Hess Corporation

Good day, ladies and gentlemen, and welcome to the second quarter 2019 HESS Corporation Conference Call. My name is Amanda, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a -and-answer session. If at any time you require operator assistance, please press star followed by zero, and we will be happy to assist you. 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, Amanda. 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, .hess.com. Today's conference call contains projections and other forward-looking statements within the meeting 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 factor 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. Now as usual, with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Reilly, 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 Reilly will review our financial results. In the second quarter, we continue to execute our strategy and deliver strong operational performance with our full-year production now expected to come in at the upper end of our guidance range and our capital and exploratory expenditures projected to come in under our original guidance. Our portfolio, which is balanced between our growth engines in Guyana and the Bakken and our cash engines in the deep border Gulf of Mexico and the Gulf of Thailand, is on track to generate industry-leading cash flow growth with a portfolio break-even that is expected to decrease to less than $40 per barrel Brent by 2025. A key driver of our strategy is our position in Guyana. The 6.6 million acres Staybrook 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 strong financial returns. In April, we announced our 13th discovery on the Staybrook Block at Yellowtail. The Yellowtail No. 1 well encountered approximately 292 feet of high-quality oil-bearing sandstone reservoir and is the fifth discovery in the turbo area, which is expected to become a major development hub. Total discoveries on the Staybrook Block to date have established the potential for at least five floating production storage and offloading vessels, or FPSOs, producing over 750,000 barrels of oil per day by 2025. Drilling and appraisal activities were completed at the Hammerhead 2 and Hammerhead 3 wells with encouraging results, including a successful drill stem test in July. These results are being evaluated for a potential future development. Exploration and appraisal drilling continues on the Block at the Triple Tail Prospect in the Greater Turbo Area and at the Ranger Discovery where a second well is underway. As a result of this year's discoveries and further evaluation of previous discoveries, we have increased the estimate of gross discovered recoverable resources for the Staybrook Block to more than 6 billion barrels of oil equivalent, up from the previous estimate of more than 5.5 billion barrels of oil equivalent, and we continue to see multi-billion barrels of additional exploration potential. In terms of our developments, Lisa Phase 1 continues to advance. On July 18, the Lisa Destiny FPSO, which has the capacity to produce up to 120,000 gross barrels of oil per day, sets sail from Singapore and is expected to arrive in Guyana in September. First production is expected by the first quarter of 2020. Phase 2 of the Lisa development, which was sanctioned in May, will use a second FPSO, the Lisa Unity, with production capacity of up to 220,000 gross barrels of oil per day. Startup is expected by mid-2022. Planning is underway for a third phase, at Payara, which will use a FPSO with the capacity to produce between 180,000 to 220,000 gross barrels of oil per day. First production is on track for 2023. In the Bakken, we have a premier acreage position and a robust inventory of high return drilling locations. We plan to continue operating six rigs, which is expected to grow net production to approximately 200,000 barrels of oil per day by 2021, along with a meaningful increase in free cash flow generation over this period. Now, turning to our financial results, in the second quarter we posted a net loss of $6 million or 2 cents per share compared to a net loss of $130 million or 48 cents per share in the year-ago quarter. On an adjusted basis, we posted a net loss of $28 million or 9 cents per share compared with an adjusted net loss of $56 million or 23 cents per share in the second quarter of 2018. Compared to second quarter 2018, our improved financial results primarily reflect increased U.S. crude oil production and reduced expiration expenses, which were partially offset by lower realized selling prices and higher DD&A expenses. Second quarter net production averaged 273,000 barrels of oil equivalent per day, excluding Libya, up from 247,000 barrels of oil equivalent per day in the year-ago quarter. For the full year 2019, we forecast that net production will average between 275,000 and 280,000 barrels of oil equivalent per day, excluding Libya, which is also at the upper end of our previous guidance range. Second quarter net production in the Bakken averaged 140,000 barrels of oil equivalent per day, up 23% from 114,000 barrels of oil equivalent per day a year ago. For the full year 2019, we now forecast that the Bakken net production will average between 140,000 and 145,000 barrels of oil equivalent per day at the upper end of our previous guidance range. Before closing, I would like to note that we published our annual sustainability report earlier this month for the 22nd year. We believe sustainability practices create value for our shareholders and position us to continuously improve our business performance. Our sustainability report is available on our company website at .hess.com. In summary, we are successfully executing our strategy, which will deliver increasing and strong financial returns, visible and low-risk production growth, and significant future free cash flow. I will now turn the call over to Greg for an operational

update. Thanks, John. I'd like to provide an update on our progress in 2019 as we continue to execute our strategy, starting with production. In the second quarter, net production averaged 273,000 barrels of oil equivalent per day, excluding Libya, which was within our guidance for the quarter of 270,000 to 280,000 barrels of oil equivalent per day. Strong performance across our operated portfolio was partially offset by unplanned downtime at the Shell-operated Enchilada facility in the Deepwater Gulf of Mexico, which reduced our second quarter net production by approximately 4,000 barrels of oil equivalent per day. In the third quarter, we expect net production to average between 270,000 and 280,000 barrels of oil equivalent per day, excluding Libya. As continued ramp-up of the Bakken is expected to be partially offset by planned maintenance at our JDA asset in Southeast Asia and the impact of Hurricane Barry in the Gulf of Mexico in early July. Based on our -to-date performance and our expectation of strong production growth from the Bakken, the Deepwater Gulf of Mexico, and Southeast Asia in the fourth quarter, we now forecast full-year 2019 net production to average between 275,000 and 280,000 barrels of oil equivalent per day, which is at the upper end of our previous guidance range. Turning now to the Bakken. Capitalizing on the success of our new Plug and Perf completion design, we delivered a strong quarter. Second quarter Bakken net production averaged 140,000 barrels of oil equivalent per day, which was at the top end of our guidance range of 135,000 to 140,000 net barrels of oil equivalent per day and approximately 23% higher than the year-ago quarter. For the third quarter, we forecast our Bakken net production will average between 145,000 and 150,000 barrels of oil equivalent per day. For full-year 2019, we now forecast Bakken net production will average between 140,000 and 145,000 barrels of oil equivalent per day, which is also at the upper end of our previous guidance range. In the second quarter, we brought 39 new wells online, and in the third quarter we expect to bring approximately 45 new wells online. For the full-year 2019, we still expect to bring approximately 160 new wells online. Moving to the offshore. In the Deepwater Gulf of Mexico, net production averaged approximately 65,000 barrels of oil equivalent per day in the second quarter, reflecting planned maintenance activities at tubular wells and ballpate, as well as an unplanned shutdown at the Shell-operated Enchilada facility in the Deepwater Gulf of Mexico, which resulted in a 22-day shut-in of production at our Conger Field. In line with our strategy of investing in high-return opportunities, we are pleased to report that the Lano 5 well in the Gulf of Mexico, where HESS has a 50% working interest, was successfully brought online in July and is expected to reach a gross production rate of between 8,000 and 10,000 barrels of oil equivalent per day in the fourth quarter. The well was drilled and completed in approximately 60 days, two weeks ahead of schedule. In Southeast Asia, net production averaged approximately 59,000 barrels of oil equivalent per day in the second quarter, reflecting a successfully completed planned shutdown for maintenance activities at North Malay Basin. As I mentioned earlier, we also completed a planned two-week shutdown at the JDA last week, and production is now back to pre-shutdown levels. Now turning to Guyana. Our exploration success on the Staybrook Block continues, with three new discoveries so far in 2019 at Tilapia, Imara, and Yellowtail, bringing the total number of discoveries on the block thus far to 13. We completed drilling operations on the Hammerhead 2 and 3 wells in June and July respectively, which included a successful drill stem test on Hammerhead 3, and we are currently evaluating the results for potential future development. The Noble Tom Madden Drill Ship is currently drilling the intermediate section of one of the Lease of Phase I development wells, and will then return to finish drilling the Triple Tail 1 well with results expected in October. The Stenekaren Drill Ship recently commenced drilling of the Ranger 2 appraisal well. This is a follow-up to the successful Ranger 1 exploration well, which in January 2018 established a large oil-bearing carbonate structure located approximately 60 miles northwest of the Lease of Field. An extensive logging and coring program, as well as a drill stem test, are planned for Ranger 2. Now turning to our Guyana developments. Lease of Phase I is progressing as planned. The Lease of Destiny FPSO, with a gross production capacity of 120,000 barrels of oil per day, has departed Singapore and is expected to arrive in Guyana in September. Drilling of the Phase I development wells by the Noble Bob Douglas Drill Ship is proceeding the plan, and the installation of subsea umbilicals, risers, and flow lines is approximately 70% complete. The project is on track to achieve first oil by the first quarter of 2020. Lease of Phase II, sanctioned in May, will utilize the Lease of Unity FPSO where fabrication activities are currently underway. Lease of Unity will have a gross production capacity of 220,000 barrels of oil per day and will develop approximately 600 million barrels of oil. First oil is expected by mid-2022. A third phase of development at Piara is expected to have a gross capacity of between 180,000 and 220,000 barrels of oil per day, with first oil on track for 2023. In closing, our execution continues to be strong, and in 2019 we are positioned to deliver production at the upper end of our previous guidance range, along with lower capital and exploratory expenditures than our previous guidance. Our offshore cash engines continue to generate significant cash flow. The Bakken is on a strong capital-efficient growth trajectory, and Guyana continues to get bigger and better, all of which position us to deliver industry-leading returns, material-free cash flow generation, and significant shareholder value for many years to come. I'll now turn the call over to John Reilly. Thanks, Greg.

In my remarks today, I will compare results from the second quarter of 2019 to the first quarter of 2019. We incurred a net loss of $6 million in the second quarter of 2019, compared with net income of $32 million in the first quarter. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $28 million in the second quarter of 2019. Turning to E&P, on an adjusted basis, E&P had net income of $46 million in the second quarter of 2019, compared to net income of $109 million in the previous quarter. The price and volume variances between the second quarter and first quarter were immaterial. The other changes in the after-tax components of adjusted E&P earnings between the second and first quarter of 2019 were as follows. Higher operating costs, as guided, driven primarily by workovers and maintenance activities at North Malay Basin and Tubular Bells, decreased earnings by $27 million. Higher production and severance taxes decreased earnings by $7 million. Higher seismic expense in Guyana decreased earnings by $9 million. Changes in foreign exchange decreased earnings by $8 million. For the second quarter, all other items decreased earnings by $12 million, for an overall decrease in second quarter earnings of $63 million. Turning to Midstream, the Midstream segment had net income of $35 million in the second quarter of 2019, compared to $37 million in the first quarter of 2019. Midstream EBITDA, before non-controlling interest, amounted to $127 million in the second quarter, compared to $129 million in the previous quarter. For corporate, after-tax corporate and interest expenses were $109 million in the second quarter, compared to $114 million in the first quarter of 2019. Turning to our financial position, At quarter end, cash and cash equivalents were $2.2 billion, excluding Midstream, and total liquidity was $6.1 billion, including available committed credit facilities, while debt and finance lease obligations totaled $5.7 billion. During the second quarter, we entered into a new, fully undrawn, $3.5 billion revolving credit facility, maturing in May 2023, which replaced our previous credit facility that was scheduled to mature in January 2021. Net cash provided from operating activities was $675 million, while cash expenditures for capital and investments were $640 million in the second quarter. Changes in working capital increased operating cash flows by $115 million in the second quarter. Now turning to third quarter and full year 2019 guidance for E&P, our E&P cash costs were $12.11 per barrel of oil equivalent, including Libya, and $12.72 per barrel of oil equivalent, excluding Libya, in the second quarter. We project E&P cash costs, excluding Libya, to be in the range of $13 to $14 per barrel of oil equivalent for the third quarter of 2019, which reflects the impact of planned maintenance shutdowns at the JDA and Ballpate, planned maintenance projects in the Bakken, and the impact of Hurricane Barry. Full year 2019 cash costs, excluding Libya, are now expected to be $12.50 to $13 per barrel of oil equivalent, which is down from previous guidance of $13 to $14 per barrel of oil equivalent. DD&A expense was $17.20 per barrel of oil equivalent, including Libya, and $18.31 per barrel of oil equivalent, excluding Libya, in the second quarter. 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 2019, with full year guidance unchanged at $18 to $19 per barrel of oil equivalent. This results in projected total E&P unit operating costs, excluding Libya, to be in the range of $31 to $33 per barrel of oil equivalent for the third quarter, and in the range of $30.50 to $32 per barrel of oil equivalent for the full year of 2019. Exploration expenses, excluding dry hole costs, are expected to be in the range of $50 to $60 million in the third quarter, and full year guidance to be in the range of $200 million to $210 million, which is in the lower end of our previous guidance. The midstream tariff is projected to be approximately $185 million for the third quarter, with full year guidance expected to be $740 million to $750 million. The increase in the third and fourth quarter tariff expense is due to an anticipated increase in midstream volumes, driven by growing HES production and increasing third-party throughput with the startup of the Little Missouri Four gas processing plant in North Dakota. 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 and for the full year. Our crude oil hedge positions remain unchanged. We have 95,000 barrels of oil per day hedged for calendar 2019 with $60 WTI put option contracts. We expect option premium amortization to be approximately $29 million per quarter for the remainder of the year. E&P capital and exploratory expenditures are expected to be approximately $800 million in the third quarter and $2.8 billion for the full year, which is down from original guidance of $2.9 billion. For the midstream, we anticipate net income attributable to HES from the midstream segment to be approximately $40 million in the third quarter and in the range of $170 million to $175 million for the full year. Turning to corporate, for the third quarter of 2019, corporate expenses are estimated to be in the range of $25 million to $30 million and full year guidance to be in the range of $110 million to $115 million. Interest expense is estimated to be in the range of $75 million to $80 million for the third quarter and full year guidance to be in the range of $315 million to $320 million. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

Ladies and gentlemen, if you have a question, please press star followed by one on your phone. If your question has been answered or you would like to withdraw your question, press pound. Questions will be taken in the order received. Please press star one to begin. Our first question comes from the line of Doug Legate of Bank of America. Your line is open.

Thanks. Good morning everybody. Morning. I wonder if I could ask a couple in Guyana and then just one on the back. On Guyana, Greg, it's probably for you. Could you give us a little bit more color on the Hammerhead appraisals? Obviously they're kind of scant detail in the release, but what does this mean for the potential of, I guess, an accelerated development? I think that had been alluded to in the past, but to put both your exploration assets and then not bring forward a development seems a little bit unusual. The related question is when you describe the Yellowtail, Turbot, Longtail area as a major development hub, one assumes that doesn't relate to a single FPSO. So it seems that we're kind of stacking up development visibility here. I just wonder if you could offer us any color on why we still haven't seen an uplift to the Greater Bands 750 guidance for 2025.

Yeah, Doug, thanks. So let me take your first question. So first of all, the Hammerhead well results for both Hammerhead 2 and Hammerhead 3 really demonstrated three things. First of all, both had high quality reservoirs. The DST on Hammerhead 3 showed very good mobility. And finally, very good connectivity. And the connectivity is actually between all three wells. So all three wells are in pressure communication. So that bodes well for a development. Now, we're rolling all the results of this, obviously, into the development plan studies for that area. So we're just not ready to announce anything, but we are rolling all the data in earnest into the studies as we speak. Regarding your second question, you're right. We do have a lot of volume now underpinned really between the Leza complex and the Turbo complex. And we're also in earnest doing development studies on that area. Obviously, it's going to be a multi-FPSO kind of situation given the amount of volume we found. And then furthermore, as we look forward between now and the end of the year, we're going to do some more exploration drilling really along that northeastern part of the State Brook Block between Turbot and Leza. And we'll drill probably three, potentially four, additional wells or get them started this year, starting with Triple Tail first and then two or three other prospects along that southeastern seaboard. So continue to see a lot of upside in that area. But again, all that's being rolled into development studies as we speak.

Thanks for the clarity, Greg. My follow-up is hopefully a quick one. You guys process a lot of third-party volumes, I believe, on a -in-kind system in the back. And my question really relates to the oil mix relative to the angiomics, I guess, and the liquids that you saw this quarter. It seemed that the oil mix dropped quite a bit. I wonder if you could speak to what was going on there and whether we should read through any material changes in response to your expectations for oil mix going forward in your development area. And I'll leave it there. Thanks.

Sure, Doug. Thanks for that. And no, there shouldn't be any change in our mix going forward. So let me just talk first at a high level, our Bakken asset. It is doing really well, and it's in terms of, I'll call it production, overall production, capital and costs, and specifically oil production. So what we had during the quarter, April and May, were tough weather months, and well availability was low. But June was really strong, and July has been really strong. So what we can tell you is we've always said we're in this low to mid-60s oil cut. So let me just say 63%, 64%. You can feel comfortable using that number on our third quarter production guidance that we gave for Bakken. And you can see there that we're going to have a very strong oil production increase from the second to the third quarter. So then specifically, let me get to your point on the second quarter, what happened. As I mentioned, April and May were tough weather months, so well availability was low, and that affected both oil and gas. Then if you look at our first quarter, we had a high oil cut of like 66% in that, and it does get into the timing of gas capture. So we had additional gas capture in the second quarter. So all else being equal, I would have said our overall production would have been in the 136 to 137 area with an oil cut percentage in that 63% to 64%. But now it gets to your, I'll call it payment in kind, on the gas processing fee. So we do have a percentage of our contracts at the Tioga gas plant that our percentage of proceeds are POP contracts. And so what happened obviously between the first and second quarter with lower NGL and gas price, gas prices, we receive more volumes for those contracts. So all else being equal, we probably picked up three to four thousand barrels a day of NGL, say in gas, if you want to call it barrels, in the second quarter. So that's why the oil cut is showing where it is. But let me just say going forward, we've always said we're going to maintain this low to mid 60% oil cut all the way up to 200,000 barrels a day. So we are right on track for the 200,000 barrels a day. The Bakken asset team is executing really well and the plug-in perf wells are doing really well. So we're excited about the asset and the third quarter looks good.

Appreciate the detailed answer, John. Thanks so much.

Thank you. And our next question comes from the line of Bob Brackett of Bernstein Research. Your line is open.

Good morning. Quick question on the ESOX prospect in the GOM. Can you give us an update on the status of that?

Yeah, Bob. So we are poised to begin drilling that, you know, in the third quarter. So we will spud that well in the third quarter. And that's a tieback. If successful, that will be a tieback to two-biller wells.

And then a follow-up on Ranger II. Can you talk about what the purpose of the appraisal is? It looks like that well sits pretty high up on the structure as opposed to the edge of the structure. Are you looking at sort of the reservoir quality or what are you testing for?

Well, I think, Bob, you know, the Ranger I well was drilled on the leeward side. It was drilled in a relatively safe position from a drilling standpoint. The Ranger II well, we're actually going to move to the windward side of the historic carbonate reef. So we expect, you know, higher porosity because that's the portion of the reef that was subjected to wave action and also, you know, rainwater, et cetera. So we're looking for reservoir quality there. We want to do a DST and that will help us, you know, also establish connectivity. Great. Thank you for that.

Thank you. And our next question comes from the line up at Roger Reed of Wells Fargo. Your line is open.

Yeah. Thank you. Good morning. I was wondering if we could come back to the change in the CapEx guidance and maybe give us an idea of where the efficiencies are flowing through the, you know, roughly 100 million decline.

Roger, I wish I had an easy just one off for you, but it really is across our portfolio. So there's been good execution. So this is in Bakken. It's in Southeast Asia. Guyana costs have been quite good. So it really is across the portfolio. So same thing on the cash cost, the reduction there from the $13 to $14 per BOE down to the $12.50 to $13 BOE. We're seeing it across the portfolio. I guess probably on the count of the biggest piece would be the Bakken, but it really is across the portfolio.

So we'll just call it a potpourri or something like that, huh?

Yes. That's a good name.

All right. And then kind of like the rest of the crowd here, I guess let's talk Guyana. As you think about the continued E&A process alongside the development, I mean, should we think about you being able to achieve as you go out, I believe, to 2025 for the exploration program, being able to achieve everything you want on exploration with the existing rig fleet, or do you think we'll see expansions there as I guess we all would like to see parallel development, continued execution on the original five SPSOs that are highlighted, and then the ability to achieve all the exploration?

Yes. So Roger, we do plan to add a fourth drill ship to the theater, and that will be initially focused on exploration on the Staybrook Block in the fourth quarter. Obviously as we begin to get into phase two drilling, et cetera, there will be a couple rigs drilling development wells at that point in time. But these rigs are going to be flexible. They're going to move from E&A work, depending on success, might move over to developments for a while, and then they'll come back to E&A. So we're developing a great plan to get everything we want to get done from an E&A standpoint in time before exploration of the block. So we are developing a plan to do all of that.

All right. Thank you.

Thank you. And our next question comes from the line of Brian Singer of Goldman Sachs. Your line is open.

Thank you. Good morning. Good morning. Just a couple of additional follow-up questions on Guyana, and the first does relate to exploration. You mentioned that some of the wells that are going to be drilled are on the southeast corridor upcoming. Can you just talk a little bit more beyond Ranger and there, if you see any step-out locations that you plan to drill with this fourth rig or otherwise over the next year, and specifically away from the, either between Ranger and Leza or a step-out away from Ranger into potentially new structures, carbonates or not?

No. So let me just again lay out the kind of drilling sequence for the next six months. So first of all, we're going to drill the Ranger to appraise a well, and then follow that with an extensive logging, coring program, and DST. So the rig will be on that location for a fair amount of time. The next rig will go back to the Triple Tail well. So that's going to be the first exploration well in the second half of the year. And then beyond that, we anticipate two or three additional exploration wells to have spud before the end of the year, with, as I mentioned earlier, the focus really being on drilling out the southeast part of the block between Turbett and Leza. So really defining that southeastern corridor of the block. And obviously that is so that we can plan our developments down there, how many ships and how do we sequence them, et cetera. And then looking beyond that, of course, in 2020 we'll spud a well in Keiter Block as well. And then also on the Heth side we'll have a Block 42 well in Suriname in 2020 also. But I think it's important that we continue to add to the inventory of exploration prospects on the block that represent multibillion barrels of upside. So there's going to be an extensive ENA program over the next several years in Guyana for sure.

That's great. And my follow-up is with regards to some of the discoveries that at least initially showed gas condensate that you've made, like Haimara, can you just talk about any new data or planning that you've seen and how you think about monetization there?

Well, I think that's being rolled into our overall block development plans. And when and how Haimara plays in, not sure yet. It's certainly in the queue. But as far as sequencing, not clear yet. And part of it is we want to praise some more and explore some more in and around that Haimara hub in the next 18 months, we'll say.

Great. Thank you.

Thank you. And our next question comes from the line of Paul Zanke of Mizuho. Your line is open.

Hi. Good morning, everyone. Greg, I guess there's very much a variation on the theme in terms of the exploration success and the sort of luxury problem you have in Guyana. Is there a point at which there's simply too much inventory and you change plans accordingly? Or is the very long-term potential nature of this development really mean that levels of activity that you've really quite clearly outlined are fairly stable and are really anticipating major discoveries, therefore plans don't change?

Yeah, Paul, excellent question. No, we're taking a phased approach here, which we think is the most capital-efficient one, and it will maximize our financial returns. So actually from a financial return perspective, the roadmap that we've laid out, which is getting Lisa 2 on in mid-2022 after Lisa 1, which actually is running ahead of schedule in the first quarter of 2020, that will be followed by Payara in 2023. And then the exploration and appraisal program that Greg's talking about is going to give us further definition about a fourth ship, which would probably be a year after Payara, and a fifth ship, which would probably be a year after that one. And that really gives you the line of sight for the five ships. The exact sizing of the fourth and fifth ship is the reason we're doing the exploration and appraisal program. So we're very comfortable about the financial requirements for that, and we're very excited about the financial returns we're getting from that. Obviously further exploration drilling may have an impact on those ships in terms of sequencing and also identify further ships, but it's very manageable from a financial perspective, and we in Exxon and CNOOC are totally aligned about maximizing value from this opportunity that we have.

Thank you, John. If I could ask a follow-up. We've had a lot of volatility in time this past regarding oil markets. Can you just update us on your latest thoughts for how Guyana will impact Gulf oil markets, given how things have changed over the past couple of years? Thank you. Well,

you know, I think Guyana being a very low-cost development with the first ship having a breakeven Brent price of $35 a barrel and the second ship having a breakeven price of $25 a barrel, you know, they're going to be very well situated to fit into the world oil market. The world oil market, as you know, is very much determined by demand and supply. The headwinds that we've had in GDP growth worldwide are obviously having an impact on demand growth. Demand is still growing, but at a slower rate as GDP grows at a slower rate. And then, you know, how shale, how these new developments and how OPEC all intersect to keep the market balanced to have a price high enough for investment and low enough for demand growth is obviously something that's unfolding. So volatility is something we have to live with, and obviously that's why we want to build a portfolio that has a low cost for barrels, so we have resilient returns in almost any price environment. Thank

you, Joan.

Thank you. And our next question comes from the line of Paul Cheng of Scotia Howard Vial. Your line is open.

Hey, guys. Good morning. Hey, Paul. A couple questions. I know it's still early, but I want to look at the preliminary outlook for the 2020 CapEx. I suppose that we should see the button expense to be up on the full year of the six-week, and also that the Guyana spending probably will be up, given that the phase two spending is going to ramp up probably a bit subsensory. So maybe, Joan, you can help us to look at in those items how the delta is going to change.

Sure, Paul. Obviously, we'll give our guidance for 2020 as per our normal practice in late 2019, early 2020. But I think you can go back to our investor day in December 2018, and we laid out the plan that John just talked about as well. So based on that, we do expect that capital and exploratory spend for 2020 to be approximately $3 billion as we had laid out. To your specific question, so Bakken, what's going to happen with Bakken? We have six rigs this year in Bakken, and we'll have six rigs next year. And then we go down to the four rigs that we had talked about in 2021 and generate that billion dollars of free cash flow. So the activity level is the same from that standpoint. So we're not expecting any big increases there in the Bakken. And obviously, as we talked about, we've been getting some nice efficiencies there. Guyana, yes, that's as you know, we're coming in at $2.8 billion this year. That's what we had expected per the investor day that there would be some increase in Guyana. And that will be the add. And we're perfectly comfortable with that, exactly as John has just laid out. And the timing of that with Phase 2 coming on in mid-2022. So everything is going along according to plan. Bakken is executing well with 200,000 barrels a day. We're a quarter closer to starting up in Guyana. And so you can expect that type of guidance when we get to 2020. Okay.

Two quick ones. One, I think you overlit by $6,000 a day. Maybe I missed it in your prepared remark. What's the earning and cash flow contribution for the quarter? And secondly, John, as you have indicated, rightfully that, with the Phase 1 coming on stream next year. And so from that standpoint, and with say you have a pretty strong balance sheet at this point, is it really necessary for us to have the hedging? What is the future hedging strategy going to look like?

Sure. So just starting with the overlifts, you can probably tell by our tax line that one of the big overlifts was in Libya. So overall, we had about, let me just call it, 200,000 barrels a day in Libya. We had 200,000 barrels a day in Denmark. And we also had a 200,000 barrel a day over lift with JDA offset by North Malay Basin being under 200,000 barrels. So what happened is just from an overall earning standpoint, it was immaterial since Libya and Denmark driving that over lift. So nothing material there. Then as far as we're looking on, yes, with our program that we have going forward, we do intend to put hedges on for 2020. We just think it's a prudent thing to do as we just discussed, or John has just discussed the oil price volatility. So it's just something that we want to do from an insurance standpoint to make sure that we can execute this great program that we have. So you can expect us to, subject to market conditions, to adding hedges for 2020.

The only comment I would make is that it seems like everyone lost money over the long haul in hedging. So I'm not sure that it's really for the benefit for the shareholder. Anyway, thank you.

Thank you. And our next question comes from the line of Aaron Jeram of JPMorgan. Your line is open.

Yeah, my first question is for Greg. Greg, I was wondering, you did 39 wells in the Bakken in 2Q. And I was wondering if you guys have tested some of the areas such as Goliath or Red Sky, or some of the areas perhaps outside of your kind of core development area, Keen, et cetera.

Yeah. So first of all, let me say that we have, and we don't have a lot of wells out there yet. But what I will say is that the wells drilled to date in those areas are meeting expectations. That's with returns in the order of 40 to 50 percent at $60 a barrel. Our plan for those areas in 2019 is to drill about 25 wells. And we're going to be testing kind of different completion designs and well spacing in order to try and further optimize our development in these areas. As you recall, we've got at least a 15-year inventory of wells that exceed 50 percent IRRs at $60 a barrel. And I expect with the optimization that we're going to do this year in those areas like Goliath and Red Sky, that I expect that inventory is probably going to grow as a result of that optimization.

Great. Thanks a lot. And this one for John Riley. John, you gave us some great color on overall production guidance and as well as your thoughts on the Bakken oil mix. Could you help us with your thoughts on a range of oil production versus the BOE total for Q3 and Q4?

So if you were looking at where we were kind of the first two quarters and you're saying overall production, we had our oil was 52 percent of our production in the first quarter and was 52 percent in the second quarter. So I would say, are you doing, and this is overall I'm talking about. Overall, right. Total company guidance. So for the third quarter, I would expect it to go up slightly driven by good O'Bach and oil production growth.

Fair enough. Just to sneak one more in, the Yano, is it the number five well? Can you remind us what kind of production impact that will be on a net basis?

Yeah. So on a growth basis, it'll be between 8 and 10,000 barrels a day in the fourth quarter and we have half of that. So the net would be half of that.

Great. Thanks a lot.

Thank you. And our next question comes from the line of Jeffrey Campbell of TV Brothers. Your line is open.

Good morning. The press release mentioned improved well performance in the Bakken. I was just wondering, was this anticipated from the shift to plug and perf or was this something in addition to that?

No, I think this is really referencing the shift to plug and perf. And those are delivering, again, about a 15% increase in IP180 and a 5 to 10% increase in EUR versus our previous sliding sleeve design. And our whole program for 2019, on average, EURs are going to be about a million barrels. IP180 is between 120 and 125. And the RRs at 60, between 60 and 100% for the program this year. So a very strong program and we're extremely pleased with the results and the Bakken is doing very well. Okay, thanks.

And referring to the slide 21 of the May presentation, it discussed tighter well spacing for higher Bakken net present value for the drilling acreage. I was just wondering, have you settled on optimal spacing in your core areas or are you still testing closer spacing in certain areas?

No, I think the nine and eight configuration in the core, we're pretty settled on. I think the optimization that could occur is as you get down into tier two acreage, I'll call it, although it's all really good acreage, you might actually widen the spacing as you get out there. And why do I say that? Because our objective is to maximize BSU NPV. So it's going to be that equation of profit loading, well spacing, etc. to basically maximize BSU NPV. So you might change the well spacing. You may not be as tight as you go out into the other acreage.

Okay, if I sneak one last one in there, just going back to Hammerhead real quick, I was just wondering are there any further Hammerhead tests in the current plans or are the three wells that you've discussed sufficient to do? To determine next steps.

Yeah, I think we've got enough well data and evaluation data to determine next steps.

Okay, great. Thanks. Appreciate it.

Thank you. And our next question is from the line of Pavel Mokinulov of Raymond James. Your line is open.

Thanks for taking the question. It's not a huge part of your U.S. production mix, but you did have 17 BCF of gas last quarter. And in that context with Henry Hubb, you know, hovering around two bucks, obviously Bakken pricing is below that. What's the point where you might resort to shutting in wells?

No, Fred, we don't see us shutting in wells. So again, you know, a lot of what we have is associated gas with our Bakken wells. So we wouldn't be shutting in anything. Also,

you have to remember the Bakken gas stream has probably three times the amount of liquids in it than most other share wells. So as a consequence in the rest of the country, we're in a pretty good position to optimize our netbacks. Even though the natural gas price and NGL prices are down, they're still accretive to our overall netbacks.

Okay. And in that same context, what's your stance on flaring and the latest status update on that?

Yeah, we are well within regulatory requirements. And I think in particularly as LM4 south of the river gas plant comes on or joint venture with Targa, which is actually imminently on, that will substantially drop our flaring south of the river and we will be substantially below regulatory requirements at that point in time. So flaring is not an issue for us. It's not a problem for us, particularly with LM4. Okay.

Appreciate it.

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