赫斯 (HES) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the First Quarter 2017 Hess Corporation Conference Call. My name is Vince, and I will be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

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

Thank you, Vince. 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 provided on our website.

As you know, Hess Midstream Partners LP completed its initial public offering earlier this month. Please be aware that even though the IPO is closed, we are still restricted by Securities Laws in what we can say about Hess Midstream Partners at this time. As such, our remarks today about Hess Midstream Partners will be very limited. We expect that Hess Midstream Partners will file its 10-Q for the first quarter of 2017 in May.

Now as usual, with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I will now turn the call over to John Hess.

Thank you, Jay. Welcome to our first quarter conference call. I will review the progress we are making in executing our strategy as well as highlights from the quarter. Greg Hill will then discuss our operating performance and John Rielly will then review our financial results.

Our company has had more than a decade of visible growth -- production growth secured with an expanding resource base, declining operating and development cost and strong leverage to oil prices, all of which should improve our financial returns and create significant value for our shareholders. Production growth, which is set to resume beginning in the second half of 2017, is underpinned by the Bakken, the North Malay Basin and Stampede developments and offshore Guyana, where we have participated in one of the industry's largest oil discoveries in the past 10 years.

Key to funding these growth projects is a strong balance sheet. With $2.7 billion of cash and total liquidity of $7.2 billion as of March 31, our financial position remains strong. To provide insurance for oil price uncertainty and our increasing activity levels, we have hedged 80,000 barrels of oil per day for the balance of 2017, utilizing a put-call strategy that provides a floor of $50 per barrel for WTI and $55 per barrels for Brent, while retaining $20 per barrel upside from those price levels.

To unlock additional value, earlier this month, we successfully completed the initial public offering of Hess Midstream Partners LP. The transaction, priced at $23 per unit, well above the indicated pricing range of $19 to $21 per unit. As a result of strong demand, the transaction was upside by 20%, resulting in net proceeds of $350 million to our Bakken Midstream joint venture with a $175 million attributable to Hess Corporation. In addition, the MLP provides another attractive long-term funding vehicle for our company.

With regard to our growth projects. In the Bakken where we have a premier acreage position in the core of the play, we added a third operated rig in March, a fourth rig in April and plan to add 2 additional rigs in the fourth quarter. In Malaysia, the Hess operated North Malay Basin development, in which Hess has a 50% interest, is expected to come online in the third quarter and add in excess of 20,000 barrels of oil equivalent per day, becoming a long-term cash generator for the company.

In the deepwater Gulf of Mexico, the Hess operated Stampede development, in which Hess has a 25% interest, is on track to start up in the first half of 2018. After which, production is expected to ramp up to 15,000 barrels of oil equivalent per day. Offshore Guyana, in March, our partner ExxonMobil announced another discovery at the Snoek prospects on the Stabroek Block. This oil discovery is additive to those at Liza, Liza deep and Payara, which have an estimated recoverable resource range of between 1.4 billion and 2 billion barrels of oil equivalent. Also, we see numerous additional exploration prospects on the block that collectively offer multibillion barrels of unrisked upside potential.

Planning for the development of the greater Liza area is underway with final investment decision and project sanction of the first phase expected midyear 2017 and first production by 2020. The development concept for Liza Phase I is based on a floating production, storage and offloading vessel or FPSO, that will process approximately 120,000 barrels of oil per day produced from 2 subsea drill centers. Liza Phase I offers attractive project economics down to $40 Brent flat. The greater Liza development has the potential to be transformational for our company and positions us for more than a decade of material reserve and production growth and improving financial returns and cost metrics.

Now with regard to our financial results. In the first quarter of 2017, we posted a net loss of $324 million or $1.07 per share compared to a net loss of $509 million or $1.72 per share in the year-ago quarter. Compared to 2016, our first quarter financial results were positively impacted by higher crude oil selling prices and lower operating cost and exploration expenses, which more than offset the change in deferred income taxes and lower production volumes.

With the activity increasing in 2017, our focus is on execution in terms of delivering production, progressing our offshore developments and continuing to drive cost reductions and efficiencies. First quarter production was above our guidance range, averaging 307,000 barrels of oil equivalent per day, excluding Libya, driven by strong performance across our portfolio. Bakken production averaged 99,000 barrels of oil equivalent per day, above the high end of our guidance range, despite challenging weather conditions during the quarter.

In summary, with our strong financial and liquidity position, oil leverage portfolio and exciting growth opportunities, we believe the company is well positioned to deliver strong cash flow growth and compelling long-term value for our shareholders.

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

Thanks, John. I'd like to provide an update on our progress in 2017 as we continue to execute our E&P strategy. Starting with production. In the first quarter, we averaged 307,000 net barrels of oil equivalent per day, excluding Libya, which was above our guidance range of 290,000 to 300,000 barrels of oil equivalent per day on the same basis, reflecting strong operating performance across our portfolio.

Regarding second quarter guidance, we expect net production to average between 275,000 and 285,000 net barrels of oil equivalent per day, excluding Libya, which is a 500,000 barrel per day increase versus our previous guidance. The second quarter is lower than the first quarter primarily due to planned seasonal maintenance in the offshore. However, the third quarter will be a major inflection point for production as positive momentum returns to our portfolio with North Malay Basin coming on stream and Bakken production ramping as a result of the increased rig count. Our full year 2017 production guidance remains 300,000 to 310,000 barrels of oil equivalent per day. But as usual, we will provide an update to full year guidance on our midyear call in July.

Turning to onshore operations for the quarter. In the Bakken, we recovered quickly from the temporary operational impacts of extreme weather conditions over December and January to average 99,000 barrels of oil equivalent per day in the first quarter, beating our guidance of 90,000 to 95,000 barrels of oil equivalent per day, while bringing online some of the highest IP rate wells that we have seen to date.

We continue to see outstanding results in the Bakken driven by high well availability and improved well performance from our 50-stage completions. We are seeing a consistent 15% to 20% increase in well productivity as a result of the shift to 50-stage completions from our previous 35-stage standard design. As discussed on our last call, we continue to trial higher stage counts and higher proppant loadings. While still early days, we are encouraged by initial results. We will gather additional production and cost data from these tests in the coming months and we'll provide an update on our July call.

In March, as John noted, we added a third operated rig in the Bakken and April a fourth, and we currently plan to add 2 further rigs in the fourth quarter. During the first quarter, we drilled 11 wells and brought 8 new wells online. This compares to the year-ago quarter when we drilled 19 wells and brought 31 wells online. In 2017, we still expect to drill approximately 80 wells and bring approximately 75 new wells online. For the second quarter, we forecast net Bakken production to average approximately 100,000 barrels of oil equivalent per day.

In Libya, we were able to complete a lifting in March and the asset contributed net production of 4,000 barrels of oil equivalent per day in the quarter. Despite the resumption of production, the political situation in the country remains uncertain and therefore, we continue to exclude Libya from our forecast.

Moving to offshore. In the deepwater Gulf of Mexico, net production averaged 66,000 barrels of oil equivalent per day in the quarter. In the second quarter, a 34-day shutdown is planned for the Conger Field and a 44-day shutdown is planned for the Llano Field, which should result in our Gulf of Mexico production averaging between 50,000 and 55,000 barrels of oil equivalent per day in the quarter.

In Norway at the Aker BP-operated Valhall Field, in which Hess has a 64% interest, drilling resumed in March from the platform rig and we expect the first well to come online in the fourth quarter. A further 11-day shutdown is planned in the second quarter at the Okume Complex in Equatorial Guinea. Net production from Equatorial Guinea averaged 31,000 net barrels of oil equivalent per day in the first quarter.

For offshore developments. At North Malay Basin in the Gulf of Thailand, in which Hess holds a 50% interest and is operator, we are now in the final phases of the full field development. The central processing platform was successfully installed in March and hook up and commissioning is progressing according to plan. The 3 remote wellhead platforms have been hooked up and commissioned. The FSO is scheduled to sail out during the second quarter, and all of the 14 wells planned for full field startup have been completed. Once full field development is completed in the third quarter of this year, we expect net production to build fairly rapidly to approximately 165 million cubic feet per day, becoming a significant long-term cash generator for the company.

At the Stampede development in the Gulf of Mexico, in which Hess holds a 25% working interest and is operator, we successfully completed the first production well and have spud a second well. Sail away of the tension leg platform and the commencement of installation are scheduled for the second quarter. First oil remains on schedule for the first half of 2018.

Now turning to Guyana. In the Stabroek Block, in which Hess holds a 30% interest, the operator, Esso Exploration and Production Guyana Limited, announced that the Snoek well, located approximately 5 miles Southeast of the Liza-1 discovery well, resulted in another oil discovery. The well encountered more than 82 feet of high-quality, oil-bearing sandstone reservoirs. The rig has now moved back to Liza to drill the Liza-4 appraisal well, which spud on March 31. This well is designed to further evaluate the significant Liza oil discovery and help define the full field development plans.

ExxonMobil estimates gross recoverable resources for the greater Liza area to be in the range of 1.4 billion to 2 billion barrels of oil equivalent, which is expected to support multiple phases of development. The Liza-4 and Payara-2 appraisal wells will evaluate the high side of this range. We plan to continue to progress exploration of the lighter Stabroek Block in 2017 and 2018, on which we see numerous remaining prospects across multiple play guides representing multibillion barrel unrisked upside potential. We expect to sanction the first phase of development of the Liza Field around midyear. This development is expected to be configured for gross production of approximately 120,000 barrels of oil equivalent per day, with first oil expected by 2020 and will generate attractive project economics down to $40 Brent flat.

In closing, we have once again demonstrated excellent execution and delivery across our portfolio. With an attractive mix of captured short and long cycle opportunities and top quartile operating capabilities, we are well positioned for a decade of value driven reserve and production growth.

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 2017 to the fourth quarter of 2016. In the first quarter of 2017, we reported a net loss of $324 million compared with an adjusted net loss of $305 million in the previous quarter.

Turning to E&P. E&P incurred a net loss of $233 million in the first quarter of 2017 compared to an adjusted net loss of $256 million in the fourth quarter of 2016. The changes in the after-tax components of E&P results between the first quarter of 2017 and adjusted results for the fourth quarter of 2016 were as follows: Higher realized selling prices improved results by $34 million. Lower sales volumes reduced results by $14 million. Lower cash operating cost improved results by $44 million. Lower exploration expenses improved results by $19 million. Lower midstream tariffs improved results by $15 million. Changes in effective tax rate reduced results by $89 million. All other items net improved results by $14 million for an overall improvement in first quarter results of $23 million.

The E&P effective income tax rate was a benefit of 13% for the first quarter of 2017 compared with a benefit of 43% in the fourth quarter, excluding items affecting comparability and Libyan operations. The lower effective tax rate in the first quarter is due do not recognizing a deferred tax benefit on operating losses in the U.S., Denmark and Malaysia as previously discussed when we provided 2017 guidance. For the first quarter, our E&P sales volume were underlisted compared with production by approximately 1.4 million barrels, which did not have a material impact on our results.

Turning to midstream. In April 2017, the Corporation and its partners successfully completed the IPO of Hess Midstream Partners, and we received our net share of proceeds totaling $175 million. The IPO transaction had no impact on the Midstream segment first quarter results, but has been incorporated into our updated guidance for the remainder of the year.

In addition, as we previously announced, commencing January 1, 2017, our Midstream segment now includes the corporation's interest in the Permian Basin gas plant in West Texas and related CO2 assets and our wholly owned water handling assets in North Dakota. We have recast all prior period financial information to include these assets and the results as part of the Midstream segment. In our first quarter supplemental earnings information presentation located on the Hess website, we have provided quarterly consolidated income statements for 2016, recast to reflect the transfer of these assets from the E&P to Midstream.

In the first quarter of 2017, the Midstream segment had net income of $18 million compared to adjusted net income of $23 million in the fourth quarter of 2016, which included the recognition of a full year of deferred minimum volume deficiency payments earned at year-end 2016. EBITDA for the Midstream before the noncontrolling interest amounted to $94 million in the first quarter of 2017 compared to $102 million in the fourth quarter of 2016.

Turning to corporate. After-tax corporate and interest expenses were $109 million in the first quarter of 2017 compared to adjusted after-tax corporate and interest expenses of $72 million in the fourth quarter of 2016. The first quarter results reflect not recognizing a deferred tax benefit on operating losses.

Turning to first quarter cash flow. Net cash provided by operating activities before changes in working capital was $443 million. The net decrease in cash resulting from changes in working capital was $94 million. Additions to property, plant and equipment were $390 million. Proceeds from asset sales were $100 million. Net repayments of debt were $21 million. Common and preferred stock dividends paid were $92 million. All other items resulted in an increase in cash of $8 million, resulting in a net decrease in cash and cash equivalents in the first quarter of $46 million. The sale proceeds received in the quarter resulted from the sale of approximately 8,500 non-core net acres in the West Goliath area of the Bakken, which at the time was producing approximately 240 barrels of oil equivalent per day.

Turning to cash and liquidity. Excluding the midstream, we had cash and cash equivalents of $2.7 billion, total liquidity of $7.2 billion, including available committed credit facilities, and debt of $6,054,000,000 at March 31, 2017.

Now turning to guidance. First, for E&P. In the first quarter, our E&P cash cost were $14.15 per barrel, which beat guidance on strong production performance and cost management. For the second quarter, E&P cash costs are expected to be in the range of $15.50 to $16.50 per barrel, reflecting the lower second quarter production guidance and higher planned offshore facility maintenance costs, with full year guidance of $15 to $16 per barrel remaining unchanged. DD&A per barrel in the second quarter is forecast to be $25 to $26 with full year guidance remaining unchanged at $24 to $25 per barrel. The resulting total E&P unit operating costs are projected to be $40.50 to $42.50 per barrel in the second quarter and $39 to $41 per barrel for the full year.

Exploration expenses, excluding dry holes, are expected to be in the range of $65 million to $75 million in the second quarter, with full year guidance remaining unchanged at $250 million to $270 million. The midstream tariff is projected to be in the range of $125 million to $135 million in the second quarter and $520 million to $550 million for the full year, which is unchanged from prior guidance. The E&P effective tax rate, excluding Libya, is expected to be a benefit in the range of 10% to 14% for the second quarter. For the full year 2017, we now expect a benefit in the range of 12% to 16%, down from original guidance of 17% to 21% due to a change in mix of operating results.

Turning to Midstream. We anticipate net income attributable to Hess from the Midstream segment to be in the range of $15 million to $25 million in the second quarter. Midstream net income attributable to Hess for the full year is projected to be $65 million to $85 million, which is down from original guidance of $70 million to $90 million. The change reflects the increased noncontrolling interest from the MLP as a result of the IPO.

Turning to corporate. For the second quarter of 2017, corporate expenses are estimated to be in the range of $35 million to $40 million and interest expenses are estimated to be the range of $75 million to $80 million. Full year guidance remains unchanged at $140 million to $150 million for corporate expenses and $295 million to $305 million for interest expense.

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

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

I got 2 questions, if I may. The first one is on the capital guidance or the capital for the year. It looks like your first quarter spending run rate is a little bit light relative to the annualized rate. Is that just a timing issue? Or are you running below what your expectations are? And I've got a follow-up in Guyana, please.

Yes. Doug, right now, we're forecasting our capital spend in Q2 through Q4 to be higher than what you're seeing in Q1 and there's a couple reasons. I mean, as you know, we're going to be ramping up rigs in the Bakken from 2 rigs at the beginning of the year to 6 at year-end. Now we are also forecasting an increased spend midyear as we get closer to the North Malay Basin startup in Q3. So as you see, cost and capital have been performing well here in the first quarter, so we'll continue to monitor what we're doing through the year. And as usual, we'll update our guidance in midyear. But right now, our guidance remains $2.25 billion.

Okay. My second question is on Guyana. There's a couple of pieces, if you can bear with me for a minute. So my understanding is you've signed that joint interest agreement with Exxon covering the broader Guyana-Suriname Basin. Can you walk us through what that means in terms of your potential entry in traditional blocks? And the second part of my question, however, is more to do with the timing of sanction. There still seems to be some concern over the potential for substantial step-up in your spending as you move into development phase. Can you walk us through what your latest thinking is in terms of flexibility to fund your share? And whether you are, in fact, moving forward with a leased FPSO because, obviously, the different capital ramifications. And I'll leave it there.

All right. Doug, I'll start with your last question on the capital spend associated with the Early Production System and our flexibility to finance it. And I guess, the first thing I should say was we are working with the operator. We are looking to sanction the Early Production System for Liza around midyear. So at that point, everybody can see the numbers associated with that Early Production System. Now we expect that Guyana development to be phased. So with the cost spread out over a number of years and for initial phases of development to fund future phases, as Greg talked about earlier. Now as you said, at this point in our discussions with the operator, we are looking at leasing the FPSO, which will reduce our upfront spend for the development. And then, again, going to our flexibility, these increasing expenditures in Guyana coincide with the startup of North Malay Basin and Stampede, which become cash generators starting in 2018. And last thing I always like to remind everybody, we are sitting with $2.7 billion of cash right now on our balance sheet and we have a high leverage to oil prices. So as you know, every $1 increase in oil price adds approximately $70 million of after-tax cash flow to our portfolio. So we are poised to benefit from any increase in oil prices. So our flexibility is there to fund that Guyana development. And Greg?

Yes. For Doug, on your first question. First of all, there's been nothing signed yet. However, Exxon and Hess are -- given our understanding of, obviously, the greater Guyana basin, I'll call it, we are looking for other potential opportunities to expand our footprint, and I really can't say much beyond that.

Appreciate the answers guys. John, if I may, just a quick follow-up on the flexibility issue. $700 million is the capital allocated to Stampede and North Malay this year. Is that right?

So it was $700 million last year and I think, hang on, for this year for Stampede and for North Malay Basin, we had $275 million budgeted for North Malay Basin and $425 million. So yes, you are correct. That's $700 million of capital associated with those 2 assets. So in '18, the capital will go down for those assets combined, plus cash flow will go up.

Our next question is from Ed Westlake of Crédit Suisse.

First question on the Bakken, and congrats on that productivity improvement and beating the forecast. Maybe an update on the decline rate of the base, because when I look at how many wells you're going to complete and the improvements in the productivity, it seems as if the production guidance you're giving is a little bit low, maybe it's just timing. What's your interest in the decline rate on the base production at this point?

Yes. And I think, as you know, it's a very complicated question because we have a whole number of wells that are in the base at a very low decline rate. You have wells that have recently come on that are in there, either their first or their second year of decline. So I think any -- as you kind of look at production in the Bakken this year, it's purely a function of timing of when wells are coming on. As we mentioned in our opening remarks, that positive momentum really picks up in the second half of the year. As we put that third and fourth rig to work and start completing wells, that momentum really picks up. So that's really what's driving it how we say to answer the decline question because it's extremely complicated.

Second question is then on cost. I mean, you did come in below guidance and obviously, with maintenance, it will go up a bit in the second quarter. But presumably, when that maintenance is complete later in the year, then some of the cost benefits you see may come back down. Is it sort of an inflation sort of driver that means you haven't sort of lowered your full year cash cost guidance at this point?

No. I'd say it's more -- it's basically more of our practice right now. It's early in the year. We've had good cost performance and good production performance. So it was both of those combined on how we came in under our cash cost guidance. In the second quarter, as you said, we will have the higher maintenance cost and the higher cash cost. So as you move to the third quarter, yes, the cost reduction efforts that we have been -- that have been ongoing, and we did some further cost reductions at the end of 2016, will come back into the portfolio. The other thing that will happen is that North Malay Basin starts up in the third quarter and that, for our portfolio, will be very accretive to cash cost because that is a low cash cost asset. So as North Malay Basin continues to ramp up in the third and then into the fourth quarter, that will help our cash cost as well. So what we'll see is by our next earnings call, we'll have gotten through the maintenance season. We'll see where North Malay Basin is from the startup standpoint on timing, and then we'll update our cash cost guidance at that point.

Our next question is from Paul Sankey of Wolfe Research.

Just the specifics, firstly, on your volume guidance. Could you just walk us through how we get to the fourth quarter guidance, which is specified to be 330,000 to 340,000 barrels a day oil equivalent. But then within oil, we're interested in the 182,000 to 186,000 barrels a day. It seems low relative to where you are today. Could you just bridge us through why it's not higher? This is for 2017, obviously.

Well, Paul, I think, as we said in our opening remarks, we did update guidance for the second quarter. So we're up about 5,000 barrels a day versus our previous guidance. And we will, of course, midyear, give a revised update or a new update, I should say, on what the guidance is for the year and for the remaining quarters. The reason we haven't updated our guidance yet is because, again, North Malay Basin, we just want to have some greater certainty on exactly when that's going to start up. So once that's clear, which will be the second quarter, the exact date of startup, then we'll be in a better position to update guidance for the rest of the year.

Yes. You hit the kind of area that we were thinking was the main reason. Is there anything else other than North Malay Basin that would be contributing or detracting from the outlook?

No.

Okay. So that's the major uncertainty, great. And then if I could just ask a strategy question. With Guyana being what it is, is there any future for any other wildcat exploration? Is there any need for any other wildcat exploration for you guys in the future? Or could we say that that's the end of it really, globally, and Guyana plus Bakken is everything you need?

Yes. No, Paul, we're going to be very selective and focused and capital disciplined in our efforts in exploration. As you know, our strategy has been and continues to be early access to material resource opportunities with running room focused on oil, Atlantic margin at low cost. And obviously, that strategy is working in Guyana and Suriname Basin. A great example where Liza, Payara, the greater Liza area already world-class in their own right will generate very attractive returns down to $40 Brent flat, competitive with any unconventional play. In our opinion, even better. So it's all about focusing on returns and creating long-term value that I think is going to distinguish our company for many years to come. Beyond that, we still see in the Guyana-Suriname Basin further unrisked multibillion potential, and that's where the majority of our efforts is going to be. Yes, there will be some wildcatting, but it will be within our framework of capital discipline and keeping a tight rein on our spending. So we will spend some money outside of that, but the majority of our exploration efforts will be focused on Guyana.

Our next question is from Bob Morris of Citi.

On the Bakken production that exceeded your guidance you mentioned that you had some of the highest IP rate wells to date. Is that performance -- is there something beyond just the uplift from the 50-stage completions that's driving that outperformance and the strong well results there?

No. I think it's really the -- it's the uplift in the 50-stage completions plus we're drilling in the Keene area, which is truly the core of the core of the Bakken. You noticed that our performance was up in fourth quarter of last year. That strong performance continued into the first quarter of this year and it's really a function of where we're drilling in the 50-stage fracs. So it's 2 factors for both quarters.

Is the Keene area where you plan to drill and bring on most of the 80 and 75 wells for the year?

Yes. I mean, a good majority of the wells will be in that section. As we increase the rig count, we'll start -- we'll stay in the core, but we'll be moving out of the core of the core which is really the Keene. So our whole drilling program will be in the core this year, but not all of it will be in the Keene area simply because of some of the operational challenges of operating that rig -- many rigs in the same place, a lot of SIMOPS issues.

And finally there, where do you stand on maybe accelerating the rig? And you'd commented last quarter that depending on the cash flow and the oil price that you could accelerate that fifth or sixth rig in Q3 versus Q4. Is that still dependent on what cash flow and oil prices are to do that?

No. I think our current plan is still to add that rig in the -- add those 2 rigs in the fourth quarter.

Okay. And then just separately, my follow-on is in Guyana and from your comments which you've made so far with the 120,000 barrel per day FPSO. It appears that you'll develop Payara and Snoek as part of that FPSO development with Liza. Will that be the correct assumption?

I think the assumption would be is that there will be a greater Liza area development. So as you get into full field development, consider Liza and Payara as kind of one. Snoek, yet to be determined but it will most likely be tied into that greater Liza, Payara development plan. I did want to go correct one of my remarks in the opening. I said the Phase I is 120,000 barrel equivalent. It's actually 120,000 barrels of oil per day facility. So I wanted to correct that on the call.

Our next question is from Brian Singer of Goldman Sachs.

Following up on a couple of the earlier questions with regards to the Bakken. You talked about in the press release some weather delays. Could you quantify what that was? And then add a little bit more color on how, if those weather delays have gone away, that still leaves flat production in sequentially -- or flattish production sequentially in the second quarter versus further step-up? And then, I think, you mentioned in your prepared remarks that you're planning an update in July on what these completions and the effectiveness they're having, but can you give us your hypothesis for the 50-stage completions and what that does for EURs and recovery rates?

Well, I think, let me answer your last question first. So the 50-stage completions, we quote now IP 90 rates versus IP 30 because we just think that's a better reflection of the takes in the operational impact. So with IP 90s now, we're showing in this quarter it was close to 800, I think it was 793. And then the EURs, the corresponding EURs are in the range of about 1 million barrels. So that's on the 50-stage frac. Now as I mentioned, in the first quarter, we're doing a lot of experimentation with higher stage counts. So we've got a number of 60-stage completions in the ground now so we're actually considering, do we just move to 60-stage? We want to get a few more on the ground and make sure they're reliable, make sure we understand the production performance of those. So that will be one thing that we'll update in July as we said. We've also got a few wells with the higher proppant loadings. We plan to do more of those in the second quarter. So again, all of these is a bit in flux, which is why I said we will update all of that EURs, IPs, well costs, we'll update everything in our second quarter midyear update as always. And sorry, your question on the first quarter, the weather really hit us in January. So we fully recovered from that in February and March. And as we mentioned, the current forecast for Bakken in the second quarter is about 100,000 barrels a day. So up a bit from the first quarter. And then you really begin to see, as we mentioned, the production momentum from the Bakken really kicking in in the third and fourth quarter as you get the impact of that third and fourth rig being able to start completing wells in the last half of the year. So that's why the first and second is relatively flat because you're drilling, you're not completing those wells from the third and the fourth rig.

And my follow-up is with regards to actually to the completion side. As you do plan to ramp up and especially if you're increasing the stage counts of some of those completions, can you talk about what you're seeing in the Bakken in terms of both the cost on the pressure pumping side and then also the availability from a people perspective and the sand and sand logistics perspective?

Yes, I think so. Certainly, on the -- again, we'll update this midyear, but the results of the higher stage counts and although a few -- only a few wells with higher proppant loadings are encouraging, so that's good. Now in regards to your second question, we are seeing some upward pressure on cost in the Bakken in the completions space, as you said. We've taken a lot of steps to really minimize that. Several things that we've done, we're locking in the rig rates, we're prepurchasing sand and we're putting in place longer-term contracts, both on the rigs and also on the pumping side. So these steps, coupled with our Lean manufacturing approach where we still make operational improvements, give us confidence that we'll be able to deliver our 2017 program with minimal inflation. There may be some, but we're really trying to minimize that as much as possible.

Our next question is from Phillip Jungwirth of BMO.

I believe there is a tender for a second rig in Guyana, and I was wondering if you could discuss any plans whether development or exploration and timing for the second rig?

I can't really discuss timing yet because it's dependent, obviously, upon sanction Phase I, which we hope to do in midyear. The current thinking is that we will probably have one rig dedicated to exploration/appraisal. And then as you move into development on Phase I, then you'll probably have a rig dedicated for drilling the development wells of Phase I. So that's the current thinking. But again, we haven't made final decisions on when that second rig comes into the play. That's up to the operator.

Okay. And then when you do sanction Liza Phase I this summer, would you anticipate that incremental disclosure would be limited to Phase I? Or could you also provide some color on Phase II or a potential multiphase development?

I think, you should assume for now that it will be primarily just a Phase I development disclosure because, again, we're -- this is going to be a large development, multi-FPSOs that are phased over a number of years. So that's going to require a lot of planning and thinking and all that kind of stuff and as to how you sequence all that. So I think you could expect later color on that. So the first disclosure will be primarily on Phase I.

Okay. And then you have the Penn State well that is expected to be brought online in the third quarter. And was just wondering if you could talk to the opportunity set in the Gulf of Mexico for a similar subsea tieback well such as this which, I believe, is expected to IP around 10,000 barrels a day?

Yes. That's a good question. I think, we see a number of similar opportunities in the Gulf of Mexico. And I think, as we've said in the past, when we would add a rig in the Gulf of Mexico, it's really going to be a function of the oil price. As you see more strength in the oil price, we'll bring that into consideration. Because I think, as we've said before, you're going to want more strength in the offshore before you do that because, typically, you'll commit to a very expensive rig. Although a lot cheaper now, but you'll commit to a rig and so you want to have confidence that you have a pretty good oil price outlook before you commit to that very high-cost rig line associated equipment. Different than the onshore.

Our next question is from Paul Cheng of Barclays.

Greg, will you be able to share any estimate for the Early Production System? How much reserve that you guys expect? Is it a 500 million or 600 million barrels that you would be able to extract from that? And what is the development cost may look like?

Yes. Paul, I think, we will share as much as we can when we sanction Phase I. So hopefully, midyear.

Okay. And you guys is not at a position that you will be able to share about the new discovery in Guyana, one, maybe the SME size?

No. Because the -- remember, we just finished that well in March so there's still a lot of evaluation going on with the Snoek prospect.

Maybe this is for John Rielly. John, when I look at the international unit OpEx cost, from the fourth to the first quarter, you had really dropped a lot in your production, actually, internationally have gone down. So I'm a little bit unclear to me why that unit cost have come down that much. Is it just purely as simple as that? Because you underlift so that the -- but your production is higher, so that means that the costs only reflect what is being lifted. Is there any other explanation that you could give us?

So the cost reduction doesn't have anything to do with the underlift. In the fourth quarter, when you're looking at those numbers, if you remember, we had some nonrecurring special items and one of them was an inventory write-off. So on the international side, we had approximately a $30 million pretax inventory write-off that's in those operating costs in the fourth quarter. So you had that special. Then even with that, you can see even across our U.S. and international though, we have reduced cost throughout the portfolio and are continuing to focus on that. Obviously, good production performance helps and -- but we did go through a lot of cost-reduction efforts through 2016 and it bore some fruit as you can see in the first quarter.

Right. So I mean, if I just -- for the inventory write-down in your fourth quarter, we talked to -- say, call you $15.50, but you're still about $2 lower in the first quarter. So is that is all just by normal cost reduction?

Yes. Correct. That's normal cost execution.

(inaudible)

Correct. It's just normal execution, good performance across the portfolio.

Okay. And just curious there, I mean, in Permian, it seems that you really have no production there. Why don't we just sell Permian into your MLP or to some other people? Why keep the Permian gas plant under Hess today?

Okay. So just to start with the Permian. So in the first quarter, it's still producing 8,000 barrels a day. So it's not an absolute material amount, but it's producing 8,000 barrels a day and it's generating cash flow for the company. Now what we have done is, from an MLP standpoint, it's the gas plant and the CO2 where you don't take the E&P type commodity price exposure to put it in the midstream. So we are, as I talked about, moving the Permian gas plant and the CO2 assets into our Midstream segment. And that happened on January 1 and we did recast the prior year 2016. So we have taken steps. Now, we still have that 100%. It has not been dropped into our joint venture with GIP, but it's something that's under discussion.

Okay. A final one for Greg. At 6 rigs, if we assume that you exit from there and stayed there, what kind of Bakken target production growth rate from 2018 to 2020 we could expect? And also there, given the -- why commodity price, and let's assume somewhere between 60 to 70, what is the optimal Bakken petro production rate that you guys currently foreseeing?

Paul, so we'll give guidance, obviously, as we approach 2018. The reason I don't want to give any -- be more specific than that is because, remember, our completion design is in flux, right? So what the future completion design will be, will be a large factor in saying what the growth rate at the Bakken will be with 6 rigs. What we do know right now is it takes about 3/4 rigs to hold the Bakken flat. It is roughly 100,000 barrels a day, let's call it. So clearly, any rigs above that is going to be growth. But depending on the completion design, the rate of that growth might vary. So we'll give guidance as we kind of complete these completion trials and determine what the completion design is on a go-forward basis.

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

I wanted to follow-up on the Bakken and the pilot programs you have planned this year. But to what extent are better well results from your pilot programs, the 60-stage fracs, the higher proppant loadings factored into your 4Q 2017 Bakken production guidance? And will there be any upside to that guidance if you do begin to see an improvement in your IP rates?

So none of that is built into the guidance yet, and that's why we hope to update things in the middle of the year. Given the early results of the 60-stage wells and even though few, but we'll do more in the second quarter of the higher proppant loading, the bias will be for that guidance to go up.

Got it. That's helpful. And then the oil cut in the Bakken looks like it also increased pretty considerably to its highest level since 2015, I believe. But can you talk about what the driver may have been of that higher oil cut this quarter and is that higher level sustainable?

No, it's not. So it's purely operational. If you look at the well GURs is about $15.50, that has stayed constant for years and will stay constant in the future. So it's purely operational related to the weather in the first quarter, where we had some compressor downtime. So you threw a lot more gas to flare than what you normally would have in normal operations. So that's what's causing that aberration in the higher oil versus gas this quarter.

Okay. Great. And then last one from me. I just wanted to circle back to the 1Q just overall production outperformance. But obviously, you beat expectations. The Bakken was very strong. Where else did you outperform relative to the internal plan? The Gulf of Mexico looked good relative to our estimates. Was that a driver? And on that note, can you give us an update on how Tubular Bells is performing and what expectations are for that asset this year?

So you're right. The Bakken was up about 7,000 barrels a day versus what we thought. The other 5,000 was really kind of spread out amongst -- across the portfolio. But you're right, it was primarily the Gulf of Mexico that came in performing better. If you look at T-Bells, as we said in our January call, in Q1, we increased water injection and began slowly bringing on our fifth producer and also, that well that we worked over right at the end of last year. So we're bringing those wells on very slowly. And as a result, production continues to increase on Tubular Bells. So while those trends are encouraging, what I said last quarter is I really want to see some constant stable production on Tubular Bells before I forecast what it's going to do. So I'd like to see a few more months of stable production and injection data before we issue kind of a new year, new full year forecast for T-Bells. But quarter-on-quarter, T-Bells is up about 4,000 barrels a day.

So what did that bring, the 1Q '17 average due for T-Bells, if you could share it?

The first quarter was average for T-Bells is about 13. Currently, we're kind of in the range of 18,000 to 19,000 barrels a day on T-Bells. So continues to ramp. We're taking it very slowly, very cautiously and also watching, hopefully, the impact of water injection as well.

Our next question is from Evan Calio of Morgan Stanley.

Maybe, first, a strategic question. I mean, as Liza moves into development and Guyana through the exploration phase, I mean, how do you think about managing your position size relative to total portfolio? Meaning, how, if or when do you consider monetizing or selling down any interest to pull forward the significant value there?

We see exceptional value and returns in our position in Guyana and a lot more upside in some of the future drilling that we have there. So we're very happy with our position. If it makes sense to pull value forward, we might look at some other levers in the portfolio because one of the best returns, I think, in the industry is going to be the investment we make in Guyana. The fact that it has very attractive economics with what we already have captured in the greater Liza area, down to $40 Brent flat and a lot of upside potential. So there's a lot more running room there and it's going to be very low cost on the cost curve. So we think it's going to have exceptional returns. So we want light to shine on that and wouldn't want to be premature in terms of anything else.

That's fair. John, maybe a follow-up to the 2017 hedges renew. I know that's been a variable program over time. Is there any change in your commodity outlook or hedging strategy, given the significant investment potential within the portfolio? Any comments there?

Yes. Obviously, with the uncertainty about the oil prices, we do think we're entering a new chapter of oil prices where they will start going up to attract more investment in the business. But we certainly think we're still in a volatile period. And with the increase in activity levels that we have, we just thought having some price insurance for this year would be a wise idea.

Great. And maybe lastly if I could, just following up on the Bakken beat. It looks like the IP 90 well performance was in line Q-over-Q from the ops report that was just filed. And so is the variance of the beat largely as you look at the completion timing in December and 1Q? I mean, given that you beat the Bakken with just 8 wells (inaudible) in the quarter?

Yes. I think, it was a combination of things. It was a combination of a little bit better well performance than planned in our 50-stage fracs. The second factor was we recovered from the weather much quicker, much more rapidly than we anticipated. So those are the 2 big things, Evan.

Great. So your plan is below the current performance and from at least an IP 90 basis that we see in the Bakken from 4Q and now into 1Q, is that (inaudible)?

It was in the first Q. So the wells did a little better than we thought in the first Q, yes. We only got 8 wells on remember, so yes.

Our next question is from Jeffrey Campbell of Tuohy Brothers.

First question on timing. When do you expect the fifth and sixth rigs coming to the Bakken to show a positive production effect in 2018?

Well, it will be late in the fourth quarter. So you really won't see any impact of those rigs in 2017. It will be primarily in 2018.

Right. And that was what I was wondering. When do you think it will start to show up in 2018?

Second quarter.

Okay. Great. Touching on John's remarks earlier about future wildcatting, I was just wondering, do you consider drilling offshore Nova Scotia in 2018 wildcatting to some extent?

Yes. That would be one of the wells that we would have a commitment on. But again, a majority of our exploration program is going to be very focused and the majority of the dollars are going to go to Guyana.

Okay. Fair enough. And my last question, Utica Shale. Appalachian NGL prices have improved significantly. Industry peers are attempting and has raised the return by drilling ultra long laterals, and this is also showing up in the Southwest PA Marcellus. I was just wondering if you could update your thinking on the Utica? Are you watching this long lateral trend? What needs to happen in the commodities to get rig into the Utica again?

No. I think you're right. I think we are watching long laterals. Obviously, we are watching the margins change and the gas prices go higher. There are no plans for us right now to bring any rigs back into the Utica in 2017. But obviously, as those trends improve, we'll begin to evaluate do we bring our rig back in the Utica.

Our next question is from David Heikkinen of Heikkinen Energy.

You mentioned that you're kind of drilling in the core, the core Keene area now and I'm just kind of curious out of the 2,850 future locations, how many locations you would assign to this area, if you could?

Well, I think, maybe a better way to answer it without being specific to Keene, we have several hundred wells that can deliver the kind of performance that we're seeing in the last couple of quarters.

So you got well more than the 2017 drilling program that carries into '18 and maybe even a little longer that's called, that's (inaudible)?

We do. And again, the only reason you wouldn't concentrate all of your drilling there is simply because of SIMOPS issues. You just can't have that many rigs concentrated in one place like that.

Our next question is from Pavel Molchanov of Raymond James.

Just 2 quick ones about the Liza FID. Once you reach FID, you're presumably going to be booking some reserves. Do you have a sense of what you'll be able to book upfront in 2017?

Well, when we take sanction, we'll obviously give you a lot more color on that.

Okay. So still figuring out. And then the timing of reaching FID, is there any relevance in the fact that there is still a border dispute involving Venezuela? Is that going to be influencing the timing at all, the political landscape?

No.

Our next question is from John Herrlin of Societe Generale.

One for Greg regarding Guyana. You talked about good returns with $40 flat pricing. Obviously, rig costs are cheaper, but how are cycle times changing for the deepwater as well as other costs like completion for the deepwater? Because The Street is already fixated these days on the other shale learnings, but what's happening in the deepwater that you could pinpoint?

Well, I think, obviously, specific to Guyana, it's unique in itself because it's shallower wells. These are only about 13,000 to 15,000 feet below the mud line. So it's a bit of a unique province in itself. I think, the broader question around industry and deepwater, obviously, the costs are coming down still, particularly in the shipyard area where shipyards now are half full and projected to be even less than that next year. Still some softness in the offshore rig market, so the price trends are awesome in the deepwater and that bodes well, obviously, for our Guyana development, both of those dimensions. Also, there is a broad effort in the industry and very significant effort in Hess around standardization. So I think all of that is going to significantly improve the cycle time. You'll have shipyards focused on much for your projects. You'll have industry focused on standardization. So all of that is really collapsing the cycle time of when you can bring these things on, which is good.

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