赫斯 (HES) 2018 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the First Quarter 2018 Hess Corporation Conference Call. My name is Sonia, and I'll 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, Sonia. Good morning, everyone, and thank you for participating in our first quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.

Today's conference call contains projections and other forward-looking statements within the meaning of the Federal Securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC.

Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information that 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 first quarter conference call. I will review our strategy and key highlights from the quarter. Greg Hill will then discuss our operating performance and John Rielly will review our financial results.

Our company delivered strong performance this quarter and continues to make significant progress in our strategy: first, to grow our resource base in a capital disciplined manner; second, to move down the cost curve so that we are resilient in a low oil price environment; and third, to be cash generative at a $50 per barrel Brent oil price post-2020.

Our strategy reflects our view that shale alone will not be enough to meet the world's oil demand growth and offset base production declines. For the past several years, the industry has significantly underinvested in longer cycle projects, which currently represent approximately 90% to 95% of global oil supply.

We have focused our portfolio on 4 key areas: Offshore Guyana and the Bakken as our growth engines with Malaysia and the deepwater Gulf of Mexico as our cash engines. By investing in our highest return assets, divesting higher cost mature assets and implementing a $150 million annual cost reduction program, we expect to lower our cash unit production costs by 30% between 2017 and 2020, while reducing unit DD&A rates by 35% over the same period.

On a pro forma basis, production from our high graded portfolio is expected to grow at a compound annual growth rate of approximately 10% between 2017 and 2023. Assuming a flat $50 per barrel Brent oil price, operating cash flow is expected to grow at a compound annual rate of approximately 20% over the same period.

In 2017, our asset monetizations resulted in proceeds of $3.4 billion. Proceeds are being used to pre-fund our world-class investment opportunity in Guyana; the increase from 4 rigs to 6 rigs in the Bakken; return $1.5 billion to shareholders by the end of 2018 through share repurchases; and reduce debt by $500 million.

Key to our strategy is our position in Guyana, which represents one of the most attractive oil investment opportunities in the world today. The 6.6 million acre Stabroek block in Guyana, where Hess has a 30% interest and ExxonMobil is the operator, is uniquely advantaged by its scale, reservoir quality, cost, rapid cash paybacks and superior financial returns.

In February, we continued our exploration success in Guyana with a seventh oil discovery at the Pecora-1 well. This discovery followed positive results from the Ranger-1 well in January, which demonstrated that the petroleum system is working in a new geologic play more than 60 miles northwest of the Liza development, and reaffirmed the extraordinary exploration potential of the block.

Excluding Ranger and Pecora, estimated gross discovered recoverable resources on the block were increased to more than 3.2 billion barrels of oil equivalent and we continue to see multibillion barrels of additional exploration potential on the block.

The Liza Phase 1 development, which was sanctioned last June, is progressing well, with first production of gross 120,000 barrels of oil per day expected by 2020, less than 5 years after discovery. Phase 2 with gross production of 220,000 barrels of oil per day is slated for startup by mid-2022. The Giant Payara field is planned as a third development with startup expected in late 2023 or early 2024, bringing expected gross production from the first 3 phases of development to more than 500,000 barrels of oil per day.

Turning to the Bakken, our largest operated asset where we have more than 500,000 net acres in the core of the play, we plan to add a fifth rig in the third quarter and a sixth rig in the fourth quarter of this year. This increased activity is expected to generate capital efficient production growth, from 105,000 barrels of oil equivalent per day in 2017 up to 175,000 barrels of oil equivalent per day by 2021, along with a meaningful increase in free cash flow generation over this period.

Turning to our financial results, in the first quarter of 2018, we posted a net loss of $106 million or $0.38 per share, down from a net loss of $324 million or $1.07 per share in the year-ago quarter. Compared to 2017, our first quarter financial results primarily reflect higher realized crude oil selling prices and lower operating costs and DD&A.

First quarter production was above the high end of our guidance range of 220,000 to 225,000 barrels of oil equivalent per day, averaging 233,000 barrels of oil equivalent per day, excluding Libya. Bakken production averaged 111,000 barrels of oil equivalent per day, above our guidance of approximately 105,000 barrels of oil equivalent per day.

In summary, our focus for 2018 is on execution and we believe we are off to a very strong start to the year. In the first quarter, we increased cash returns to shareholders, reduced debt, exceeded our production guidance, continued to lower our costs and announced 2 significant oil discoveries offshore Guyana, Ranger and Pecora. Longer term, our reshaped portfolio is positioned to deliver a decade-plus of capital efficient growth with increase in cash generation and returns to shareholders.

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

Thanks, John. I'd like to provide an update of our progress in 2018 as we continue to execute our E&P strategy.

Starting with production. In the first quarter, production averaged 233,000 net barrels of oil equivalent per day, excluding Libya, above our guidance range of 220,000 to 225,000 net barrels of oil equivalent per day, primarily reflecting strong performance in the Bakken. In the second quarter, we expect production to average between 235,000 and 245,000 net barrels of oil equivalent per day, excluding Libya.

We maintain our full year 2018 production guidance of 245,000 to 255,000 net barrels of oil equivalent per day. Production is expected to grow steadily throughout the year, increasing to between 265,000 and 275,000 net barrels of oil equivalent per day in the fourth quarter, which represents a growth rate of over 15% between the first quarter and fourth quarter of 2018.

In the Bakken, we delivered a strong quarter that continued to build upon the successes of last year. First quarter production averaged 111,000 net barrels of oil equivalent per day, an increase of more than 12% from the year-ago quarter. Our 60-stage, 8.4 million pound proppant completions continue to show a 15% to 20% uplift in both IP-180s and EUR over our previous 50-stage, 3.5 million pound standard.

Because we were reaching the practical limits of the sliding sleeve system in terms of stage count, last year, we began piloting limited entry plug and perf completions and initial results are encouraging. This new limited entry technique allows us to more than double the number of distinct entry points in a 10,000-foot lateral, while maintaining good fracture geometry control and should result in a further increase in initial production rates, estimated ultimate recovery and most importantly, net present value.

While we only have a small number of wells that have been on production for 90 days or more, we are increasing the number of plug and perf completions and plan to complete approximately 40, and bring online 25 of these wells in 2018. We will keep you [appraised] of the results as we go throughout the year.

We're also conducting a comprehensive study of the Bakken to determine optimum development methodology for each area of the basin. As previously announced, we plan to add a fifth rig during the third quarter and a sixth rig during the fourth quarter. We also plan to add a third frac crew by the end of the year.

In the first quarter, we drilled 23 wells and brought 13 wells online. For the full year 2018, we expect to drill approximately 120 wells and bring 95 wells online. In the second quarter, we forecast that our Bakken production will average approximately 115,000 net barrels of oil equivalent per day and for the full year 2018, we forecast production to average between 115,000 and 120,000 net barrels of oil equivalent per day. Longer term, we continue to forecast steady Bakken production growth to approximately 175,000 net barrels of oil equivalent per day by 2021 assuming [sixth] rig.

Moving to the offshore. In the deepwater Gulf of Mexico, production averaged 41,000 net barrels of oil equivalent per day in the quarter, reflecting the previously announced downtime at the Shell-operated Enchilada platform following the fire there in early November 2017.

During the first quarter, production was restored at our Baldpate and Penn State Fields as well as at the Shell-operated Llano Field. Approximately 15,000 net barrels of oil equivalent per day of production remains shut in at our Conger Field but we expect Conger to resume production by the end of the third quarter.

At our Stampede Field, where Hess is operator and has a 25% interest, we achieved first oil from the field in January. We will continue to ramp up production gradually throughout 2018 and expect to achieve peak rates during 2019. Drilling will continue throughout this period.

For the second quarter, we forecast Gulf of Mexico production to average between 45,000 and 50,000 net barrels of oil equivalent per day and maintain our 2018 full year production forecast of approximately 50,000 net barrels of oil equivalent per day. By the fourth quarter, with all Enchilada-impacted 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 at the joint development area in which Hess has a 50% interest, production averaged 34,000 net barrels of oil equivalent per day in the first quarter. Production is forecast to average approximately 36,000 net barrels of oil equivalent per day in 2018.

At the North Malay Basin, also in the Gulf of Thailand, production averaged 22,000 net barrels of oil equivalent per day in the first quarter and is forecast to average approximately 26,000 net barrels of oil equivalent per day in 2018.

Now, turning to Guyana. At the Stabroek Block, in which Hess holds a 30% interest, we announced a seventh oil discovery at Pacora, located approximately 4 miles West of Payara. The well encountered approximately 65 feet of high-quality oil-bearing sandstone reservoir.

Following well operations on Pacora, ExxonMobil spud the Liza-5 appraisal well on March 8. The well has been logged and cored and the operator is currently performing a drill stem test. Results from the Pacora-1 and Liza-5 wells will be incorporated to appropriately size the FPSO for the third phase of development, which will be between 175,000 and 220,000 barrels of oil per day.

Following completion of the well test on Liza-5, the Stena Carron will drill the Long Tail-1 prospect, located approximately 4 miles northwest of the Turbot-1 discovery. A second drilling rig, the Noble Bob Douglas, spud an exploration well on the Sorubim prospect on April 3, which is located approximately 37 miles southwest of the Ranger discovery. Well operations are still underway. Following Sorubim, the Bob Douglas will begin drilling the first of 17 planned development wells associated with Liza Phase 1.

The Liza Phase 1 development sanctioned in June 2017 remains on track for first oil by 2020 with a nameplate capacity of 120,000 barrels of oil per day. Liza Phase 2 is on track for sanction by year-end with a nameplate capacity of 220,000 barrels of oil per day and first oil expected by mid-2020. The Liza Phase 3 development is in FEED, and first oil is expected in late 2023 or early 2024.

In Canada, offshore Nova Scotia, the Aspy well was spud on April 22. BP as operator 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. The well is targeting a large sub-salt structure, analogous to those found in the Gulf of Mexico.

In closing, our team, once again, demonstrated excellent execution and delivery across our asset base. The Bakken is on a strong capital efficient growth trajectory and Guyana continues to get bigger and better.

I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the first quarter of 2018 to the fourth quarter of 2017. We incurred a net loss of $106 million in the first quarter of 2018 compared with a net loss of $2,677,000,000 in the fourth quarter of 2017. Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $72 million in the first quarter of 2018 compared to a net loss of $304 million in the previous quarter.

Turning to Exploration and Production. On an adjusted basis, E&P had net income of $12 million in the first quarter of 2018 compared with a net loss of $219 million in the fourth quarter of 2017. The changes in the after-tax components of adjusted E&P results between the first quarter of 2018 and the fourth quarter of 2017 were as follows: higher realized selling prices improved results by $54 million; lower sales volumes reduced results by $133 million; lower DD&A expense improved results by $207 million; lower cash cost improved results by $40 million; lower exploration expense improved results by $32 million. All other items improved results by $31 million for an overall improvement in first quarter results of $231 million.

Turning to Midstream. The Midstream segment had net income of $28 million in the first quarter of 2018 compared to net income of $20 million in the fourth quarter of 2017. Midstream EBITDA before the noncontrolling interest and excluding specials, amounted to $123 million in the first quarter compared to $113 million in the previous quarter.

Turning to corporate and interest. After-tax corporate and interest expenses were $109 million in the first quarter of 2018 compared to $105 million in the fourth quarter of 2017.

After-tax adjusted corporate and interest expenses were $112 million in the first quarter of 2018. Capitalized interest in the first quarter was lower than the prior quarter by $21 million due to first production at the Stampede Field in January.

Turning to our financial position, we increased our share buyback during the quarter to $1.5 billion from $500 million, representing nearly 10% of shares outstanding. This, combined with our previously announced plan to retire $500 million in debt, allows us to maintain a strong balance sheet while providing current returns to shareholders.

Excluding midstream, cash and cash equivalents were $3.4 billion. Total liquidity was $7.7 billion including available committed credit facilities, and debt was $5,587,000,000.

In the first quarter, we purchased approximately 8 million shares of common stock for $380 million, which completed the initial $500 million program. In April, we entered into a $500 million accelerated share repurchase agreement that is expected to be completed by the end of the second quarter.

During the first quarter, we paid $415 million to retire debt including the redemption of $350 million principal amount of 8.125% notes due in 2019 and to purchase other notes. We remain on target to complete our $1.5 billion stock repurchase program and our $500 million debt reduction initiative in 2018.

Now turning to second quarter guidance. In the first quarter, our E&P cash costs were $13.46 per barrel of oil equivalent, which beat guidance on strong production performance and a deferral of a Tubular Bells workover to the second quarter. As a result of the workover deferral, cash costs for the second quarter of 2018 are projected to be $14.50 to $15.50 per barrel of oil equivalent, with full year guidance of $13 to $14 per barrel of oil equivalent remaining unchanged.

DD&A expense in the second quarter is forecast to be in the range of $17.50 to $18.50 per barrel of oil equivalent with the full year guidance remaining unchanged at $18 to $19 per barrel of oil equivalent. This results in projected total E&P unit operating cost of $32 to $34 per barrel of oil equivalent in the second quarter with the full year guidance remaining unchanged at $31 to $33 per barrel of oil equivalent.

Exploration expenses, excluding dry hole costs are expected to be in the range of $60 million to $70 million in the second 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 second quarter; and $625 million to $650 million for the full year of 2018, which is unchanged from prior guidance.

The E&P effective tax rate, excluding Libya, is expected to be a benefit in the range of 0 to 4% for the second quarter with the full year guidance of a benefit in the range of 0 to 4% remaining unchanged.

With respect to our 2018 crude oil hedges, we are now able to realize the benefit of WTI prices above $65, which we accomplished by buying back the $65 WTI call options within our crude oil collars. We continue to keep the $50 WTI put options on 115,000 barrels per day of production for the remainder of the year. We expect amortization of premiums on our crude oil hedges, which will be reflected in our realized selling prices, will reduce our results by approximately $45 million per quarter for the remainder of 2018.

We anticipate net income attributable to Hess from the Midstream segment to be approximately $30 million in the second quarter with the full year guidance of $105 million to $115 million remaining unchanged.

Turning to corporate and interest. For the second quarter of 2018, corporate expenses are estimated to be in the range of $25 million to $30 million, and interest expenses are estimated to be in the range of $85 million to $90 million. Full year guidance remains unchanged at $105 million to $115 million for corporate expenses and $345 million to $355 million for interest expense.

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

(Operator Instructions) Your first question comes from the line of Doug Leggate of Bank of America Merrill Lynch.

Mr. Hess, I wonder if you could opine on the latest thoughts on your disposal plans. And what was -- I have specifically in mind is, obviously, oil prices are a little healthy, and now Denmark appears, I believe, a process is underway. So if you could give an update, any expectations on timing. If I could ask you to also address Libya and the Utica and what's in the back of my mind is obviously, Marathon's sale in Libya. Are any other issues you think might contribute to noncore asset sales this year? I've got a follow-up, please.

Yes, Doug, the sale process for our Denmark assets is ongoing. So I can't say more than that right now. And while we obviously, can't comment specifically on the Total-Marathon transaction, in the normal course of business, we're always looking to high grade and optimize our portfolio. So that's what we'd like to say on Libya and for that matter on the Utica.

If I may, the one that's missing then, I guess is -- you talked previously about potentially dropping down some additional Midstream assets to the joint venture, but specifically Bakken water handling. Is that still the plan for 2018?

Yes, that's still the plan, Doug, that we do plan to have that done in 2018.

Can you give an order of magnitude as to what EBITDA associated with that is, John?

No, not at this point. So we are still putting together the assets that will be dropped and we'll be working with our partner, GIP. And I'll have to give guidance on that a little bit later in the year, Doug.

Okay. My follow-up, if I may, is probably for Greg, and it's exploration in Guyana. Greg, a couple of weeks ago, Exxon suggested that Sorubim would be completed last weekend, thereabouts. I realize you're not the operator but can you offer any color around what you might be seeing there in terms of the fact that it's taking a little bit -- it seems to be taking a little bit longer? And what's on my mind there is, Exxon suggested that in a success case, there was a possibility of bringing a third rig into the basin. So I'm just curious if that's consistent with your thoughts? And any color you can offer, and I'll leave it there.

Yes, Doug, thanks. I think the only thing we can say about Sorubim right now is that well operations are still underway. And as I said in my opening remarks, following Sorubim and then Bob Douglas is going to move and start drilling those development wells for Phase 1 and then, again, just to remind everyone we also have operations going on in Liza-5. Liza-5 has been logged, cored, and is currently undergoing a drill stem test. So that's sort of where we are on the block in terms of exploration and appraisal right now.

Do you have a connectivity result on Liza-5, yet, Greg?

No, we don't yet, Doug. It's early in the test sequence.

Our next question comes from Bob Morris of Citi.

Greg, on the Bakken, it seems that you're a bit more encouraged by what limited results you've had on the 200-stage plug and perf style completions here going forward. And remind me, I think those costs may be up to $500,000 per well more, and so you did just raise the EURs based on the 60-stage sliding sleeve. But what sort of uplift are you thinking about or anticipating to sort of make this the go-forward design in moving to the 200-stage plug and perf completions?

Yes, thanks for the question, Bob. In terms of the cost, first, we're early in this process and costs are running between $6.5 million and $7 million for those 200-stage 8.5 million pound proppant wells. But we believe that's going to come down as we apply lean manufacturing. Just like we did with sliding sleeves, as we apply lean manufacturing to that process, we know that we'll be able to bring those costs down. As I said, in my opening remarks, we really don't have any wells that we have plug and perf. We have 7 online right now, but we don't have any of their past -- their IP 90 dates. So it's a little bit premature. The results are encouraging but it's premature because we just don't have a statistical enough sample yet to be definitive about what the uplift is. It's positive but I don't want to get specific beyond that.

Now our plans are, because of the encouraging results, we are going complete 40 plug and perfs this year and will have 25 wells online by year-end. And as I also said in my opening remarks, that data was going to be critical for the study that we're conducting on the Bakken, which is really designed to, on a go forward basis, determine what now is the optimum methodology used -- to use for each area of the field as we think about further development of the Bakken.

Great. And my second question relates to that longer-term development plan. We've had several companies talk about what they refer to as parent-child love relationships in other basins where some operators have said that in the Bakken you actually see better performance from the infill wells versus the [pair well], because pair well was drilled so long ago with older technology. Are you able to discern any relationship in that regard? Or is that just sort of being masked or overshadowed by the continued improvement in the type of completions you're applying here in trying to assess whether there is some degradation at some point on infill wells, or is it just too hard to tell continuing to do better higher intensity completions?

Yes. I think in the Bakken, the performance just continues to get bigger and better with the improvements we're making in completion design. I will say, for us, because we drill half of the DSU at a time, we actually have no parent-child relationship because what we'll do is we'll go in and we'll drill half of the 1,280 and then maybe 12, 18 months later, we'll come back and drill the other half of the 1,280. So that really minimizes any interference at all. So there's no impact to us.

Our next question comes from Ryan Todd of Deutsche Bank.

Maybe first question on CapEx. It was relatively light in the quarter. How much of that was timing related, i.e., fewer well completions in the Bakken on the quarter? Are you seeing any continued efficiencies that could drive lower-than-expected CapEx for the year?

Right now, it's really timing. When we were early in the year that always happens with our CapEx program and, as you know, as Greg mentioned, so as we move to the year, we're bringing a fifth rig into the Bakken in the third quarter and then the sixth rig in the fourth quarter, and then also now, as Greg mentioned, we are going to have 2 rigs running in Guyana. So there is, as we move through the year, it was kind of more back ended on the CapEx. So again, everything is going -- the execution on the CapEx plan is going really well. But at this point, I would still tell you $2.1 billion for the year.

Great. And then maybe -- you touched -- obviously, we touched already on asset disposals. There have been and are a number of packages and -- may continue to be packages being shopped in the Bakken. Would you guys have any interest in acquiring additional resource in the Bakken? Or would you consider most of the deals as being dilutive relative to your current asset quality? Or what would you need to see to be interested in picking up additional resource there?

Look, we're always looking to optimize our portfolio. Having said that, anything that we could potentially acquire would have to compete with the high-return projects we already have secured in our portfolio between the Bakken and Guyana; and thus far, we haven't seen any package in the market that would compete favorably in terms of what we have already under our feet.

Our next question comes from Brian Singer of Goldman Sachs.

On costs, can you discuss progress towards your cost reduction targets and milestones that you and we should be looking for? And can you also discuss the service cost environment in the Bakken as you add the 2 rigs and 1 crew?

Sure. Brian, I'll start on the cost reduction program. It is going along according to our plan. I mean, you could see from the -- as a milestone, we did have the severance charge in the first quarter. As I mentioned, from a headcount standpoint, there's approximately 400 employees and contractors affected by the reduction in force. Now not all, it's a little bit above 65% of those employees have left the company in the first quarter. And so there will continue to be reductions in force as we move through the year.

As far as other aspects of our plan, I mean, we're starting here in the first quarter, and what I would tell you with our plan, we expect to have everything done by the fourth quarter. And then in the fourth quarter, combined with the Enchilada field and Conger coming back online and our increase in the Bakken, you should begin to see the effects of our $150 million cost-reduction program as well as the investments in our higher return assets driving our cost lower.

Brian, in terms of the cost trends in the Bakken, cost trends are expected to increase anywhere from 5% to 15% versus last year, depending on which commodity line you're talking about. But we've taken steps to contain those costs by locking in rig rates, putting in place longer-term contracts and forming strategic partnerships with our key suppliers. So the steps we've taken, coupled with our lean manufacturing approach, we're pretty confident that we can deliver our 2018 program with minimal inflation.

Great. And then my follow-up is, you mentioned that I think you bought back the portion of the hedges collars that now give you exposure to that oil price upside above $65. I may have missed if you mentioned if there was a cost to do that or an effective dollar barrel to do that. But now that there is more exposure to the upside to the degree that oil prices do stay here or move higher, can you talk about how that impacts capital allocation either in terms of using that cash for incremental share repurchase or a debt paydown or reinvesting in the business?

Yes. Right now, obviously, we're keeping the downside protection but we felt it prudent in the current oil environment to buy those [calls] back. John can talk further on the cost of that. So we will benefit and our shareholders will benefit in the higher oil price environment that we're in. And again, our priority #1, #2 and #3 is to fund Guyana and future capital requirements, not just for FPSO 1 but FPSO 2; and also the engineering for FPSO 3, continue the exploration and appraisal program. And in that -- and move up to 6 rigs in the Bakken. In that it's really important and we've talked about this before to keep a strong balance sheet and cash position. So incremental cash right now, we'll just be keeping the balance sheet strong for the funding requirements that we see going forward.

In terms of any further share repurchases to be contemplated, one, let's finish the $1,500,000,000 program we have, which we will do this year; and two, as we look into next year, we'll see where our capital requirements are, specifically on Guyana. We'll see where the oil price is, and at that time, we can give consideration to further return of capital to shareholders.

John, you might want to talk about the other.

Sure. On the cost of the buying out the call options, it was approximately $50 million. Now in my guidance that I gave, that is reflected in the amortization of the premiums on our hedge contracts. So as I mentioned, so for the next 3 quarters of 2018, the results will be reduced by $45 million a quarter due to the buyout of those call options.

And our next question comes from Paul Cheng of Barclays.

Quick question. On the Bakken, Greg, have you seen any cost inflation really start to picking up? I mean, Permian, we heard that they have difficulty getting enough staff or equipment there. When they start to see some other area, they are moving the equipment and people there. So how is that looking in the cost and the availability of the equipment? And also, when you are talking about Bakken, can you also talk about -- you're saying that you're going to reach 175,000 barrel per day on -- by 2021. Is that the [pathway], or that's subject to, say, other factor that you may change, what is the [path]way?

Well, first of all, on the cost trends -- Paul, thanks for the question. As I responded to the last person, we do expect cost trends to increase by some 5% to 15%, very different than the Permian simply because if you look at the rate of growth of rigs in the Bakken, it's much smaller than it is in the Permian. So it's kind of onesie, twosie, I'd say, people growing by 1 or 2 rigs. So the rate of increase is not as substantial.

Now, we've taken a lot of steps to contain those costs by locking in some rig rates, putting in place longer-term contracts, forming strategic partners with our key suppliers. And we're pretty confident that the steps we've taken and our lean manufacturing approach is going to enable us to deliver our 2018 program with minimal inflation. There will be some, but it will be minimal. We think we can cover most of that. So very different than the Permian.

Regarding the 175,000 barrels of oil a day in 2021, that's -- the only assumption in there is that we maintain 6 rigs for the next couple of years to get us to the 175,000.

But should we look at it from a resource standpoint? And logistically that, that will be the sweet spot you're going to get to 175,000 and you're just going to sustain at that level for a number of year? Or that may change also? So I'm trying to understand what you guys have in mind in targeting.

Yes, I think at this point the 175,000 is -- appears to be the sweet spot, then we can maintain that for several years in the Bakken. And of course, that's a combination of infrastructure build out and whatnot, and that's why the 175,000 appears to be a sweet spot. The only caveat I will put on that is we are conducting this comprehensive Bakken study this year and so depending on the outcomes of that study, that could dictate how long you hold that peak, how fast you get there, some other factors. So that's the only caveat I'd put on that.

And going back into the [cost], have you seen people and the equipment being moved out from Bakken into Permian?

Not -- certainly it hasn't affected us at all. And that's all that I'm concerned about, is that it doesn't affect us.

Okay. And for John Rielly, the second question on the unit DD&A. Why from the first quarter to the second quarter you would jump that much?

So from the guidance that we gave, you remember, Paul, since we're giving the guidance ex-Libya on there. So if you're looking at actual cost that we had in the first quarter going into our second quarter guidance. So without Libya, right? Our production is going to be lower, our cash costs are going to be lower and our DD&A -- I'm sorry, our cash cost will be higher and our DD&A will be higher and then our tax rate will be lower. So there's really no change. If you want to say quarter-on-quarter for the DD&A, it's just from a guidance purposes, we don't have Libya in there.

Okay. So that if I -- so maybe then -- let me ask then, in the first quarter, if you're excluding Libya, what was the cash cost and the unit DD&A?

So you can add about $1.50 to the DD&A rate, and you can add about $1 to the cash cost.

I see. So that's why you're saying that sequentially it's really not such a big difference anyway.

Correct, correct.

Our next question comes from Roger Read of Wells Fargo.

Just to kick a little harder on the Bakken on the kind of the service cost and just what's going on there in terms of productivity. Are you seeing pressure on the pricing side? I know the question was asked about kind of labor and so forth, but any general pressure on any part of the service sector there for you?

Yes, I think, as I said before, that the cost trends are expected to increase 5% to 15%, depending on the commodity line. You're talking about on the upper end would be the pumping services. On the lower end, it would be the sand and kind of other commodities. So -- but again, with the steps we've taken by locking in the rig rates, putting in place longer-term contracts, forming strategic partnerships with our key suppliers and lean manufacturing, we think that we can execute our '18 program with relatively minimal inflation.

Okay. And then switching gears a little bit. Your -- the Gulf of Mexico has come back a little quicker than expected. I know you still are predicting the last part of it or budgeting the last part of it for late September, but is there a rational way to approach that or a reasonable way to approach that, that it could on a little bit quicker, just sort of going by what the operator has been saying?

Yes. So I think as we said, the instantaneous weight that was off at the end of the year was 30,000 barrels a day. Half of that came on in the first quarter, in March. The other half we're projecting to be on by the start of the fourth quarter. The operator is still forecasting kind of June, July sort of a time frame. So, yes, there could be a little bit of upside but obviously that depends on weather and all kinds of factors. So we've got a little bit more conservatism built in, given it's a brownfield project, and we'll just see kind of where we end up.

Okay. And then just last question on the Sorubim well. If I remember correctly, it's sort of a different structure than what we saw with Payara, so the fact that it has taken a little longer to drill that, I would assume, makes sense or was within the budgeted expectations?

Yes, it's definitely within the budgeted expectations, and yes, it was a different -- it is a different play type. It's on-lapping sediments onto a carbonate shelf margin, so...

And just -- I can add just from a cost standpoint, because that is some of the benefits of drilling exploration wells in Guyana. Just a typical exploration well there is -- our gross well cost is around $50 million, so net to us is about $15 million. So that's kind of a typical exploration well there.

Our next question comes from Guy Baber of Simmons & Company.

So the Bakken production during the quarter obviously seemed especially strong in light of you guys only bringing on 13 wells. Some of the plug and perf wells likely contributed, but can you talk a little bit more about the outperformance? And how well productivity is shaping up relative to what is assumed in the full year production guidance of 115,000 to 120,000? It just appears that, that guidance might be a little bit conservative due to what you guys delivered in 1Q, and the schedule and the number of wells you're planning to bring on in the rest of the year.

Yes, just a -- thanks for the question. A couple of comments. First of all, the first quarter was strong, and that was mainly driven by drilling wells in Keene, which is really our best area of the field. So that mix changes as you go throughout the year. But Keene performed particularly well during the first quarter. And in our investor pack, we show the IP 180s in Keene and Stony Creek and East Nesson and Capa. And we've said, those IPs are north of 100,000 barrels of IP 180s, north of 100,000 barrels.

Keene has come in exceptionally strong. So if you weight-average that and assume that Keene's going to continue to perform, our IP 180s for the year will actually be some 15% to 20% higher than what's in our current investor pack, and that's a step up from last year, as we said, of 10% to 15%. So yes, there is upside, driven mainly by Keene. If you look at East Nesson South, Stony Creek and Capa, they're coming in about where we expected, but Keene has really outperformed. So very strong performance from Keene.

As I said, the plug and perf wells, we just don't have enough to be statistically significant. There's only 7 online, none of which have gone beyond IP 90. So it's just early days on that but it is encouraging. So there is a little bit of additional volume associated with those plug and perf wells.

That's helpful. And then you all have been clear that the top priority for capital is prefunding Guyana. I was just hoping you could shed a little bit more light on the longer-term plan there, and specifically how you see the balance of cash inflow versus CapEx shaping up over time, especially with 3 phases happening and the discovered resource to do much more than that. But you all have highlighted rapid cash payback there; cost recovery will help, I'm sure. But can you just talk through maybe in a little bit more detail or give us a framework as to at what point Guyana actually becomes self-funding or begins to generate excess cash flow on kind of base case expectations or plans?

Sure. So the way -- as we mentioned in the scripts earlier, Phase 1 Exxon is planning to bring on by 2020. When that production comes on, we're beginning to pick up significant cash flow but Guyana itself is going to be still maybe more in a breakeven to maybe a slight deficit as we go forward with Phase 2 and Phase 3 capital. Then what happens when Phase 2 comes on -- and remember that's a bigger FPSO, 220,000 barrels per day -- when that comes on, and let's just say, it's 2 years for now, somewhere mid-ish 2022 just for an assumption standpoint, Guyana begins to throw off significant free cash flow at that point in time. So our production with our 30% share in there gets over 100,000 barrels a day, once that ship comes on and Guyana then -- basically that supports all future capital in Guyana once the Phase 2 production comes on.

Great, that makes sense. And then I had one more follow-up one the 1Q cash flow number, but the pre-working capital cash flow number looked very strong, but obviously, there were some meaningful working capital headwinds that you all called out. You had a large working capital drag last year, but with the divestment of some of your cash-consuming assets, we'd expected that issue to maybe go away this year. So can you talk a little bit more about the extent to which some of these issues that affected 1Q bottom line cash flow may or may not persist going forward?

Sure. So what we have in the first quarter, I'm going to -- let me just first talk about kind of if you want to call it normal but still nonrecurring-type pulls on working cap in the first quarter. So as we said, it was a reduction in accounts payable and accrued liabilities. What happens in the first quarter, typically most companies were paying our bonuses in the first quarter. So you're accruing through the year and then you're paying that bonus. So you have that always in the first quarter, and then in our first and third quarters is where we pay basically semiannually then the interest payments on our public bonds. So typically you will see any -- a type of working capital pull for interest payments in our first and third quarter.

Then the other one now -- this is not recurring, I mentioned earlier -- was we bought our call options on the WTI. So that was approximately $50 million. That will not recur.

And then the only other thing I need to remind everyone on is we are still going through kind of the remnants of our portfolio reshaping and we are going through a cost reduction program. So for example, we have that severance, we will be then paying severance off in the remainder of the year. So you're going see still some remnants of that portfolio reshaping. And that's why I like to say, as I mentioned earlier, by the fourth quarter, we'll have gotten through our cost reduction program and all that benefits will begin to be shown through as you see in the fourth quarter and then into '19. So again, no -- nothing unusual except for the -- really the buyout of the WTI call options, and then further transition costs you may see through the year.

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

I just wanted to follow up on a couple of things. First, in the Williston, I think there's some tighter flaring regulations coming in the back half of the year. How are you guys set up to handle that? And then second, in the second quarter on that, 115,000 MMBOE a day, what's the expected wells put to sale to support that?

Okay, so on the first question, we don't have any issue with the flaring regulations coming up, we're set up well for that. Why? Because we have a 250 million cubic feet capacity at Tioga Gas Plant, that can be expanded to 300 million for very little capital. We won't need that this year but that's certainly an option out in the future. Q1 processing volumes were 214 million so you can see that we've got room to go there.

And then secondly, thinking ahead, we're adding 100 million cubic feet of net capacity south of the river at the Targa JV that our Midstream announced. So because of those reasons, we'll be set up well for handling any flaring constraints. And on your second question was related to wells, is that correct?

Yes. Just how many wells do you expect to have turned to sales in the second quarter?

Yes, our current forecast is to have 23 wells online in the second quarter versus 13 in the first quarter.

Okay. And then, I guess, the other follow-up then, just uses of capital in this more elevated commodity environment. What would you say a targeted debt level would be on a dollar basis as you look towards 2019, 2020, just kind on a longer-term basis as you enter the full Guyana development phase?

Our plan is that we can fund -- so we set up through our asset sale program that we prefunded Guyana. So we do not intend to go to the debt markets for any additional requirements for Guyana or for anything else that we have. So we're set up from a prefunded standpoint, so you could expect our debt level to stay where it is after we finish our debt reduction initiative.

Yes. I guess, I was thinking the other side. Are there any further debt reduction targets that you think there are on a longer data basis?

As John Hess mentioned earlier, so what we'll do is as we finish out this debt reduction plan, the $500 million and our stock buyback of $1.5 billion, as we'll finish that out, again, our priorities are to make sure that we have Guyana prefunded because that's truly transformational; and then maintain a strong balance sheet, so we want to be investment grade, maintain that investment grade balance sheet; and then excess cash beyond that we will be considering for stock buybacks or debt buybacks at that time.

Our next question comes from Pavel Molchanov of Raymond James.

You've been asked about costs in the U.S., I would kind of expand that to what you're seeing in the offshore arena. So as you're contracting for new rigs or development equipment in Guyana, how are those costs tracking relative to your original expectations from when Liza project was originally sanctioned a year ago?

Great. Thanks for the question, Pavel. The deepwater offshore market continues to be oversupplied given the extended period of low activity that John talked about in his opening remarks. And as a result, we expect to see minimal, if any, cost inflation. In terms of Guyana Phase 2 versus Phase 1, costs are coming in lower, actually lower than for Phase 1, for most of the commodity line. So again, you're seeing that continued oversupply reflect itself in Guyana Phase 2 as well.

Okay, that's helpful. And then quick one about the dividends. So it's been about 5 years since you've taken that down to $0.25 a quarter. Is that at all on the agenda as far as an increase goes alongside the buyback that you're implementing?

On the dividend itself, that -- we would want to see us being cash flow generative with our current capital requirements and our current dividend on a recurring basis for us to consider going up on that. We're not quite there yet. Obviously 2020, we start seeing our company being cash flow generative in a $50 world on a recurring basis. So at that time, we consider what's the best way to enhance return of capital to shareholders. And obviously, I talked earlier about how we're thinking about next year in terms of capital through share repurchases based upon funding Guyana and keeping a strong balance sheet and cash position for future phases of Guyana and obviously, the oil price environment. So that's sort of how we think about return of capital.

Our next question comes from Michael McAllister of MUFG Securities.

My question is about the Bakken. The scenario you're kind of presenting is looking like 50% increase in rigs could lead to a 30% increase in wells tilled for 2019?

So, again, yes, we are taking the rig count up. We'll add a fifth rig in third quarter and a sixth rig in fourth quarter. So that's true; our actual wells online will go up in 2019 relative to 2018.

And can I take that further to say that production would be or could be 20% to 25% higher?

Well I think, again, thinking about where we are on the road to 175,000 in 2021, you're right, the rate of increase will go up in 2019 as a result of that higher number of wells online.

Okay. And then to 2019, any thoughts on hedging at these prices?

So we will be -- we continue to look at our hedging program. We've made some changes as you know in '18. As of right now, we don't have any hedges on in 2019, we're continuing to look at it. Obviously the curve is a bit backwardated, and when you're this far from 2019, it is expensive on that time value with the volatility. So at this point, we haven't had anything but we will continue to look at that. And then obviously, as we continue move up, as Greg was saying with the Bakken increasing production or production increasing next year, we don't have as much of a cash deficit as you move into 2019, and we don't have a funding deficit at all because of the asset sales. So any hedging we probably do would not be at the same level. We did in '18, but we'll continue to look at putting hedges on in '19.

Our next question comes from Arun Jayaram of JPMorgan.

Greg, I was wondering if you could just maybe comment a little bit more on the study you're doing in the Bakken to determine the optimal development methodology and just give us a sense of what you're looking at and how could things potentially change?

Yes. So I think it's an -- it's the right time to do the study in the Bakken because the Bakken is at an inflection point. We're adding rig count, we're changing -- potentially changing methodology on completion type, and so it's a good time just to step back and say, okay, given that plug and perf looks like it's coming into the mix, how do we think about our development methodologies for various parts of the field? What's that mean for the core? What's that mean for outside the core? What's that mean for well spacing? Does that change our thinking on well spacing? All of these factors are going to go into the study to really define in the back half of the year, what is our revised development methodology going forward in the Bakken. So it's really a good time to do it because we have more DSUs in the core than anyone else. We're stepping up the rig count, so it's time to just step back and really think thoughtfully where -- how we want to take this asset forward.

And results would be later this year or something like that?

Yes, it will be. I think we've talked about in Investor Day, fourth quarter of the year, we'd obviously share result of that in the Investor Day.

Great. And just my follow-up. It sounds like results in 1Q in the Bakken outperformed, just given a bit of the results at Keene. Could you talk a little bit about the mix of Keene versus outside of Keene for your 2018 completions? And would you think that your overall Bakken guidance is conservative just given the performance at Keene?

Again, it's early in the year and Keene did outperform, and if you look at our program, so of the 95 wells that we've guided to be online this year, 40 of those wells are in Keene, 25 of those are in Stony Creek, 20 are in East Nesson South and 10 are in Capa. And if you look at our investor presentation, we actually showed the EURs and the IP 180s for each of those areas. As I said, Stony Creek, East Nesson South and Capa are coming in at about what we expected, but Keene is one that's really so far outperforming this year.

Our next question comes from John Herrlin of Societe Generale.

Following up on what you were saying on the Bakken, Greg. Does this mean you're trying to better -- your space densities? Or should we assume that given the results of your study down the line that it may go to longer wells in terms of the completions?

Yes, I think -- John, thanks for the question. I think all of that is part of what the study will look at. As you know, we've been developing the Bakken on very tight spacing and so fractured geometry control is really, really important given that you are on tight spacing. With limited entry plug and perf now, the methodology is such that you can get tighter fracture geometry control but also a lot more entry points in the wellbore. So if that's true, that could affect your well spacing assumption. But way too early to predict what the outcome is going to be, that's one of the elements of the study that we'll be looking at. And it could vary depending on where you are on the field. Because obviously, in the core you've got a lot more natural fracturing that's helping you out, as you get outside of the core you don't have as much. So all these things will be part of this study that we're looking at in the Bakken with the ultimate objective to maximize DSU and overall NPV for the Bakken asset.

Great. Then I wanted to follow up on Guyana. I was able to see cores the other day with Exxon and looked to me like the reservoirs weren't super well cemented, it looked like calcite cement, were you at all surprised by that?

Not really, no. And again, it's -- these wells are going to produce like gangbusters, as you know, just based on your look at the core. So we weren't surprised by it and we're not particularly concerned about it.

No, I don't think it was a concern, I just -- I thought it looked like great rock, that's all.

Our next question comes from Phillip Jungwirth of BMO.

I think that the Penn State well in Gulf of Mexico is expected to be brought online in March, and I was just curious if there's any update here on timing and also the rate of that well.

Yes, so the well did come on in March as planned and we're currently in ramp up operations on that well. Just like Stampede wells we're bringing these wells on slowly in the Miocene, adjusting the chokes slowly. That well is expected to be in the range of 5,000 to 10,000 barrels a day once it gets to full choke.

Okay, great. And then on the Bakken, you'd talked about this asset as you need to be a free cash generator to the corporation, just looking at 2018 and maybe 2019, do you have a sense for where the free cash flow profile of this asset would be at current oil prices? And how that can influence the decision to move beyond 6 rigs plan for year end?

Sure. Again, at this point, we are just planning on the fifth and sixth rigs being added in the second half of the year with where prices, even with prices lower, the Bakken was going to be generating a little free cash flow in 2018, and that's again, because when you bring on the fifth and sixth rigs, you're really not getting any production from those rigs yet that goes into '19. Then as we increase production and with '19, '20, and getting up to 175,000 barrels a day, and obviously holding 6 rigs, the Bakken will generate significant cash flow, a lot in '19 and even more in 2021, and that as -- we've always said in the near term that's what's driving us to be able to be free cash flow positive at $50 Brent post-2020, and then it's when Guyana and really that Phase 2 comes in that really continues to drive up our free cash flow. So at this point in time, we -- there is no plans to go above the 6 rigs or 175,000 barrel a day. But a target is on that 6 rigs, but as Greg said, we are looking, we're doing a study and we'll let you know if we make any changes, but at this point in time, there's no change to our 6 rigs.

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