赫斯 (HES) 2018 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Second Quarter 2018 Hess Corporation Conference Call. My name is James, 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, James. Good morning, everyone, and thank you for participating in our second 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, which will be provided on our website.

Now as usual, with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer.

I'll now turn the call over to John Hess.

Thank you, Jay. Welcome to our second quarter conference call. I will provide a strategy update, Greg Hill will then discuss our operating performance, and John Rielly will review our financial results. We continue to make significant progress during the quarter in executing our strategy, to grow our resource base in a capital disciplined manner, to move down the cost curve so we are resilient in a low priced oil -- low oil price environment and be cash generative at a $50 per barrel Brent oil price post-2020.

Consistent with this strategy, in June we announced the sale of our joint venture interests in the Utica for a net cash consideration of approximately $400 million as part of our continued efforts to high grade and focus our portfolio by divesting lower-return noncore assets.

In addition to the $3.4 billion from our 2017 asset sales, these proceeds are being used to invest in our highest return assets: Guyana, which is one of the industry's largest oil discoveries in more than a decade, and the Bakken our largest operated asset where we have more than 500,000 net acres in the core of the play, as well as to fund our previously announced $1.5 billion share repurchase program and reduce debt by $500 million.

During the quarter, we announced that we will retain our interest in Denmark, where we hold a 61.5% interest in the South Arne field and are the operator. The offers received in a previously announced sale process did not meet our value expectations.

Key to our strategy is our position in Guyana. The 6.6 million acres Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, is a massive world-class resource that is uniquely advantaged by its scale, reservoir quality, cost, rapid cash paybacks and superior financial returns.

As such, our first priority is to maintain a strong balance sheet and our investment grade credit rating in order to fund one of the most attractive oil investment opportunities in the world today.

Earlier this week, we increased the estimate of gross discovered recoverable resources for the Stabroek Block to more than 4 billion barrels of oil equivalent, up 25% from the previous estimate of 3.2 billion barrels of oil equivalent. The increase follows completion of testing at the Liza-5 appraisal well, discoveries at Ranger and Pecora and the incorporation of results from the recent Longtail discovery into the Turbot area evolution.

The Liza Phase 1 development that was sanctioned last June is progressing rapidly, with first production of gross 120,000 barrels of oil per day expected by early 2020.

Phase 2 of the Liza development, which is targeted for sanction by the end of this year, will use a second FPSO with gross production capacity of approximately 220,000 barrels of oil per day, start-up for Phase 2 is expected by mid-2022.

The Liza-5 well, which successfully tested the northern portion of the Liza Field along with the giant Payara field will support a third phase of development in Guyana. Planning is underway for this third phase, which is targeted to be sanctioned in 2019 and will use an FPSO vessel designed to produce approximately 180,000 barrels of oil per day with first production as early as 2023.

The Longtail discovery established the Turbot-Longtail area as a potential development hub for recovery of more than 500 million barrels of oil equivalent. Additional prospects to be drilled in this area could increase this estimate. The total discoveries on the Stabroek Block to date have established the potential for up to 5 FPSOs producing over 750,000 barrels of oil per day by 2025.

There is potential for additional development phases from significant undrilled targets and plans for rapid exploration and appraisal drilling including at the Ranger discovery. We continue to see multibillion barrels of additional exploration potential on the Stabroek Block.

In April, we extended our acreage position in the prolific Guyana-Suriname Basin by acquiring a 15% participating interest in the Kaieteur Block, which is adjacent to the Stabroek Block. The Kaieteur Block is approximately 3.33 million acres or roughly the size of 580 deepwater blocks in the Gulf of Mexico.

Also, key to our strategy is the Bakken, where we have a premier position and a robust inventory of high-return drilling locations. We added a fifth rig in June and plan to add a sixth rig early in the fourth quarter, which is expected to generate capital efficient production growth from an average of 114,000 barrels of oil equivalent per day in the second quarter to 175,000 barrels of oil equivalent per day by 2021, along with a meaningful increase in free cash flow generation over this period.

During the quarter, we continued evaluating new completion techniques and initiated a comprehensive study to further maximize the value of this important asset. We plan to provide an update on these initiatives later in the year.

Second quarter net production in the Bakken averaged 114,000 barrels of oil equivalent per day. For the full year 2018, we continue to forecast that Bakken production will average between 115,000 and 120,000 barrels of oil equivalent per day.

Now turning to our financial results. In the second quarter of 2018, we posted a net loss of $130 million or $0.48 per share, down from a net loss of $449 million or $1.46 per share in the year-ago quarter.

Compared to 2017, our improved second quarter financial results primarily reflect higher realized crude oil selling prices and lower operating costs and DD&A expense, partially offset by lower production volumes primarily due to asset sales.

Second quarter production was above the high end of our guidance range, averaging 247,000 barrels of oil equivalent per day, excluding Libya, driven by strong performance across our portfolio.

For full year 2018, we reaffirm our net production guidance of 245,000 to 255,000 barrels of oil equivalent per day excluding Libya. This guidance includes the loss of production from the sale of our Utica joint venture interests and the benefit from the earlier than planned return of production from the Conger Field in the deepwater Gulf of Mexico.

In summary, we continue to make significant progress in executing our strategy, and positioning our company to deliver long

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and superior financial returns to our shareholders.

I will now turn the call over to Greg for an operational update.

Thanks, John. I'd like to provide an update on our operational performance for the quarter, as we continue to execute our strategy.

In the second quarter, production averaged 240,000 (sic) [247,000] net barrels of oil equivalent per day excluding Libya. This was above the top end of our guidance range of 235,000 to 245,000 net barrels of oil equivalent per day and reflected strong performance across our portfolio.

In the Bakken, we delivered another strong quarter despite some curtailments related to heavy rains in June that caused a significant number of road closures. Second quarter Bakken production averaged 114,000 net barrels of oil equivalent per day.

In the second quarter, we drilled 28 wells and brought 27 wells online. For the full year 2018, we still expect to drill approximately 120 wells and bring 95 wells online. In line with our previous guidance, we have added a fifth rig in the Bakken and plan on adding a sixth rig early in the fourth quarter.

We also added a third frac crew early in the third quarter. We continue to see encouraging initial results from our pilot of limited entry plug and perf completions. Of the 95 growth operated wells we expect to bring online this year, approximately 25 are planned to be plug and perf. In late June, we announced an agreement to sell our JV interests in the Utica Shale play to Ascent Resources. Production from this asset was expected to average 14,000 net barrels of oil equivalent per day over 2018, and we expect this transaction to close by the end of the third quarter.

In mid-July, Shell brought its Enchilada facility in the deepwater Gulf of Mexico back online, which allowed us to restart production from the Conger Field. Production from Conger is in the process of ramping back up to its pre-shut-in rate of approximately 15,000 net barrels of oil equivalent per day.

Taking these factors into account, we forecast third quarter production to increase to between 250,000 and 260,000 net barrels of oil equivalent per day excluding Libya.

We are maintaining our full year 2018 production guidance range of 245,000 to 255,000 net barrels of oil equivalent per day as the earlier than expected return to production of the Conger Field is expected to offset the production associated with the sale of our Utica joint venture assets.

Both in the third quarter and for the full year 2018, we forecast that Bakken production will average between 115,000 and 120,000 net barrels of oil equivalent per day. We continue to forecast steady Bakken production growth to approximately 175,000 net barrels of oil equivalent per day by 2021 assuming a sixth rig program.

Now turning to the offshore. In the deepwater Gulf of Mexico, production averaged 47,000 net barrels of oil equivalent per day for the quarter in line with guidance, and again, reflecting approximately 15,000 net barrels of oil equivalent per day of production that was shut-in at our Conger Field over the quarter.

For the third quarter, we forecast Gulf of Mexico production to average approximately 60,000 net barrels of oil equivalent per day. By the fourth quarter, with all the Enchilada impact fields back online and the continued ramp-up at Stampede, we forecast Gulf of Mexico production to average approximately 65,000 net barrels of oil equivalent per day.

Moving to the Gulf of Thailand. Production from our Asian assets averaged 63,000 net barrels of oil equivalent per day during the second quarter. At the joint development area in which Hess has a 50% interest, production averaged 37,000 net barrels of oil equivalent per day in the second quarter.

Production is forecast to average approximately 36,000 net barrels of oil equivalent per day over 2018. At the North Malay Basin, where Hess holds a 50% interest and is operator, production averaged 26,000 net barrels of oil equivalent per day in the second quarter and is forecast to average approximately 26,000 net barrels of oil equivalent per day over the year.

Now turning to Guyana. We announced on Monday the gross discoverable recoverable resources at the Stabroek Block, in which Hess holds a 30% interest, are now estimated to exceed 4 billion barrels of oil equivalent, which is up 25% from the previous estimate of more than 3.2 billion barrels of oil equivalent.

In addition, total discoveries to date have established the potential for up to 5 floating production, storage and offloading vessels, or FPSOs, to produce over 750,000 gross barrels of oil per day by 2025.

As we've said before, Guyana continues to get bigger and better. In late June, the operator ExxonMobil announced an eighth oil discovery at Longtail-1, which is located in the Southeast of the $6.6 million acres Stabroek Block, approximately, 5 miles west of the Turbot-1 discovery. The well was safety drilled to 18,057 feet and 6,365 feet of water in 26 days. It encountered approximately 256 feet of high-quality oil-bearing sandstone reservoir. With the success of Longtail, we believe the combined gross recoverable resources in the Turbot-Longtail area exceed 500 million barrels of oil equivalent. And we continue to see several additional prospects in this area that could potentially take this estimate even higher.

Post-Longtail, the operator decided to perform routine maintenance on the Stena Carron. This provided an opportunity to complete the riser-less top hold section of Ranger 2, before proceeding to the Hammerhead-1 exploration well in the coming days. Hammerhead is located 9 miles Southwest in -- of the Liza discovery.

In the coming days, the drillship will move to the Hammerhead-1 exploration well, and following completion of the well operations on Hammerhead, the current plan is to return to Ranger. The Liza Phase 1 development sanctioned in June 2017 continues to make rapid progress. Development drilling began in May, laying the foundation for production start-up in early 2020.

Liza Phase 1 will consist of 17 wells and an FPSO designed to produce up to 120,000 gross barrels of oil per day. Development drilling and construction of the FPSO and subsea equipment is progressing on schedule.

Liza Phase 2 is on track for sanction by year-end. The Phase 2 development will utilize an FPSO with a gross production capacity of 220,000 barrels of oil per day with first oil expected by mid-2022.

Given the ongoing exploration success on the Stabroek Block and its significant remaining potential, the operator now plans to add a third drillship by the fourth quarter, which will be dedicated to exploring and appraising the numerous high-value prospects on the block.

On the recently acquired 3.3 million acre Kaieteur Block offshore Guyana, in which Hess holds a 15% participating interest, the 2018 work program will include processing and interpretation of 3D seismic data and evaluation of a future drilling program. In neighboring Surinam, Hess has exposure to an additional 4.4 million acres through our 33% interest in both Block 42 and 59. We see these blocks as a potential play extension from the Stabroek Block in Guyana with similar play types and trap styles. The operator, Kosmos, plans to spud a first exploration well on a prospect called Pontoenoe in Block 42 by the end of the third quarter.

In Canada, offshore Nova Scotia, the operator, BP, has spud the Aspy play test well, targeting a large subsalt structure, analogous to those found in the Gulf of Mexico. BP and Hess, each hold a 50% working interest in exploration licenses that cover approximately 3.5 million acres, equivalent to some 600 deepwater Gulf of Mexico blocks. We anticipate results by the end of the third quarter.

In closing, we have once again demonstrated excellent execution and delivery across our portfolio. The Bakken is on a strong capital efficient growth trajectory, and this, combined with our sizable interest in the world-class Guyana-Suriname Basin, has positioned us for more than a decade of visible cash flow and production growth and improving returns and cost metrics.

I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the second quarter of 2018 to the first quarter of 2018. We incurred a net loss of $130 million in the second quarter of 2018 compared with a net loss of $106 million in the first quarter of 2018.

Our adjusted net loss, which excludes items affecting comparability of earnings between periods was $56 million in the second quarter of '18, down from $72 million in the previous quarter.

Turning to Exploration and Production. On an adjusted basis, E&P had net income of $21 million in the second quarter of 2018 compared to net income of $12 million in the first quarter of 2018.

The changes in the after-tax components of adjusted E&P results between the second quarter and first quarter of 2018 were as follows: Higher realized selling prices increased earnings by $46 million; higher sales volumes increased earnings by $47 million; higher exploration expense reduced earnings by $25 million; higher DD&A expense reduced earnings by $23 million; higher cash costs reduced earnings by $14 million; higher mainstream tariffs reduced earnings by $12 million. All other items reduced earnings by $10 million for an overall increase in second quarter earnings of $9 million.

Turning to Midstream. The Midstream segment had net income of $30 million in the second quarter of 2018 compared to net income of $28 million in the first quarter of 2018. Midstream EBITDA, before the noncontrolling interest, amounted to $126 million in the second quarter compared to $123 million in the previous quarter.

Turning to corporate, after-tax corporate and interest expenses were $191 million in the second quarter of 2018 compared to $109 million in the first quarter of 2018. After-tax adjusted corporate and interest expenses were $107 million in the second quarter of 2018 compared to $112 million in the previous quarter.

Turning to our financial position. In April, we entered into a $500 million accelerated share repurchase agreement, which was completed in June bringing total share repurchases under our previously announced $1.5 billion repurchase program to $1 billion. Total shares purchased to date amount to 19.2 million shares at an average price of $52.18 per share.

We plan to purchase the remaining $500 million of shares during the second half of 2018 and are targeting $250 million of purchases in the third quarter and $250 million in the fourth quarter.

In the second quarter, we also purchased approximately $110 million of our public notes, increasing total debt retire to $500 million. Excluding Midstream, cash and cash equivalents were $2.5 billion, total liquidity was $6.8 billion including available committed credit facilities and debt was $5.5 billion at June 30.

In the third quarter, we completed the purchase of WTI put option contracts that set a floor price of $60 per barrel on a notional 35,000 barrels of oil per day during calendar year 2019. Proceeds from the recently announced sale of our Utica joint venture interests are expected to be received in the third quarter.

Turning to guidance. First for E&P, in the second quarter, our E&P cash costs were $13.37 per barrel of oil equivalent including Libya, and $14.03 per barrel of oil equivalent excluding Libya, which beat guidance on strong production and lower cost.

We project cash cost for E&P operations excluding Libya in the third quarter to be in the range of $13 to $14 per barrel of oil equivalent, while full year 2000 -- cash cost guidance remains unchanged at $13 to $14 per barrel of oil equivalent.

DD&A expense in the second quarter was $16.85 per barrel of oil equivalent including Libya, and $17.92 per barrel of oil equivalent excluding Libya, which was in line with guidance.

DD&A expense, excluding Libya, is forecast to be in the range of $18 to $19 per barrel of oil equivalent in the third quarter of 2018, and full year DD&A expense guidance of $18 to $19 per barrel of oil equivalent is unchanged. This results in projected total E&P unit operating cost excluding Libya of $31 to $33 per barrel of oil equivalent for the third quarter and for the full year of 2018.

Exploration expenses, excluding dry hole cost, are expected to be in the range of $50 million to $60 million in the third quarter with full year guidance remaining unchanged at $190 million to $210 million. The midstream tariff is projected to be approximately $165 million for the third quarter with full year guidance forecast to be in the range of $635 million to $650 million.

The E&P effective tax rate, excluding Libya, is expected to be an expense in the range of 0 to 4% for the third quarter. The full year effective tax rate is expected to be a benefit in the range of 16% to 20%, which is updated from the previous guidance of a benefit in the range of 0 to 4%.

For the full year 2018, our E&P capital and exploratory expenditures guidance remains unchanged at $2.1 billion. Our 2018 crude oil hedge positions remain unchanged. We have $50 WTI put option contracts on a notional 115,000 barrels per day production for the remainder of the year. We expect the noncash amortization of premiums on our crude oil hedges will reduce our financial results by approximately $50 million per quarter for the remainder of 2018.

For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $30 million in the third quarter with the full year guidance of approximately $115 million, which is above the midpoint of our previous guidance.

Turning to corporate. For the third quarter of 2018, corporate expenses are estimated to be in the range of $25 million to $30 million, and the full year guidance is estimated to be in the range of $100 million to $110 million, which is down from the previous guidance in the range of $105 million $115 million. Interest expenses are estimated to be approximately $85 million for the third quarter, and the full year guidance is estimated to be in the range of $340 million to $345 million, which is also down from the previous guidance in the range of $345 million to $355 million.

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

(Operator Instructions) Our first question comes from the line of Bob Morris with Citi.

Congratulations, John, on the continued success in Guyana and the reserve update earlier this week.

Greg, just some quick questions on the Bakken Shale. I know that 40 of the 95 completions this year is supposed to be in the higher productive Keene area. How many of those 40 wells in the Keene area have you done in the first half of the year, and then also of the 25 plug and perf wells, how many of those were completed in the first half of the year?

Well, let me -- thanks, Bob. And before I get started, I do want to correct something in my remarks. Our second quarter production was 247,000 net barrels of oil equivalent per day excluding Libya. I believe I said 240,000, which was obviously incorrect. Let me start with the plug and perf wells first. So we expect to do 40 of those this year, drill and complete but only have 25 of those online. And as you said, we do expect to have 40 Keene wells online, 7 of those will be plug and perf by the end of the year that will be drilled and completed.

Regarding how many we've got done in the first part of the year, I think we have about 12 done in the Keene area in the first half of the year, so the remainder will come in the second half of the year. Now what I should say is those Keene wells are doing extremely well. So there outperforming their type curves at least on the wells that we've done so far by some 25%. So the results here have been very good, also on the Stony Creek area, the wells that we have done there, again, reminding everyone we're going to do 25 of those this year in Stony Creek. Those were outperforming their type curves by around 40%. So Stony Creek and Keene are really the top 2 areas in this year's drilling program and then our East Nesson South and our Capa wells are performing about at expectation on the type curve. So Keene and Stony Creek are the ones to watch.

Our next question comes from Roger Read with Wells Fargo.

If we could, maybe just hit Guyana a little bit here. So if we look at the guidance of 750,000 or more barrels by 2025 and the expectations of barrels out of the first 3 FPSOs, we'd be implying kind of Liza-1 sized FPOs -- FPSOs at the minimum in terms of Phases 4 and 5. And is that -- should we think of them though as upside to maybe where Liza-2 is, when we're trying to frame the overall impact of the development?

Okay, thanks for that, Roger. A couple of comments here. I think first of all, in our messaging, you note that we said that we see the potential up to 5 FPSOs produce over 750,000 barrels a day. So that's 1 caveat. I think the other one -- the other thing is that the ultimate size and timing of those last 2 vessels very much in the scoping phase, and it's going to be a function of a lot further exploration and appraisal drilling as well as detailed engineering work and again, these are massive reservoirs with very large areal extent and multiple horizons. So those are directional numbers. Let's get that appraisal and exploration drilling done and then we can be much more definitive. But again, we see it as over 750,000 barrels a day.

And one more clarification, as we think about Guyana, I know Phase 1 here is in oil-only situation. How are we thinking about the gas and the other liquids, as you look at these future phases? Any plans to bring the gas to shore, or are we thinking pretty much a 100% oil in terms of production?

Well, I think the grand majority of the gas will be reinjected in the reservoir. There is a small project being discussed with the government of Guyana to bring a small amount of gas onshore for an onshore power plant. Other than that, all the gas right now is anticipated to be reinjected in the reservoir because, particularly, in the Liza complex the gas is miscible. So there will be recovery uplift as a result of putting that gas in the reservoir.

Our next question comes from Doug Leggate of Bank of America Merrill Lynch.

Guys, maybe I could kick off with a follow-up on Guyana just very quickly. And I think, Roger kind of hit the point about the 750,000 to FPSO math doesn't really seem to make any sense. But can you walk us through what the exploration plan is for the second half of the year? Looks like Ranger is, obviously, been brought forward in the plan? But with the third rig coming in, what should we think about what you're trying of identify for the second half, and what I'm really trying to get out is, are we getting to a point where we're going to start to see parallel developments on some of these things as you move into the '23, '24, '25 time line?

Let me answer your second question first, Doug. I think regarding in parallel, we are in absolute agreement and alignment with the operator that the way to approach this development is in a phased manner. So that's currently the thinking right now, and we're absolutely in support of that. Regarding the exploration drilling program for the remainder of the year, all I can say now is that next we go to Hammerhead. We just are in the final phase of drilling the top -- drilling the top section on the Ranger 2. We'll go to Hammerhead and most likely, we'll go back to Ranger. The sequence for the fourth rig, we're still working out with the operator but obviously, we've got a lot of stuff to do and we've got a lot of stuff to do in kind of the Turbot-Longtail area, there are some things that we'd like to drill there as well, potentially a good resource increase there. So the exact order, we're still working out. But there'll be more and more in the Turbot-Longtail area.

Just to be clear Greg, it's the third rig or the fourth rig?

No, it's the third rate, yes.

Third, okay. So my follow-up is if I could take you back to the Bakken for a second and I appreciate the color on the Keene and the Stony Creek wells doing better. But can you kind of walk us through, have you completed any plug and perf wells yet? Is that contributing to the better performance? Or is there something else going on with the better performance? And in your answer, Greg, I wonder if you could take one other comment, I think John had made in a prior third-party conference that you're starting to look at potentially putting ESPs down some of these wells as well. So I guess I'm really just trying to get a prognosis for what was embedded in your guidance? Because clearly the better type curves wasn't embedded in your guidance, so what are you assuming in your guidance, and how should we think about the risks for that guide and per well performance as we move into 2019?

Yes. So Doug, the grand majority of our guidance reflects the sliding sleeve wells. And the reason for that is because we only have 3 of the plug and perf wells on right now. Now they're doing better-than-expected but it's early days. So we didn't want to build a whole bunch of uplift in the guidance at this point, until we got more data on those plug and perf wells. So far so good but we wanted to have confidence in the data before we did that. Now on ESPs, we've been evaluating the use of ESPs as well as some other forms of lift, as you know some operators up there doing gas lift as well, particularly, in the areas that have higher fluid rates and require the use of additional liquid handling. And in particular, the plug and perfs, if they continue to perform and have high fluid rates, obviously, that's something we're looking at. But at the end of the day, the decision on which forms of artificial lift we're going to use is ultimately going to be driven by economics, not volume. So it will be an economic decision as to whether -- what we do on the lift side.

Sorry to press you on this, Greg. Just to be clear, the Keene wells, the Stony Creek wells are doing 25% and 40% better than your type curve and they're the majority, I think, of the completions in the second half of the year. And that's not in your guidance, so why haven't you raised the guidance in the Bakken?

No, we've raised some of the guidance on those Keene wells. But only on the sliding sleeve completions, Doug. So I wouldn't -- watch this space as we get more data it will reflect itself in the production numbers but we have not raised guidance on the Bakken until we get more data from the plug and perf wells.

Yes, I think the important thing here, Doug, and obviously, you're on to something, which is with the improved completion techniques, we're doing a study to really optimize our investment in the Bakken going forward, and we'll be ready to share the results of that study between now and the end of the year, where we hopefully can give more specificity and clarity on to what our future production rates might be in the Bakken. So let's get a couple of more wells under our belt and as we do, incorporate that into our investment program and then the output of that program, obviously, focused on returns, as Greg was saying, I think we'll be able to provide more clarity on the question you're asking by the end of the year.

Our next question comes from Devin McDermott with Morgan Stanley.

I had first a follow up on Guyana as it relates to the addition of the third drillship later this year. I was just hoping to better understand the CapEx impact of that. Now I noticed that overall CapEx guidance for the year is unchanged, so are there some offsetting efficiencies you're seeing elsewhere in the business that are allowing you to keep CapEx flat with that addition of the drillship?

Yes. I mean, if you look where our run rate is right now, so for the first half of the year we came in at $909 million on our capital spend. And the reason, if we look at that and say why isn't the guidance coming down, but it's because of these type of things that you've mentioned. So what do we have in the second half of the year? So Guyana, we do have the third drillship, as you've mentioned, coming in, it's going to come in the fourth quarter. So that will be an impact. What we also have is a little more Phase 2 spend, as we're getting coming up on sanction than we had in the first half of the year so we'll have Phase 1 in Guyana and more Phase 2 spend in the second half of the year. And then the other component that we have that is going to raise capital in the second half of the year is the Bakken, right? So we have the fifth rig coming in now and the sixth rig coming in later in the year. And yes, so far our efficiencies have been good with our program but as we see it right now, we're reaffirming that guidance at $2.1 billion.

Excellent, that's helpful color. And then thinking just longer term on the overall cash flow profile of the company. You've talked about being cash flow positive post-2020. And I believe since then, there's been upside to the Guyana resource estimates as well as potential for additional phases of development. Can you just talk about the latest thoughts there on cash generation post-2020 and also the ability to fund within cash flow these incremental developments at Guyana longer term?

Sure. The best thing that we can do for our portfolio and matching up with our strategy on generating free cash flow at a $50 environment is to add more oil resources in Guyana. It's just a fantastic asset. Obviously, you've heard all the attributes on it. But combined with the great reservoir characteristic, it just gives superior financial returns and has a very low breakeven price as we talked about at $35. So what happens is, you add Phase 4, Phase 5, what we've done for the portfolio is it continues to lower our breakeven price as we go forward, and can generate more cash flow in a low-price environment or in a higher-price environment. Now just to get to your specific question on timing, on free cash flow. Let me tell you what we know right now, and as Greg mentioned earlier, what we really don't have good information on. So starting with Phase 1, obviously, we've got really good information on that, what the capital, what the timing is, Phase 2 fees is progressing rapidly, we expect to sanction that before the end of the year and achieve first oil by mid-2022. So we have good information on that. Phase 3 has now been sized, expected to be sanctioned during 2019, so we have a decent estimate on that. So with those 3 FPSOs in place, we do see that we can generate free cash flow at $50 post-2020 with those 3 FPSOs. Now Phases 4 and 5 still require, Greg mentioned, we've got additional exploration and appraisal drilling in order to size the projects and optimize the development plans. So at this point, I really do not have a good estimate as the timing, how much of that capital could be in 2021, and what exactly the amount will be for future phases. It will be further out in the future, but what we can say about this funding is the way we've prepositioned the portfolio with our asset sales that the funding is very manageable and that Guyana itself is expected to become free cash flow positive really once Phase 2 starts producing. So as I mentioned, it would be in 2022. So again, for us Guyana, it's right in our strategy, driving our costs down and driving our breakeven for the portfolio, so that we can really drive production growth and free cash flow.

Our next question comes from Arun Jayaram with JPMorgan.

Yes. The first question is for Greg. Greg, as you test the plug and perf completions in the Bakken, can you remind us of how you're doing in the well spacing within the Middle Bakken and the Three Forks for the plug and perf? Because I believe, under sliding sleeve, you're doing 8 or 9 wells in the Middle Bakken per DSU, and maybe 7 or 8 in the Three Forks. I just wanted to see if you could give us a sense of what the spacing would look like for plug and perf.

Yes. Again, it's early days. So what we're doing now is we are using the same well spacing that we're using with sliding sleeve because we want to compare the 2. So we want to have a valid comparison by keeping the well spacing the same. Now as we mentioned, as part of the Bakken study, we're going to take our data, relevant industry data and one of the outputs for the Bakken study will help us confirm the appropriate well spacing completion type and proppant loading for each area of the basin. So that's ultimately what we're trying to determine. And then the penultimate question is, what's the way to maximize value from those DSUs in the Bakken? So that's what we're aiming for with the Bakken study and through our own experimentation.

And just can you remind us what the current spacing is under sliding sleeve, just to get the baseline?

Yes, it's on the 9 and 8. Nine and 8 duration.

Nine and 8? Okay. Okay, great. And Greg, just in terms of the 3Q Bakken guide of 115,000 to 120,000, you did 114,000 in this quarter with some weather impacts. Do you view that guide as conservative?

No. I think we're back on track in the third quarter. So we're right within our guidance range on the third quarter, recovering from the weather impacts that hit us in very late June.

Got you. Got you. And my final question is just on Guyana. You have a gross $4 billion barrel kind of resource range. Can you help us think about potentially now 5 phases of the project of -- how much resource do you expect to recover in 5 of those potential distinct phases?

I think -- the recoverable resource on the block, again, is 4 billion barrels. I think those last few phases I said before were very much in the scoping phase as to where that -- where those vessels could lie. Are they going to be in Ranger? Or are they going to be in Turbot kind of complex? Where are they? So there's still a lot of uncertainty in that. But clearly, we've got a lot of oil to recover here, extremely high value. We're going to do that as judiciously as possible. So this is all good news.

Our next question comes from Paul Sankey with Mizuho.

I wanted to ask about the free cash flow inflection, but you've clearly answered that. I guess, one follow-up would be, given this is transformative for you in Guyana, the hedging, how do we think about that? And also, I guess, buyback, given that you're currently buying back stock, is that really something that you'll be doing when you have these big asset sales, I assume? And then the final thing, again, thinking transformatively, is dividend policy.

Sure. So let me get that dividend policy and the buyback. So let me just start where we are with that right now. And I guess as you know, we've got $500 million left under our share repurchase program right now, and we expect to complete that by the end of the year. And we're targeting $250 million in the third and $250 million in the fourth. And so as we look at it, we've got drilling coming here in the third quarter. We've got an exciting well in Suriname, another well, as Greg mentioned, Hammerhead. We need to get the results of this drilling program, and then work through with our partners on what our investment plans are going forward. So it's a little early right now. We'll get to the end of the year. We'll see where prices are. And at that point in time, we'll look where we are and see if there's anything from a buyback or debt reduction as we look into the future. Was there -- I forgot, Paul. Did you have another? Hedging...

Yes, I started with hedging, but you sort of headed towards dividend. Go ahead, sorry.

Yes. So from a hedging standpoint, as I mentioned, we did add 35,000 barrels a day for 2019, and you can expect us to add a bit more for 2019. Why, again, we're still in the investment phase, Guyana production hasn't started up in 2020. So again, from our standpoint, we just think it's prudent to put some insurance on in 2020. Obviously, when we get to the free cash flow phases of Guyana, then we're in a different position and hedging maybe less as we move forward. And that's when generating the growth in free cash flow is when we would start looking at our dividend policy as well and potentially increasing it at that time.

Great. And then the follow-up would be, you talked about a $35 breakeven for Guyana. Many of us on the call are oil finance nerds. Could you talk about the assumptions that you make to get that breakeven?

Sure. It's not -- you don't have to do really that much from an assumption standpoint. So the contract is out there, and it's public. It's there. We can't, from a confidential standpoint, talk about it. But it's public, so you can look at the contract. And the unique difference from a Guyana versus, let's just call it, a U.S. on a tax and royalty system is the production-sharing contract impact. So even if with -- we're in a great point in the cycle and you have low costs from that, so you can get low F&D in the Gulf of Mexico, well, what happens is if prices are lower, then, obviously, your breakeven is affected because you're not being able to get additional barrels out of the ground. With a production-sharing contract, what works with that is your cost recovery gets affected by the price. So as prices go lower, you get more cost recovery to help with that. And that's the way -- the point of a production-sharing contract. So it's really the mixture of the reservoirs, how good they are, the low point in the cycle, the F&D costs associated with it, and the production-sharing contract that gets you to that $35.

Our next question comes from Brian Singer with Goldman Sachs.

You've undergone a significant restructuring here in preparation for the Guyana development and production, selling the non-core assets, repurchasing shares. I wonder if you consider yourself towards the final innings of that restructuring. With the $0.5 billion of share repurchase left and the Utica assets to close in the third quarter, do you see any more to come on the asset shifting side of the equation?

Yes. The portfolio reshaping, I'd say the majority of the work's been done. There are 1 or 2 assets that still, if we got full value for them, we would consider monetizing. If not, we're happy to have them in the portfolio because they're good cash generators. Having said that, I think the key point going forward is, as both John and Greg have said, Guyana is really a truly world-class investment opportunity, one of the best, if not the best, in the industry, with low breakeven oil prices and high financial returns across the industry. It's one of the best. So our first, second and third priority is to fund that, maintain a strong balance sheet, investment grade credit rating to ensure that we have the capacity to do that. As we get further definition regarding our future capital requirements for the third phase of development, and then potentially a fourth and fifth phase as well as the outlook for oil prices, then we're in a better position to give consideration to further return to capital. But right now, we're focused on execution, finalizing the share repurchase program that we have, and bringing more clarity, both to our Bakken growth plan and our Guyana growth plan. So that's where we are. But we love the position we're in. And obviously, I think we're going to be in a position to generate superior financial returns and cash flow generation for many years to come as Guyana comes to fruition, and our Bakken plan does as well.

Great. And then my follow-up is with regards to that, the third drillship, specifically from exploration perspective. It sounded like there are some priorities for appraisal at Ranger and elsewhere. But can you speak more to the -- when and potentially where we would see exploration within Stabroek Block? And maybe relatively, can you talk about the extent to which the Ranger and Liza discoveries have derisked the portion within Stabroek and between the 2 discoveries, the acreage in between, and the plan for exploration there?

Yes. The third ship is going to -- as we understand from the operator and are working with operator, going to be focused on bringing further definition to the greater Turbot area with the success that we had at Longtail. To your point, this area is starting to be derisked. We see some other prolific sand channels there and potential resource adds. So that's what the third ship is going to try to appraise. The other exploration ship, as Greg said, goes to Hammerhead first. In the coming days, that should be spud. Then after that, we'll go to further appraise Ranger, maybe 1 or 2 wells. We'll see where that goes. And yes, obviously, as we get definition in each of those campaigns, and we get further seismic work, correlating the well results with the seismic, we definitely see numerous, more prospects on the block. I think Exxon said, and we would agree, there are probably another 20 exploration prospects on the block to drill. And yes, we do see the Stabroek Block being further derisked as we have more success. Remember, we're 8 out of 10.

Our next question comes from Paul Cheng with Barclays.

A number of quick questions. First is for Rielly. On the hedges, for 2019, do you have an estimate what is the amortization cost?

Sure. The cost of the 35,000 barrels a day was approximately $50 million. So it would be amortized over the...

For the full year?

For the full year.

And that's after tax?

Yes.

And John, that when -- previously, I thought the 2018 hedges you already crossed out or that you already have the offsetting. So that I thought the amortization charges, should they stay constant, why is hedging up over the last several quarters? I mean, initially you're talking about $30 million a quarter, and then $40 million. Now they're talking about $45 million. Any particular reason -- or now it's $50 million why that has been hedging up?

Sure. There's 2 reasons. One the jump from the $30 million to the $45 million was due -- remember, we did have a collar in place with the $50 WTI options at $65, and we bought back that collar. And obviously, we're benefiting from the higher prices right now from that purchase. So that increased the -- from $30 million to basically to $45 million. The only difference between the $45 million and $50 million is due to accounting. You have mark-to-market. On the way these hedges, you get this ineffectiveness. So we've got this additional amount that sits in other comprehensive income that's going to be amortized for the remaining part of the year. So nothing accounting associated with that.

Okay. On the Phase 2 Guyana, on the development, should we assume that the unit cost is going to be about the same as Phase 1? Or that because you said new drillships so that is going to be higher?

So we are still -- we're progressing FEED right now and getting all that information. So I'd prefer, Paul, we're going to be at the end of the year that we can be a little bit more specific on it. But obviously, what I would tell you, this is still going to be a terrific investment there. But right now, we're still working with the operator at exactly what the cost will be. We're working through the FEED, and we'll update you at the end of the year.

What I will say -- Paul, what I will say is that based on what we know so far that the costs are coming in lower on Phase 2 than they did for Phase 1 for most of the service lines. So obviously, that bodes well for Phase 2.

And Greg, should we assume $220 million that -- given that side, that would be a new drillship, right?

Yes, that will be a newbuild.

Because that the Phase 3, on the other hand, will be potentially a refurbish if you only go for $180 million. Is that the way how we should look at it?

Yet to be determined. But I think it will be -- no matter what it is, it's going to be consistent with this design one build, mainly very efficient kind of strategy, where the only thing that flexes is the top sides. Those will be modular based on the specific attributes of the development.

And can you give us some rough idea of what's the different cost between the refurbish and the new drillship? Is it about a $1 billion difference?

Paul, I don't have that information in front of me. What we're doing right now is just working with the operator. Obviously, ExxonMobil's been doing a terrific job on that. We could refer that type of question to them, but we'll be, again, try to maximize value in this as we move from Phase 3.

Yes. I think the key point here, Paul, is we're finalizing our costs. The operator's doing a great job getting those numbers to be as cost-efficient as possible. When we sanction the second FPSO, you'll have the number. And that will be before the end of the year. And then you'll be able to compare, as other investors will, with our Phase 1 ship as well. So once we finalize the sanction numbers, we'll give them to you, and then you'll be able to compare that with the first ship that we already have contracted.

And John and [Greg, then] now that you no longer put it up for sale, how should we look at that, asset that? I think, before, you've put it up for sale. At one point, you were thinking about spending some money to gradually expand the production. So now that you are no longer selling, should we just assume you're going to maintain here as flat or allow you to decline over time? Or are you trying to grow it a little bit over time? So how should we...

Yes. Paul, South Arne is a very good cash-generating asset. Obviously, Brent-based pricing generates good cash flows. And it has upside potential, both in terms of optimizing the field and further production with some investment, and also some nearby exploration that we could tie in. So we're coming up with our plans now to have an investment program there. It will have to compete for capital and the rest of the portfolio. But having said that, as we get further definition on what our investment program there, which we think will be very manageable, we'll be happy to communicate that to you. And we're going to retain the asset. We're happy to do it. It's all about value. And in the normal course of business, we'll continue to evaluate options to maximize its value.

Sure. A final one for me is probably for John Rielly. That if we're looking at your 2018 Midstream appendix, say, call it $640 million, $650 million, that's roughly about $16 per barrel for the Bakken production. And that must be including some minimum warning. But -- so as we're looking out, when you get to 175,000 barrels per day by 2021, what type of unit trend that we should be assuming?

So first, Paul, we do put in the supplements. You can see how the Midstream tariff then gets calculated, and coming back to Hess, net barrels. Because the first thing, when you calculate it on those numbers, you're getting kind of -- on a tariff applied to a net number, which is really applied to gross volumes, and also includes third-party numbers. So well, if you look at the supplement, which we do, we'll put that in place after the call here, you'll see, for us, it's about $8.70 on a gross basis for our barrels, and then we have 50% of that. So it's sitting in that kind of $4, $4.60-type range, net to Hess. Then as we see going forward, when the volumes do increase from the Bakken, you will get -- it is factored in -- the growth is factored in the way we calculate the tariffs. But over time, obviously, you'll get the efficiency of scale impact to those tariffs.

Now do you have a number you can share by 2021?

No. So I mean, again, we've talked about the Bakken study. What we're doing now, that all has to be integrated into our infrastructure plans, and that will work into the tariffs. So that's all part of the Bakken study to maximize value.

Our next question comes from Michael Hall with Heikkinen Energy Advisors.

Mike Hall with Heikkinen Energy Advisors. So most of mine have been answered at this point. I'm just curious. On the Bakken earlier in the year, you had talked about a 4Q rate of around 120,000 to 125,000 MBOE a day. Is that still in the cards? Is that something we should still be modeling towards? It sounded like maybe sub-120,000 per the comments. I didn't know if that was just kind of rounding for a lack of a better word.

So I just want to make sure what you're asking, Michael. So on the Bakken volumes that we're talking about as we were getting to the end of the year?

Yes. I think it was about how -- this call, you talked about 120,000 to 125,000. Is that still fair?

Yes. You can still expect us to be at 120,000 barrels plus in the fourth quarter in the Bakken. In fact, if you just look at our guidance in the way we have the 115,000 to 120,000 in the third, and then going 115,000 to 120,000 for the full year, you'll see we are still planning to be above 120,000.

Got it. Yes, I didn't know if that comment on the full year meant the rest of the year, sorry. I was just trying to clarify. No, that's helpful. Okay. And then the remaining wells to be turned online in the Williston, this year, are those relatively evenly loaded across the year? Or was there any emphasis in 3Q or 4Q just from a timing standpoint?

More of them will be in the fourth quarter. Because what happens now is we have the fifth rig coming in. Really, any wells that are drilled by the fifth rig, that will -- won't impact the third quarter. That's why we'll get more wells online in the fourth quarter and the production going up from there.

Yes. The fourth quarter is going to be a very big quarter in terms of wells online.

Okay. And the last one. I guess, just on the Williston again and the -- can you just quantify how much the weather impacted 2Q in June?

It was a couple thousand. Because we were -- as Greg said, we were right on track, April, May. It was June in the weather. And that month was affected. So overall, for the quarter, it was a couple thousand barrels. And right now, we are right back on track where we were before.

Our next question comes from Phillips Johnston with Capital One.

Greg, just a follow-up on the prior questions about Keene. As we look out to 2019 with the rig count, entering the year at 6 versus 4 in the first half of this year, from a directional standpoint, should we expect activity will be less focused on the Keene area with the mix maybe dropping down to -- closer to 1/3 of completions versus close to half this year? Or would you expect to keep the Keene mix closer to 50%?

No. I think the Keene percentage will go down. But obviously, in our 2019 budget, we'll update the guidance because we will be most likely in a 100% plug and perf mode by then. So all the IP 180s and everything will have to be updated as we do our planning guidance for 2019. But yes, there will be fewer Keene wells next year than this year. But that doesn't mean IP 180's average for the year will be less. With plug and perf, there would be upward pressure on IP 180 with the plug and perf situation. But we'll update all that when we give guidance next year.

Okay. And you quantified how many remaining locations there are at Keene or is that something that will come out after the study?

That's something that will come out after the study as well.

Okay. And then just a question, maybe for John Rielly. You guys have reported working capital cash outflows for the past 6 quarters that have amounted to roughly $1 billion or so. What have been the primary factors there? And when would you expect that trend to sort of reverse?

Sure. So first of all, we did have the hedging, right? So we've kind of gone through with our hedges. Now we will have -- as I mentioned earlier, we have $50 million on our 35,000 barrels a day in 2019. So that will come in the third quarter. So our hedging do go through there. Some of the things that were basically impacting us, besides the hedge's premiums paid, is we do have -- you've got your normal things like pension contributions. You've got -- we had abandonment. If you were going back several quarters, and when we had Valhall, those were always significant amounts. We've got timing on income tax payments related to Libya in the 93.5% tax rate. So those will always continue. And what I would say is on a normal run-rate basis, our first quarter and our third quarter were going to be the higher pulls on working capital. So you have -- because, one, we've -- that's the semiannual kind of payments from our -- on our bonds happened in the first and third quarter. The first quarter always has your bonus payments in there as well. And then outside of that, it's just normal recurring. So the only unusual things that we'll get in there is kind of from the hedging and things like that. So if you looked at this quarter, right, it wasn't much of a pull in cash flow, and you can see was an add in fixed assets. So we actually -- on an overall basis, working capital had a positive on the bottom line from it. So things are going to move in and out just like that, and first and third being bigger, and second and the fourth, not so much.

Our next question comes from Jeffrey Campbell with Tuohy Brothers.

I wanted to just ask Greg to kind of step back maybe and give me an overview of all this plug and perf stuff. In the past, I thought you had said that you felt these were going to be the best for maybe a Tier 2-type resource. But it sounds like that it's -- particularly based on what you just said about 2019, it sounds like this is moving towards becoming a primary way to complete the wells. So maybe I was confused, but could you just talk about it kind of on a higher level?

Yes, you bet. So I think you are correct. We always knew that as we went outside the core of the core that we would have these plug and perfs. So I think we've always said that. But what we are doing is part of the Bakken study because some of our competitors are using plug and perf in the core of the core. We are trialing some of that as well. So again, our mission here is, for the 2/3 of the inventory remaining in the Bakken, what is the best way to maximize value per DSU, both in the core and outside the core? So we wanted to get some wells in the quarter as well to do a good comparison. So that's the ultimate objective of the Bakken study. Now based on the results, so far -- and again, it's a limited sample. But based on the results so far, indicatively, it looks like that even plug and perf and the core can give you an improvement. So -- but at the end of the day, we're going to go area-by-area in the field, and answer that question, what's the best way to maximize value per DSU? And that answer could vary depending on where you are in the field, and the completion design could vary depending on where you are in the field. Right now, directionally, we're just saying plug and perf looks pretty good. So from an assumption standpoint, let's assume that we're going to do plug and perf throughout the field.

Okay. Well, that's helpful. And also, I assume, as you always say, that case-by-case, it's going to be economic. So if it were somehow possible that sliding sleeve would produce a better economic and sell someplace, then you would use that.

Exactly. And I think what's happened with plug and perf, so there's been quite a change in plug and perf over the last couple of years, which kind of changes how we think about it. And that's the introduction and perfection of limits then reperforating. So that allows you to tightly control where your proppant and fluids are going. And then secondly, the costs of plug and perf have come down substantially during the downturn. So that made plug and perf come more into queue on a comparison basis to sliding sleeve. And then finally, we reached kind of the technical limit on sliding sleeves. About 60 stages is all you can really stuff in those. So I can get more stages, have tight control, and as a cost that's not that far off from plug and perf or sliding sleeve. So therefore, it makes sense to evaluate that technology now.

Yes, that was really helpful. I appreciate it. And I just wanted to ask quickly, you mentioned you're going to go to 6 Bakken rigs by the end of the year, and I think you said you've already added a third frac crew. I was just wondering, is this the activity level that you see maintaining going forward? Or are you still unsure until you completed it all on the study?

No. I think, directionally, it looks like 6 rigs is about right. And that's a function of you don't want to build the infrastructure too fast and overbuild and not be capital-efficient. So 6 rigs, at this point, is still kind of the sweet spot. The third frac rig -- frac crew will be added in the latter part of the year. So we have not added that yet, but it's on its way.

Our next question comes from Pavel Molchanov with Raymond James.

Just one question for me kind of a high level point about Guyana. Given the new targets you're putting out for 2025, at least 1/3 -- possibly half of the company's net volumes will be coming from Guyana at that point. How comfortable are you just kind of conceptually with that level of asset concentration? And to state the obvious, what's historically been somewhat of a frontier market?

We're very happy to have one of the truly world-class investment opportunities in the oil industry that keeps getting bigger and better. We believe that our 30% working interest is appropriate for this world-class asset. We have a world-class operator in ExxonMobil. And so we're happy to have this opportunity to invest shareholder money, which has a very high financial return. So net-net, we're happy with it. And you've got to remember, it's part of our portfolio. We also have the Bakken. We also have the deepwater Gulf, and also Malaysia. So the combination of that portfolio, I think, manages, and is really managing not only the risk of the different investments, but the financial performance of those. So we think our focus portfolio with that balance, and that's the key, makes Guyana stand out and be positioned the best way that it can be for our shareholders.

This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.