging at that point as insurance.

Clear. Thank you.

Jeff Campbell, Tuohy Brothers.

My first question was with regard to the Bakken and increase to 50 stages in the standard completion design. I was just wondering: do you anticipate any alteration of your current well spacing assumptions on pads as a result of the more intensive completions?

No, we don't. Based on our current reservoir studies with this completion design, we think that is the optimum. Now, having said that, we have done a few very close -- even closer-spaced pilots, and we are waiting on the results of those. So it is too early to speculate one way or the other.

But right now, we believe that nine and eight configuration with the 500-foot well spacing with 50-stage fracs appears to be the optimum. As we said, though, we are going to continue to push that stage count higher if we can. And we just got a successful 60-stage trial in the ground. So we are excited about the possibilities there.

Okay. Just to follow that up to make sure I understood that clearly: you have some spacing pilots that are tighter than 500 feet, with 50 stages being tested, and we just don't have the results yet. Is that correct?

No. Those are actually lower stage count, but we are monitoring those wells closely to see, you know, can we see breakthrough? So far, we haven't, but we need a lot more data before we can be definitive.

Okay. That was helpful. I was just wondering, can you update on the Gulf of Mexico production outlook over the next several quarters? Specifically, are the valve problems behind you? And what is the production recovery arc?

Yes. So as we mentioned in our remarks, there is kind of two events that are going happen. The first thing is on Conger. We will get that defective valve replaced, and it will come -- that well will come back online in the first-quarter 2017.

As we move to Tubular Bells, there is two events that are going on there -- well, actually three. First of all, we are going to commence water injection this quarter. Secondly, we have a fifth producer that will come online in the first quarter of 2017. And then, finally, we will get that third defective valve replaced in the fourth quarter, and the well will come online in the first quarter.

And so that is how it kind of lays out on Conger and the T Bells. The rest are pretty much just in a run-and-maintain mode -- run for cash.

Okay. And if I could ask a last one real quick, I just wondered if you could add a little color on Skipjack. Was it simply a noncommercial well, or did it fail to find any kind of hydrocarbons -- I mean, was there no system there? And just how the Skipjack result has an effect, if any, on any other potential exploration targets in the area.

Okay. So I think, as the operator said, the Skipjack well did not find commercial quantities of hydrocarbons, but did fine -- you know, the same excellent quality reservoir that we have seen in the Liza wells. So how we think about this in the context of the whole block is, again, this is a giant block. It is 1,150 Gulf of Mexico blocks.

We are in of the very early stages of the exploration program, and we continue to see numerous additional prospects and play types on the block. And we haven't even processed all the seismic yet. So we still remain very excited about the potential of the block in spite of Skipjack.

Okay, great. Well, that was helpful. Thanks very much for answering my questions.

John Herrlin, Societe Generale.

Most things have been asked. In the third quarter, you had a $16 million dry hole cost. Was that all Skipjack?

Yes, it was, John.

Okay. Thanks, John. Regarding Payara, or however you want to pronounce it, your next exploration well in Guyana -- is it a similar structure, Greg, morphologically? Or is there anything you can talk about for that?

No. Very similar stratigraphic trap and same kind of reservoir sequence as the other Liza wells.

Great. Thank you.

Pavel Molchanov, Raymond James.

No one has asked yet about the MLP. The last time you updated the S-1 was, I believe, last December. But you're obviously talking about accelerating Bakken activity next year. As that materializes, will you also kind of accelerate, perhaps, the process towards taking the MLP public?

So just at a high level, the midstream business itself -- it's executing well, as you can see from our numbers. The Hawkeye project we are working to completion, and that will come online in 2017. Market conditions, obviously, are getting better. And as you mentioned -- and John has mentioned earlier -- that we are making our initial preparations on increasing our drilling activity in the Bakken. And I think when you put all those together and we start our increasing -- our drilling there in the Bakken, it does fit nicely into a timeline, then, for the MLP IPO.

Okay. And then just kind of conceptually, if and when Hess Midstream ends up becoming a public company, will you limit it to Bakken assets exclusively? Or would you consider adding or broadening its asset base towards other aspects of your domestic midstream portfolio outside the Bakken?

Yes. We will obviously talk about this as it gets further in the process. But there is no restriction for the midstream to just be in our North Dakota business.

Okay. Clear enough. Appreciate it.

Arun Jayaram, JPMorgan.

Just a couple real quick ones. Assuming the upper end of that resource range at Liza, guys, how many phases would that potentially include? You talked about potentially sanctioning phase 1 in 2017, but how many potential phases could that include?

I would direct those questions to ExxonMobil, the operator.

Fair enough. Fair enough. And my only other question: Malay comes online in the third quarter. Could you give us a sense of how the ramp could look like in terms of getting to full production there?

Yes. So I think, again, it will reach plateau at 165 million cubic feet a day. And the fact that we are pre-drilling most of the producers -- that should be a pretty steady ramp.

Okay. When -- at what quarter would you anticipate getting to full production? Is it fourth quarter, or first quarter of 2018?

We will begin ramping in the third quarter, so probably fourth quarter.

Fourth quarter. Okay. Thanks a lot, guys.

Guy Baber, Simmons.

The E&P CapEx has been consistently coming in below guidance pretty much every quarter. Can you just discuss the drivers there? To what extent is that activity-driven, perhaps offshore versus efficiency capture, deflation capture? Just curious what you are seeing with those savings. And then I have one follow-up.

Sure. Kind of, Guy, day in and day out right now we are focused on reducing costs, both on an operating basis as well as capital. So the biggest driver of the reduction in capital -- because we had already had the activity reductions basically budgeted in, or -- especially when we updated the forecast guidance. So it really has been efficiencies here, and just continuing to look at better ways of doing things and reducing costs from that standpoint.

Okay, great. And then the international offshore CapEx -- it looks like you basically cut off spending to a good portion of your base international offshore assets. Is that something you are comfortable continuing to do through 2017? Or do those base assets need to attract a bit more capital? And is there anything new to share at Valhall, South Arne, for example?

Right. So as we have talked about, we across our portfolio have very good return opportunities, both onshore and offshore. But the way we are thinking about allocating capital here as the prices come back -- and we have mentioned it -- is we are now initially preparing for increasing capital to the Bakken. So that is going to have -- our first call on capital will be going to the Bakken.

Then again, now, as prices continue to move -- and as you know, $1 move for us is $70 million of annual cash flow -- we will begin to look across the portfolio. And there are opportunities across our offshore portfolio that we could increase capital to. So it will be something that we will be looking at and balancing it with where our balance sheet is and commodity prices are and returns to shareholders, but there is very good returns across our portfolio.

And I think the only thing I would add there is there were logical drilling breaks, both in EG and South Arne, Associated with processing additional 4-D seismic and ocean-bottom seismic. So those were logical, technical drilling breaks. And we are in the process of evaluating all that data.

Great. Thank you, guys.

Doug Leggate, Bank of America Merrill Lynch.

Sorry for lining up again, but I wanted to dig into the fourth-quarter production guidance, because when I was asking my question, the slides were not yet posted. Can you just walk us through what is driving the drop sequentially oil versus gas, primed versus unprimed, versus declines? Because the Bakken seems to be relatively stable. I would appreciate that. Thanks.

Sure. The so if you are starting with our third quarter, the 314,000 barrels per day, we are going to get an increase about 11,000 barrels a day combined from JDA and South Arne. As Greg had mentioned in his comments earlier, JDA will get back above 30,000 barrels a day, because the booster compression tie-in work that we had in the second quarter -- and South Arne did have a turnaround as well. So we are getting a pickup there.

That increase, though, is being offset and slightly even more -- there is going to be reduction of about 12,000 barrels a day as it relates to, as we talked about, Utica. Utica is going to be -- start declining. We are not drilling or bringing any wells online there.

The Bakken, as you mentioned, it is going to come off the 107 and begin to decline with the two rigs. And in EG, we do have a bit of our normal entitlement change that we have in the fourth quarter as you get through the year of your cost recovery.

So combined, Utica, EG, and Bakken will be down about 12,000 barrels a day. Then you have the ones and twos across the portfolio, again, where we are not drilling. And that comes to approximately 8,000 barrels a day there. Just things in the Gulf of Mexico, as Greg mentioned. So that is where we get to this approximate of about 305,000 barrels a day in the fourth quarter.

So, John, just to be clear, the Utica is obviously mainly gas. So what is the Utica contribution to that? It makes a difference in your cash margins, obviously.

About -- I would say about 5,000 barrels a day will be in the Utica. It will start declining here significantly with no activity happening in the Utica.

All right. Helpful. Thanks, fellas.

That is all the time we have for questions today. Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Everyone have a great day.