赫斯 (HES) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third 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 third quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.

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

Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

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 third quarter conference call. I will provide an update on the progress we are making in executing our strategy. Greg Hill will then discuss our operating performance, and John Rielly will then review our financial results.

Our strategy is to focus our portfolio by investing in our highest return assets and divesting mature higher-cost assets, which in turn will lower our unit cash operating costs, bolster our balance sheet and pre-fund our truly world-class investment opportunity in Guyana. This strategy is designed to deliver significant value to our shareholders, even in a low oil price environment, for many years to come.

During the third quarter, we achieved several strategic milestones, including this week's announced sales of our interests in Norway and Equatorial Guinea as well as our enhanced oil recovery assets in the Permian in early August. We also announced plans to sell our interest in Denmark, which should result in a complete exit from the North Sea. In April of this year, we also completed the initial public offering of Hess Midstream Partners LP. Proceeds from these asset sales to date are estimated at approximately $3.25 billion and, along with cash on our balance sheet, will be used to fund offshore Guyana, one of the industry's most attractive investment opportunities, which offers superior returns even in a low price environment and positions our company for a decade plus of visible reserve and production growth with outstanding returns.

The Stabroek Block, where Hess has a 30% interest, contains a massive world-class resource that keeps getting bigger and better. Earlier this month, the operator, ExxonMobil, announced a fifth oil discovery with the Turbot #1 well, which encountered 75 feet of high quality oil-bearing sandstone reservoir. We are encouraged by the results of this discovery, which is accretive to the estimated 2.25 billion to 2.75 billion barrels gross recoverable resources already discovered on the Stabroek Block. Additional drilling at Turbot is planned for 2018 to further evaluate the full commercial potential of the resource. We also expect to spud the Ranger #1 well by the end of this month.

We are also very excited about the Liza Phase I development that is already underway, which will have the gross capacity to produce up to 120,000 barrels of oil per day, with first production expected by 2020. Guyana is simply an extraordinary investment opportunity that is uniquely advantaged by its scale, quality, cost, timing and financial returns.

First, as I mentioned, Liza and Payara are giant oil fields, some of the industry's largest oil discoveries of the past decade. Second, it has one of the highest-quality reservoirs in the world with high porosity and permeability and is expected to deliver very high recovery factors and production rates. Third, since the producing horizons are relatively shallow for deep water wells, the wells can be drilled in approximately 1/3 of the time and cost of those in the deepwater Gulf of Mexico. Fourth, development is set to occur at what is expected to be the bottom of the offshore cost cycle. Fifth, ExxonMobil, as the operator, is one of the most experienced project managers in the world for this type of development, with a great track record, which significantly reduces execution risk. And finally, we see multibillion barrels of additional unrisked exploration upside on the block. In addition, allocating capital to our highest return assets and selling those that are mature and higher cost, together with a planned $150 million annual cost reduction program will contribute to reducing our cash unit production costs by approximately 30% to less than $10 a barrel by 2020.

Funding our high return growth opportunities requires a strong balance sheet and liquidity position, which remain a top priority for our company. At September 30, we had $2.5 billion of cash and total liquidity of $6.8 billion. Proceeds from asset sales announced in 2017 and the midstream IPO are estimated to exceed $3.4 billion, with additional proceeds expected in 2018 from the sale of our interest in Denmark. Our asset sales will also extinguish approximately $3.2 billion in future abandonment liabilities and enable $500 million of debt reduction in 2018.

At the same time, we have built a strong hedge position in a period of oil price uncertainty to protect our cash flows. For the remainder of 2017, using put/call collars, we have hedged 130,000 barrels per day of oil production, 20,000 barrels per day of Brent, with a $55 floor and $20 upside; 60,000 barrels per day of WTI, with a $50 floor and $20 upside; and 50,000 barrels per day of WTI, with a $50 floor and $15 upside. For 2018, we have hedged 115,000 barrels per day of oil production using put/call collars, with a $50 WTI floor and $15 upside.

Now turning to our financial results. In the third quarter of 2017, we posted a net loss of $624 million, which includes net nonrecurring losses totaled $300 million. On an adjusted basis, our net loss was $324 million or $1.07 per common share compared with a net loss of $340 million or $1.12 per common share in the third quarter of 2016. Compared to 2016, our third quarter financial results were positively impacted by higher realized crude oil selling prices and lower operating costs, depreciation, depletion and amortization and exploration expenses, which more than offset the lower tax benefits following a required change in deferred tax accounting.

Third quarter production was within our guidance range, averaging 299,000 barrels of oil equivalent per day, excluding Libya. Net production in Libya was 12,000 barrels of oil equivalent per day in the third quarter.

The Bakken is our largest operated growth asset, where we have an industry-leading position, with more than a 0.5 million net acres in the core of the play and the capacity to grow production to approximately 175,000 barrels of oil equivalent per day from 103,000 barrels of oil equivalent per day currently. Our distinctive lean capability has enabled us to lower our well cost by 60% since 2010. In addition, our use of technology through the application of geo-steering, optimized spacing, higher stage counts and proppant loading has increased our well productivity by approximately 50% over the last 2 years. Together, these improvements have enabled us to generate returns that are competitive with any shale play in the United States. We are currently operating 4 rigs in the Bakken. That, with 60-stage fracs and increased proppant levels, are forecast to deliver virtually the same oil production growth of approximately 10% a year that would've taken 6 rigs a year ago. Based on the strong financial returns of our Bakken wells, we are evaluating plans to add up to 2 additional rigs in the Bakken during 2018 for a total of 6 rigs.

In Malaysia, the North Malay Basin full field development achieved first production of natural gas in July. Hess is the operator with 50% interest, and PETRONAS is our partner with the remaining 50%. For the third quarter, production averaged 86 million cubic feet a day and the field is on track to reach its planned plateau rate of 165 million cubic feet per day in the fourth quarter. North Malay Basin will be a significant long-term low-cost cash generator for the company.

In the deepwater Gulf of Mexico, the Stampede development, in which Hess has a 25% interest and is the operator, remains on track to start up in the first quarter of 2018 and ramp up production over the following 12 months.

In summary, we are well positioned to deliver a decade plus of returns-driven growth and increasing cash generation through continued execution of our strategic plan. The success of our asset sales program to-date further focuses our portfolio on higher return assets and lowers our cash unit costs. At the same time, we are strengthening our balance sheet to fund our world-class investment opportunity in Guyana, which we believe will create significant value for our shareholders for many years to come.

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

Thanks, John. I'd like to provide an update on our operational performance in 2017. In the third quarter, despite several weather-related challenges, our team executed well across our producing and development assets. We also continued delivering value through exploration. The Turbot-1 well, some 30 miles to the Southeast of Liza, resulted in a fifth significant discovery on the Stabroek Block in Guyana, reinforcing the tremendous potential of this 6.6 million-acre block. The recently announced asset sales, as John noted, further focus and simplify our portfolio, lower our cash unit operating costs in breakeven oil price and allow us to pre-fund the development of our world-class discoveries on Stabroek, as Guyana continues to get bigger and better.

Now starting with production. In the third quarter, net production averaged 299,000 barrels of oil equivalent per day, excluding Libya, at the center of our guidance range of 295,000 to 305,000 barrels of oil equivalent per day. Our third quarter production was influenced by the following, primarily weather-related factors: first, hurricanes Harvey and Irma, along with third-party downtime at our Conger Field, impacted our Gulf of Mexico production by approximately 7,000 barrels of oil equivalent per day; second, unusually heavy rainfall in North Dakota resulted in road closures and deferred completions, reducing our production there by about 4,000 barrels of oil equivalent per day. As a result, net production averaged 103,000 barrels of oil equivalent per day in the third quarter, slightly below our guidance. However, both of these weather impacts were offset by a temporary adjustment in our JDA entitlement, which increased production by approximately 8,000 barrels of oil equivalent per day.

Looking ahead to the fourth quarter, we will have some carryover effects from these issues as follows: the cumulative impact of 1 tropical storm and 3 hurricanes has resulted in 40 days of overall downtime for the Noble Paul Romano drilling rig, that will push the start-up of the Penn State 6 well to December and the subsequent workover of another well into first quarter 2018. These delays will impact fourth quarter production by approximately 5,000 barrels of oil equivalent per day versus plan. The Conger Field has been off-line in October due to downtime at the Shell-operated Enchilada platform, which will impact fourth quarter production by approximately 3,000 barrels of oil equivalent per day versus plan. At the JDA, the third quarter benefit in our net entitlement will reverse, reducing production by about 8,000 barrels of oil equivalent per day. However, in the Bakken, we plan to temporarily add a third completion crew to help us recover from the weather impacts experienced in the third quarter, and we expect net production to rebound in the fourth quarter to the range of 105,000 to 110,000 barrels of oil equivalent per day. On this basis, we continue to expect delivery of our full year guidance in the Bakken of approximately 105,000 barrels of oil equivalent per day. Assuming the sale of our interests in Equatorial Guinea closes at the end of November, and the sale of Norway closes in December, our fourth quarter production will reduce by approximately 14,000 barrels of oil equivalent per day. As a result of all these factors, our company fourth quarter production is now forecast to be 290,000 to 300,000 barrels of oil equivalent per day, excluding Libya.

As we enter 2018 with North Malay Basin fully online, 4 rigs operating in the Bakken, and Stampede coming onstream, we expect to deliver strong pro forma production momentum. We will provide production guidance for 2018 on our January call.

Turning to the Bakken. During the third quarter, we drilled 24 wells, completed 20 wells, but only brought 13 new wells online due to weather compared to the year-ago quarter when we drilled 21 wells and brought 22 wells online. We continue to test higher stage counts and proppant loadings in our sliding sleeve wells and have begun to test some plug and perf completions, in line with our focus on maximizing the value of our DSUs. To date, we have fracked 14 50-stage wells and 20 60-stage wells with proppant loadings of 140,000 pounds per stage. 18 of these high proppant wells are online. And although the wells are in the early stages of their type curve, results to date have been encouraging.

In our earnings release supplement, we've provided our actual drilling and completion costs of $5.8 million per well in the quarter. About 3/4 of the wells completed were the 60-stage high proppant wells, which had an average cost of approximately $6 million each. We expect these well costs will be further reduced through lean manufacturing. And with the positive results to date, we expect average gross EURs for wells drilled in 2017 to exceed 1 million barrels of oil equivalent per well. Early next year, we will issue new guidance in terms of completion design, well costs, IP 90s and EURs.

Now moving to our developments. At the North Malay Basin in the Gulf of Thailand, in which Hess holds a 50% interest and is operator, first gas was achieved on July 10. Production averaged 86 million cubic feet per day during the third quarter, and following a continuing successful ramp-up, is expected to reach its plateau production level of approximately 165 million cubic feet per day in the fourth quarter, which is expected to continue into the next decade, throwing off significant free cash flow for the corporation. At the Stampede development in the deepwater Gulf of Mexico, in which Hess holds a 25% working interest and is operator, all pipeline pre-commissioning was completed during the third quarter. Three wells have been drilled and completed, and first oil is now expected to be achieved during the first quarter of 2018, which is 6 months ahead of schedule and well below budget.

Now moving to offshore Guyana. Earlier this month, ExxonMobil, the operator, announced that the Turbot-1 well resulted in another discovery on the Stabroek Block, in which Hess holds a 30% interest. The well encountered 75 feet of high quality oil-bearing sandstone. This discovery follows the Liza, Payara, Snoek and Liza Deep discoveries. Our success at Turbot is exciting, not just because of its large aerial extent, but also because it extends the play more than 30 miles to the Southeast of Liza and confirms our geologic models and the vast hydrocarbon potential of the block which, even given the discoveries to date, remain substantially untested. The drilling rig will now move to the Ranger prospect, which is expected to spud by the end of the month. Prior to the Turbot discovery, the operator, ExxonMobil, estimated gross discovered recoverable resources for the Stabroek Block to be 2.25 billion to 2.75 billion barrels of oil equivalent, and following further appraisal of Turbot, we expect volumes to continue to increase.

Liza Phase I development is underway following project sanction in June, and first oil remains expected by 2020. This is an asset of exceptional scale, with a high quality multi-Darcy permeability reservoir and attractive financial returns at oil prices down to $35 Brent. We plan to conduct further exploration and appraisal drilling throughout 2018 on the Stabroek Block, where we see numerous remaining prospects across multiple play types, representing multibillion barrel unrisked upside potential on this 6.6 million-acre block.

In closing, we continue to execute well operationally and are taking the necessary portfolio steps to improve returns and price resiliency by redeploying capital from higher cost mature assets to lower-cost high return assets. This will drive a meaningful reduction in our cash unit operating costs and will generate proceeds to pre-fund our world-class investment opportunity in Guyana as it continues to get bigger and better. Our pro forma production momentum will strengthen in 2018 with plateau production from the North Malay Basin, a further ramp-up of the Bakken and planned first oil from Stampede in the first quarter.

I will now turn the call over to John Rielly.

Thanks, Greg. Let me start by discussing our recently announced asset sales and the use of proceeds. We expect the sales of our interest in Equatorial Guinea and Norway to be completed by year-end 2017. And together with our Permian EOR sale, total proceeds are $3.25 billion from the announced transactions. Additionally, we anticipate that the Denmark sales process will be completed in 2018. As the proceeds from these transactions are received, we intend to reduce debt by $500 million, and are evaluating plans to add up to 2 additional rigs in the Bakken during 2018 for a total of 6 rigs. The proceeds from asset sales, along with our current cash position and, importantly, our free cash flows from our low-cost cash-generative assets in the Gulf of Mexico and Malaysia, provide us the financial flexibility to fund our growing world-class investment opportunity in Guyana in an extended $50 oil price environment, without the need to access the debt or equity markets. We do not intend to pursue any M&A activity, and believe that our reshaped portfolio provides us with superior returns compared to other outside opportunities. We are highly cognizant of the importance of cash returns to shareholders given the strength of our current liquidity position. However, we need more visibility into Exxon's plans for Phase II and III of the Liza development in Guyana. Until we have this clarity, we initially plan to maintain a strong liquidity position, but will clearly consider cash returns to shareholders as appropriate.

I would also like to provide some additional comments on the deals just announced. The Equatorial Guinea and Norway asset sales will not incur any transaction taxes. We also will not incur any taxes on the repatriation of these proceeds. Additionally, the company has settled open tax matters with the EG taxing authorities for the tax years prior to the effective date. In this regard, the company will release $85 million in related tax reserves on the balance sheet, which it had accrued in prior periods for the years in question. These reserves fully cover the company's tax obligation under the settlement.

Now turning to our results. I will compare results from the third quarter of 2017 to the second quarter of 2017. We incurred a net loss of $624 million in the third quarter of 2017 compared with a net loss of $449 million in the previous quarter. Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $324 million in the third quarter of 2017. Third quarter results include an after-tax gain of $280 million associated with the sale of our enhanced recovery assets in the Permian Basin. The sale transaction included both upstream and midstream assets and, as a result, an after-tax gain of $314 million was allocated to the E&P segment, and an after-tax loss of $34 million was allocated to the Midstream segment.

Third quarter results also included a noncash charge of $550 million after tax for the sale of Norway. In the fourth quarter, an additional charge relating to the Norway cumulative translation adjustment included in shareholders' equity will be recognized. The cumulative translation adjustment for Norway at September 30, 2017, was approximately $840 million.

Turning to E&P. E&P had an adjusted net loss of $238 million in the third quarter of 2017 compared with a net loss of $354 million in the second quarter of 2017. The changes in the after-tax components of adjusted E&P results between the third quarter and second quarter of 2017 were as follows: higher realized selling prices improved results by $37 million; higher sales volumes improved results by $10 million; lower operating costs and expenses improved results by $18 million; lower DD&A expense improved results by $33 million; lower exploration expenses improved results by $12 million; all other items improved results by $6 million, for an overall improvement in third quarter results of $116 million. The E&P effective income tax rate, excluding specials and Libyan operations, was a benefit of 18% for the third quarter of 2017 compared with a benefit of 8% in the second quarter. For the third quarter, our E&P crude oil sales volumes were underlifted compared with production by approximately 280,000 barrels, which did not have a material impact on our results.

Turning to midstream. On an adjusted basis, the Midstream segment had net income of $22 million in the third quarter, which was up from $16 million in the second quarter. Midstream EBITDA before the noncontrolling interest and excluding specials amounted to $109 million in the third quarter compared to $96 million in the second quarter of 2017.

Turning to corporate. After-tax corporate and interest expenses, excluding items affecting comparability, were at $108 million in the third quarter of 2017 compared to $111 million in the second quarter of 2017. Third quarter 2017 results include an after-tax charge of $30 million in connection with vacated office space.

Turning to third quarter cash flow. Net cash provided by operating activities before changes in working capital was $415 million. Changes in working capital reduced operating cash flows by $327 million. Additions to property, plant and equipment were $513 million. Proceeds from the sale of assets were $604 million. Net repayments of debt were $19 million. Common and preferred stock dividends paid were $91 million. Distributions to noncontrolling interest were $33 million. All other items were a net decrease in cash of $2 million, resulting in a net increase in cash and cash equivalents in the third quarter of $34 million. Changes in working capital during the third quarter of 2017 were net cash outflows related to Norwegian abandonment expenditures, advances to operators, premiums on hedge contracts and the timing of interest payments.

Turning to cash and liquidity. Excluding midstream, we ended the quarter with cash and cash equivalents of $2.48 billion; total liquidity of $6.8 billion, including available committed credit facilities; and debt of $6,016,000,000. As previously mentioned, we also have a strong crude oil hedge position through 2018 to protect our cash flow.

Now turning to guidance. But before I give the guidance for the fourth quarter, I will provide third quarter pro forma financial metrics that remove the EG, Norway and Denmark assets being sold, but exclude the projected $150 million of cost savings to assist with your modeling of the portfolio post asset sales. Our third quarter pro forma cash costs were $12.80 per barrel as compared to actual reported results of $13.67 per barrel. Our third quarter pro forma DD&A per barrel was $23.72 and actual DD&A was $24.79 per barrel. Finally, our pro forma tax rate, excluding Libya, was a benefit of 2% as compared to our reported benefit of 18%.

I will now provide fourth quarter guidance with a cautionary statement that this can be impacted by the timing of the asset sales. Also, our DD&A rate will be lower than expected because DD&A will not be recorded on EG and Norway post the contract signings, since these assets will be classified as held for sale. The lower DD&A will improve results and, therefore, also impact our tax rate significantly since Norway has a high statutory tax rate. For the fourth quarter of 2017, E&P cash costs, excluding Libya, are projected to be in the range of $13.50 to $14.50 per barrel of oil equivalent, and full year 2017 cash cost guidance remains unchanged at $14 to $15 per barrel. DD&A per barrel, excluding Libya, is forecast to be in the range of $22.50 to $23.50 per barrel in the fourth quarter of 2017 and $24.50 to $25.50 per barrel for the full year, which is unchanged from previous guidance. As a result, total E&P unit operating costs are projected to be in the range of $36 to $38 per barrel in the fourth quarter and $38.50 to $40.50 per barrel for the full year.

Exploration expenses, excluding dry hole costs, are expected to be in the range of $75 million to $85 million in the fourth quarter, with full year guidance of $225 million to $235 million, which is down from the previous guidance of $250 million to $270 million. The midstream tariff is projected to be in the range of $135 million to $145 million for the fourth quarter and $535 million to $545 million for the full year, which is updated from previous full year guidance of $520 million to $535 million.

The E&P effective tax rate, excluding Libya, is expected to be an expense in the range of 16% to 20% for the fourth quarter. For the full year, we now expect a benefit in the range of 5% to 9%, which is down from previous guidance of 11% to 15% due to the asset sales.

For midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $15 million to $20 million in the fourth quarter and $70 million to $75 million for the full year, which is updated from previous full year guidance of $65 million to $75 million.

Turning to corporate. We expect corporate expenses to be in the range of $30 million to $35 million for the fourth quarter and full year guidance of $130 million to $135 million, down from previous guidance of $135 million to $145 million. We anticipate interest expenses to be in the range of $70 million to $75 million for the fourth quarter and $300 million to $305 million for the full year, which is updated from previous full year guidance of $295 million to $305 million.

This concludes my remarks. We will 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 Guy Baber of Simmons.

I wanted to explore some of the implications here of your strategic divestments that you've announced. But production at EG was obviously declining rapidly, and neither EG nor Valhall were competing for capital. So my question is, can you just discuss how the monetization of those higher cost assets, which were more capital-intensive to grow or even just to keep flat -- I mean, to what degree do you think those divestments improve the medium term to longer-term F&D costs that you think your company is capable of delivering on a sustainable basis? If you could just help us quantify that or give some thoughts on how you think about that? I think that will be helpful.

Sure. This will clearly improve our F&D costs as we move forward. I mean, the part of our strategy of divesting these high-cost assets is to free up capital, accelerate value and be able to put that capital into our high-return Guyana and Bakken assets. So if you look at Guyana, I mean, right now, if you just take Phase I, it's a $7 F&D. If you just look at the gross cost there associated with Liza and the reserves that we're going to get, it's a $7 F&D. Take our Bakken numbers. Again, under $10 F&D. So we will have a substantial improvement. And that is, again, part of the key of this portfolio strategy moves are to get this capital to invest in these great return assets. The other thing, the other aspect of it, as you said, Norway was not generating much cash flow from us at all. We have a significant abandonment expenditures. Actually, Norway was only going to provide us $20 million of net cash flow in the quarter -- I mean, sorry, for 2017. EG, like you said, was in decline. So there was $170 million of net cash flow in 2017, but we weren't investing because it didn't compete for capital. So the way we look at this from a net cash flow standpoint, the proceeds that we got, we received a 14x multiple on that net cash flow. So again, that -- and also, that net cash flow on Norway was not going to improve here through 2020. EG was going to decline, so that wasn't going to be generating much free cash flow for us in our portfolio. As John mentioned, too, with the high cost of all these assets coming out of the portfolio and our cost reduction program, we can really start driving down our breakevens on F&D and our portfolio cash costs will be driven down under $10. So again, we just think just great strategic moves for us and our portfolio.

And I also have to say, I think our asset sales program's exceeded expectations with a -- really high outcomes for the Norway, EG and Permian. And we exceeded expectations, I'd say, both in terms of proceeds and timing on a NAV basis. So we're very pleased with those outcomes, and we brought a lot of value forward for assets that were high cost, that really weren't generating much cash.

That's very helpful. And then I had just one other kind of strategic question here. But can you elaborate just in a bit more detail on the statement that you all made that M&A is not really something you're looking at here, given the strength of the returns you see in your portfolio? I mean, I'm sure you all are looking at what's available in the market around your core areas of focus. So just curious if this is a statement reflecting that you just don't believe M&A is necessary strategically in your portfolio right now? Or if there's just no way, from what you see, that what you see in the M&A environment can compete on a returns basis with just using your capital and investing organically in the portfolio as it stands?

Right. We're all about focusing our portfolio on returns. And one of the reasons John said that about we certainly don't intend to pursue any M&A activity is because of returns, and that our reshaped portfolio provides us with superior returns investing in what we have, obviously, led by Guyana and the Bakken, compared to any other outside opportunities. We're always looking to optimize the portfolio. We said that we would sell the higher cost, lower return assets to basically pre-fund Guyana. I think, as I've said before, we should celebrate the outstanding results we had because basically, that cash allows us to pre-fund Guyana, which is extremely high return. So it's all about returns, it's all about capital discipline. It's not about volume, it's about value. And we're building a portfolio that I think will be very resilient in a low-price environment, but have world-class cash cost per barrel that really will position us for a decade plus of outstanding returns and cash generation.

Our next question's from Brian Singer of Goldman Sachs.

I think you were pretty clear in that last response on not wanting to pursue M&A with the improved balance sheet. Can you comment on if there's any change to a dividend policy, given in part some of the reduction in free cash flow from the assets being sold? And also the comment that you made on wanting to maintain strong liquidity while awaiting clarity on spending need for Phase II in Guyana?

Yes. Obviously, we're very aware of the importance of cash returns to shareholders, given the much stronger position we're going to have in terms of cash and liquidity. We just need some more visibility into Exxon's plans for Phase II and Phase III of the Liza development, which we should have in the next month or so. But until we have this clarity -- and you talked about dividends, but whether it's dividend or share buyback, we initially -- which is really cash returns to shareholders, we initially plan to maintain a strong liquidity position. But we will clearly consider improving cash returns to shareholders as appropriate once we have that visibility.

And that means no reduction in the dividend would be being considered? Just to be clear on that as well.

Correct.

Great. And then my follow-up is on the Bakken. You mentioned the additional completion crew, which seems to, I think as you said, be temporary, given some of the delays that you had. I wondered if there's any change to strategy from an investment perspective in drilling beyond the temporary point in the fourth quarter, in part considering the improved balance sheet and narrowing of focus to that towards the Bakken and Guyana?

No I think, as we mentioned in our opening remarks, we are giving consideration to increasing the rig count in the Bakken in 2018 to 6 rigs. We have not made that decision, but it certainly, it'll be part of our calculus as we do the budget this year.

And that is a function of your outlook on oil prices or the narrowed focus? Not that it maybe matters, but is that -- would you put that in the, "this would have happened anyway camp" or as a result of the asset sales?

Yes -- no. I mean it's primarily returns driven. We've just got such an outstanding inventory in the Bakken of wells that deliver outstanding returns all the way down to $40 and $50. So we want to get after that business in 2018. Again, have not made the decision yet, but we're giving it strong consideration.

Our next question is from Arun Jayaram of JPMorgan.

Greg, I had a couple of questions on the Bakken. I wanted to see if you could comment how your testing of higher Bakken proppant concentrations are going? I think you're shifting to 140,000 pounds per stage. And also if you could kind of discuss the uptick in completion costs from $1.8 million to $3.1 million sequentially in 3Q?

Yes, you bet. So as I mentioned in my opening remarks, our average well costs in the quarter were $5.8 million, and about 3/4 of the wells were these high-proppant loading wells, 140,000 pounds per stage, and those averaged about $6 million in the quarter. We fully expect those costs to come down as we apply lean manufacturing to the new completion design. The results of the 60-stage wells again, as I said in my remarks, are encouraging. They are early in their type curves but again, the EURs are anticipated to be over 1 million barrels per well in 2017. The actual uplift for modeling and predictive analytics is estimating a 10% to 15% uplift in IP 90 rates and we're actually seeing that in the field. So, so far, things are matching the models. I do want to get more type curve performance, but in January of 2018, we'll be able to give new guidance on: what is our standard completion design, what IP 90s can we expect, what well cost can we expect and what EURs can we expect. But so far, very encouraging and value accretive moving to the 60 stages and the 140,000 pounds per stage.

And I just also want to clarify one thing on your question, because again, we're seeing all positives. But the way -- when you asked the question, you said the increasing costs from second quarter to third quarter, if you're looking at our supplement, make sure you look at the footnote down there. We have apples and oranges between the second and third quarter. If we had broken out the second quarter, the 60 140 wells and the 50 70, there was no increase actually in cost from the same type of wells being drilled. The thing was, we were just doing pilots here in the first and second quarter, so we were only putting the 50-stage fracs with the 70,000 pounds proppant there. And so now in the third quarter, since we've moved basically to the 60 140s, we're just including all the wells there. So I just wanted to clarify that there's no real increase in our well cost.

That's very helpful. And just, Greg, the oil mix was a little bit light of our numbers in 3Q in the Bakken. Was that impacted by weather or anything?

Let me talk about this mix issue, because we always get the question. The first thing is, there is no change in product mix at the wellhead. So overall GORs have remained flat at about 15 50 a -- standard cubic feet per barrel of oil. And we expect the oil -- our oil mix to stay in this kind of low 60% range for a long time. Now the decrease in Q3 reflects 2 things: first is, lower oil production due to the weather, because we had lower field availability overall and lots of road closures; and then that was coupled with a 20% increase in previously flared wells being connected to our gas gathering system. So you had lower oil volumes due to weather, plus you had a significant uptick in the number of previously flared wells being added to that midstream business that we have. So that's what's causing the mix change quarter-to-quarter. Now as I said, we expect to remain in the low 60s -- lower 60s for the foreseeable future. Oil, however, is expected to grow at 10% a year with 4 rigs. But we will continue to hook up more previously flared gas to generate more profit in our midstream business. So there will be these quarter-to-quarter fluctuations depending on all those various well hook ups.

That's helpful. And just, Greg, could you give us an update on Stampede? Looks like it's running early and could come online in the first quarter. Could you just give us a sense of how you expect the production profile to trend at that project?

Yes, thanks. So first of all, thanks. I mean, Stampede is about 6 months ahead of schedule and it's running well below budget, particularly on the drilling side. On the drilling side, we're 15% to 20% below AFE on the drilling side, so that's going extremely well. I think what the industry has learned in the Gulf of Mexico is that you need to ramp these wells up slowly and carefully. So we don't expect to reach our peak in Stampede until 2019. Our current development scope has 6 producers and 4 water injectors, and those will be ramped up slowly over 2018.

Our next question is from Doug Leggate of Bank of America.

If I may, I'm going to put 1 for all 3 of you, if you don't mind. John Hess, I'll start with you, if I may. So John, you've made a lot of steps, obviously, in the last couple of days, and you've seen what's happened to your stock. The market clearly has some concerns about something. If you really believe in the value of what you're doing in terms of Guyana, I know you've talked about it already, but to pull everything together, cash in the balance sheet, hedge protection, the dividend burden and the pending sales next year, likely including Ghana, I'm guessing, why wouldn't you send a more obvious signal to the market on the buybacks? Because your stock's suffering. The steps aren't being recognized, and the best M&A you can do in the market right now is your own share. So can you address that, and maybe give some thoughts as to the scale of what you might consider? Because, I think at this point, the market needs some kind of message from you, John.

Thanks, Doug. Obviously, I think the first point is we just completed these asset sales yesterday with outstanding results. And I think we bought a lot of value forward. It certainly exceeded, on an NAV basis, most of the third-party estimates and certainly exceeded expectation in terms of both proceeds and timing. So this just happened yesterday, that's #1. Number -- and really, what that does, as you point out in a $50 forever world and whatever ones we use of oil prices are, you want to be financially prudent here. We basically brought forward these values and bolstered the cash on the balance sheet that we can prefund Guyana. And that's a big deal because Guyana is a great return. People often talk about living within their means. Well, by bringing the cash forward, we are living within our means to -- meaning that we can prefund this world-class investment opportunity. Having said that, now that we have completed the sales, we can deliberate and bring clarity to the very question you're asking. And the importance of cash returns to shareholders, given the strength of our cash and current liquidity position, obviously, gives us an opportunity to consider bolstering cash returns to shareholders as appropriate. We are going to do that. We've won a little more visibility into Exxon's plans for Phase 2 and 3 of the Liza development in Guyana. But once we have that clarity, I can assure you, we are going to clearly consider improving the cash returns to our shareholders as appropriate because you're right, our stock is a great investment.

All right. I'll -- maybe a new one to #2, if I may, and this is just very quickly on CapEx. On the last call, John Rielly, I guess, you indicated that the CapEx in 2018 would be similar to 2017 at $2.1 billion. With all these moves, can you give an early look at directionally how that would -- that CapEx (inaudible) should move next year?

At this point, I'd still -- I'd stick with that guidance, and here's what the difference is from that last quarter is. So we do have the asset sales. So Norway, you're in that $120 million to $130 million of capital this year that will not be there next year. EG was very low. Now as Greg mentioned, we are considering adding 2 more rigs in the Bakken during 2018, so you do have that type of offset. So we're still looking at being flat, but we're going to be going through our normal budget and plan process, and we'll be updating that with our fourth quarter numbers.

Okay. My last one, if I may then, is for Greg. So Greg, on the production guidance, at the start of this year, the fourth quarter guidance was 330,000 to 340,000. Can you walk through in a little bit more detail, perhaps, on what that momentum you talked about going into the first quarter looks like because even adjusting for 1 month of Equatorial Guinea and, I guess, a full quarter of Norway, it still seems that the guide is a bit light? So could you help us understand or reconcile what the differences are and what you would expect going into Q1?

Doug, let me split your question into 2. The first one is just the fourth quarter guidance compared to our third quarter actual production, which I think was part of your question. So as I mentioned in my opening remarks, the asset sales will be 14,000 to 15,000 barrels a day negative depending on timing. We talked about the knock-on effects in the Gulf of Mexico, particularly as it's associated the Penn State 6 and then the unplanned maintenance downtime from the Shell-operated facility on Enchilada that affects Conger. The combination of those 2 things is about 8,000 barrels a day. And then you get the reversal of that temporary NEI adjustments JDA, which is another 8,000. Now all that to offset, though, by North Malay Basin coming up to full field ramp-up and then also the Bakken. So that's why we guided this 290 million to 300 million in the fourth quarter relative to the 299,000 we experienced in the third quarter. In regards to your momentum question, I mean, if you think about it, year-to-date, we've only been -- our average rig count in the Bakken is 3. That will be fully 4 rigs as we go into 2018. And as John Rielly mentioned, that could be 6 rigs in 2018. That's one piece. You have Stampede coming on stream into -- in early 2018 now in the first quarter, so that will be another strong production momentum. And the final thing as you'll have North Malay Basin fully at plateau. So those 3 pieces are really what are going to provide the strong production momentum as we go into 2018.

Our next question is from Roger Read of Wells Fargo.

I guess, can we talk a little bit about -- from a micro standpoint, price realization in the Bakken came in a little bit lighter than would have thought, whether hedged or not hedged, DAPL opening up would've expected a little bit better. Just curious maybe what some of the moving parts were there.

So in the third quarter, when you compare the third quarter to the second quarter, actually, even with DAPL, the Clearbrook was essentially unchanged, the second quarter to third quarter. And now a good majority of our production doesn't go to Clearbrook just like all other operators. You have to get it out of the basin. So with Clearbrook essentially unchanged and you're moving your product outside of North Dakota, you just have some additional cost comparatively between the second and third quarter even with DAPL starting up. So that's where -- that is in the third quarter. Now right at the end of the third quarter going into the fourth quarter, Clearbrook has clearly improved. So those values from Clearbrook would show up more in the fourth quarter.

Yes. And we're also taking advantage of the export market year-to-date. We've had 3 exports. In fact, I think we're one of the first company, if not the first company, to export Bakken crude 1 year ago. So we actually have had 4 exports over the last 12 months or so. So we basically optimize all of our marketing outlets to maximize value. And over time, that's created relative superior value at the wellhead versus any of our competitors in the Bakken.

No. Appreciate that. Just curious if there's anything other than market conditions, but it sounds like that's all it is. And then sort of a broader question is you've gone through the asset sale process. And clearly, the goal here to get overall operating cost, whether cash or noncash down. You've done some of these asset sales. And we've seen both gains and losses as you adjusted to what the underlying asset values were. I was just curious if you step back and look at the overall portfolio here going forward, are there any more sort of asset write-downs that will affect depreciation in the future? I know this is an annual test kind of thing in prices at the end of the year. But I was just curious if that's any component of future lower DD&A or if we should think about it solely as the new projects coming in or simply better than what's going out the door.

Well, first, you should start with that. That -- the new -- I mean, the new projects or the projects like Bakken and Guyana, they're going to have better returns than the assets that we were divesting. So clearly, that's going to drive improvements in cash cost and DD&A and F&D, everything, as we spoke about before. As far as just accounting, we go through and it goes on a quarterly basis. You evaluate what prices are. We'll be going through our budget and plan with the board and setting price parameters in the fourth quarter. And we'll look at all assets at that point in time on where prices are. And then you go through your normal impairment reviews at that point in time. But that will happen on a quarterly basis.

Our next question is from Evan Calio of Morgan Stanley.

Yes. Maybe another follow-up on the cash balance question for John. Really reading between the lines of your comments, you mentioned you had a better idea on Guyana Phase 2 and Phase 3 timing in the next few months that you could consider a potential buyback at that time. Yes -- I guess, my question is on the spending side. What is the earliest you could be spending on Guyana Phase 2 and Phase 3 post-FID-type spending? Meaning, is there a reasonable scenario where you will need the cash from asset sales to support or to bridge to the post-lease's startup period?

Evan, this is Greg. So again, Exxon is still working on it. We are in early phases of FID on Phase 2, but we just can't be specific yet on the exact timing of when Phase 2 and Phase 3 could come about. I mean, clearly, with 2.25 billion to 2.75 billion barrels of recoverable, you're going to need more than just Phase 1 to get at that. But timing on both of those is I don't want to comment on because Exxon is still in various phases of planning that. We should have clarity on that, as John mentioned, as we go through the budget process by year-end.

And that's clarity through kind of 2020 time frame, then.

Yes.

Maybe a different question. I know you guys have been successful and very active in high grading the portfolio. Again, an asset that you didn't discuss, you discussed the attributes that make Malaysia core to remain in the portfolio, given that would likely be an accretive sale if pursued. Can you talk about how that fits?

Yes. So -- I mean, just when now -- when you look at our portfolio now and as we get through to 2020 with Guyana, we want to be in a situation there. We're set ourselves up in this portfolio that we've got a low-cost, cash-generative portfolio and have the ability through these asset sales to bring cash forward to prefund effectively Guyana. What Malaysia now provides us, and I'm saying now is because we were developing North Malay Basin, North Malay Basin now is coming on. It's ramping up to its full production capacity. Putting North Malay Basin and JDA together, I guess, the best way I describe this is a nice long-term infrastructure asset that provides this cash brick, just cash flows year in, year out in your portfolio. And it's both the JDA and North Malay Basin, obviously, their PSCs, prices go down, you get coverage as prices go down. So it's a great part. This Malaysia asset is just really key for us to drive our cash flow to help fund our assets. Now going forward, you never know, long term, what happens, but Malaysia is, right now, a key core asset for us to generate cash flow and drive us through to 2020 as Guyana comes on.

Yes. And another way to bring perspective to it from a strategic viewpoint is the cornerstone, our core of our portfolio is going to be Guyana and Bakken, which are low-cost, high-return growth assets and the deepwater Gulf of Mexico and Malaysia, which are low-cost, cash-generating assets. The focus in the portfolio is much sharper. It's the areas that are low cost. And basically, we are redeploying the capital from the high-cost mature assets into the low-cost, high-return assets and, at the same time, simplifying and focusing the portfolio, which, we think, will bring forward a lot of value for our shareholders.

That's great. Maybe one more, if I could. Just on the Bakken, more minor. Can you talk about what drove that sequential declines on the 90-day (inaudible) there? I know it appears that most of the programs is well within the McKenzie area. Just trying to understand the -- that variance.

Yes. Thanks for that, Evan. I figured that would come up. So in the third quarter, the IP 90s averaged 840 barrels of oil per day, which is fully in line with our guidance of 800 to 850. Now in the second quarter, we had IP 90s that were over 1,000. So what's driving that? Really simple. It's where the rigs were located. So those IP 90s in the second quarter were reflecting 8 wells in the core of the core of the Keene area, which is the absolute best area in the field. I think if you step back, though, as John mentioned in some of his remarks, our IP 90s have averaged 890 barrels of oil per day over the first 3 quarters of 2017 versus 580 barrels a day over those same 3 quarters in 2016. So that's an improvement of about 50%, just comparing year-on-year in IP 90s. So the trend is outstanding. And again, that's from these higher-stage counts and then as we move into higher proppant loading as well. So the quarterly fluctuations is purely a function of well mix. And as we added rig 3 and 4 in the Bakken, we had to spread those rigs out because operationally, you have SIMOPS issues, infrastructure that you're trying to balance, so you move outside of that fantastic core of the core rock in Keene. You had put rigs in other areas of the field. But again, just look at the overall average, very substantial improvement in IP 90s. But there will be fluctuation. Yes, there will be fluctuations quarter-to-quarter just based on well mix.

And 5 and 6 will add to that, I presume.

It will. I mean, in terms of operational flexibility, you'll have to move into other areas of the field if you have 6 rigs versus 4. And we'll give guidance on that if we make the decision to go to 6. If we -- and we'll give guidance on that in January, just like we always do, yes.

Our next question is from Pavel Molchanov of Raymond James.

This is Muhammed on behalf of Pavel. So the 2 recent asset divestitures that you guys announced in EG and Norway, those are both pretty high-tax countries. How do you expect the closing of those divestitures to affect your income tax rate?

Sure. So I gave on -- when I gave the pro forma numbers, you saw the benefit that we were recording was -- our actual was 18% in the third quarter. And on a pro forma basis, that goes down to 2%. So it all depends that -- what that means is, as you can tell, those assets had losses and were generating losses in the portfolio. And so we'll have less losses and you won't be benefiting, just like you said, at those higher tax rates.

Okay, yes. Sorry, I must have missed that. One other question for me. So last month, the International Tribunal for the Law of the Sea decided in favor of Ghana in their maritime dispute with Ivory Coast. How do you guys expect to proceed with your, I guess, the acreage in that region or in that offshore of that country? Are you guys trying to do continue drilling or monetize that acreage?

Now that there's clarity on the border dispute, we can proceed with the best way to optimize the value of the asset.

So no more details other than that.

Correct.

Our next question is from Paul Sankey of Wolfe Research.

There's a tremendous interest in the market, particularly on the buy side, for return on capital employed improvements. And I was hoping that you could walk me through the path to a better return on capital employed for Hess, perhaps, over the next 5 years. I think we all understand that you're outspending for Guyana. It seems that with the hedging you've announced, you're kind of planning on $50 or sort of locking into $50, certainly, for next year. It sounds like it will be flat CapEx. So with cash on the balance sheet, I can get there on the cash side of the story. The problem, I think, has been the shareholder equity keeps shrinking. And we're seeing net income losses. And I guess, the easy thing might be John Rielly first to talk about DD&A reductions given what you said about marginal barrels being so much higher return than trailing barrels. But any help you can give me on that would be great.

Sure. I mean, the -- I mean, obviously, I think we've said it over and over, the whole goal of our strategy here in this portfolio moves are to improve the returns on invested capital. So that's what we're focused on. So now by selling those high-cost assets and just from that prior question, as you know, those assets just from -- as I told you, on the pro forma tax rate were generating losses in the portfolio. And you're right, we are doing all of this and planning for, can call it a low price or an extended $50 oil price environment, and we believe we've set ourselves up to win in this $50 environment because, one, now we have the cash to be able to fund Guyana, just like you said. And then the assets that we will be investing in, which are Guyana, and we've gone through the returns there and I know we've gone through this, we have it in our investor deck of how Guyana can compete and actually do better than even some Permian, Delaware-type assets and a low-priced environment. So that will improve our returns. And like we said earlier, Liza has a $7 F&D, so that will drive down DD&A. So Bakken as well, we'll continue with the investments that we'll have at 4 rigs. And as you know, we're evaluating going to 6 rigs. The reason we're evaluating going to 6 rigs is because of the tremendous returns that we see in our portfolio there. And we have plenty of well locations that work at sub $50. So that will also low F&D and improve returns. And both Bakken and Guyana are going to be at a cash cost lower than our current portfolio average. So the returns that we generate there are going to improve. And the point -- and the goal and, I guess, the way you can measure it is as we say post Guyana in a $50 world, when that comes up, it's all these investments will be generating free cash flow post the Guyana production starting up. And then, as you will start to see that, we'll generate post the Guyana production, again, net income will continue to increase along with that cash flow. So it is all about trying to shift and reallocate the capital in our portfolio to the highest returns. And we believe the Bakken and Guyana investments will really drive that improvement and return on capital employed.

To be specific here -- I understand that. Could you be specific on the dynamic of the DD&A coming down? Do we have (inaudible) for DD&A to start getting that net income improvement that we want?

Okay. So I mean, you heard, at least, from a pro forma standpoint, we're dropping in the third quarter that it went over $1. So that's one thing just starting there. When these assets come out of the portfolio, you're going to get that. Every time we bring on a new barrel in the Bakken, with this F&D, that's driving down our DD&A rate. And then Guyana now, the big change there with the F&D there, that won't happen until 2020. So it's just going to be a progression as we move through from 2017 to 2020 on driving down that DD&A rate. And like you said on the -- we've talked about on the cash cost, you can just start from where we are right now at $14 driving it down to under $10 as we go to 2020. So it's just going to be that slow progression on cash cost and DD&A as we move through.

Understood. So could you -- just very finally, could you guide me to DD&A for next year?

No, I can't exactly at this point, but I can do that on the fourth quarter. If I -- with all else being the same, you would use this pro forma number of -- that I said were $23.72. And then that would come down based on the investments and the growth that we have in the Bakken coming through. So it will be lower than that number in 2018. And then we'll continue to look at all the assets and -- on our portfolio mix. It depends on where production is as we go into 2018. And I'll update on our call then.

Our next question is from Jeffrey Campbell of the Tuohy Brothers.

And congratulations on the recent asset sales. Maybe another way to ask a question as sort of tangential to some of these discussions we've been having around the portfolio and uses of cash. You said that Guyana will be self-funding once Liza Phase 1 comes online or, at least, I believe that's what you said. And there's obviously a lot of future development there. Do you have any idea how long you think it will take to generate free cash flow from Guyana development?

No. It's too early to comment on that because, again, it depends on the timing of Phases 2 and 3. And we hope to get clarity about that from the operator and ExxonMobil before the end of the year.

Yes. Just for Phase 1 -- as we've said in meetings with investors, just Phase 1, in and of itself, you get your cash back in about 3 years from first production. So that's infinitely superior to any shale investment you would make, that 7 to 10 years, even the best of shale. So the cash-on-cash returns in Guyana are much superior to anything you could get in shale. It's not a disparage shale. Shale is a different investment profile. But Guyana is truly superior to almost any other investment you can make in the E&P space in the world. So we can talk intelligently about Phase 1 because we've authorized it. We just have to wait for the phasing of Phase 2 and Phase 3 to give you the macro picture on Guyana itself for Hess.

I appreciate that and I think kind of where I was trying to go is before people get so comfortable with selling assets that are obviously generating free cash now, one should step back and think about when free cash flow is going to emerge from Guyana. If I could ask one other Guyana question real quick. Does the success of Turbot influence your confidence in pending Suriname exploration in any way? And can you remind us what's coming up for exploration there?

Yes. So Block 42 in Suriname, as you mentioned, we see that as being part of the same play fairway as Liza. We're currently interpreting in 3D seismic there and evaluating to drill a well in 2018. So Block 42 looks great. And of course, we also, as you know, entered Block 59 along with ExxonMobil and Statoil. That's 1/3, 1/3, 1/3 equity each. That's a very big block. That's 500 Gulf of Mexico blocks. We also see it as part of the same play fairway as Liza. And the coal ventures now are just beginning to plan seismic program. So 42, likely a well in 2018. 59, too early to comment on when we might be drilling there because we got to get the seismic done first.

Our next question is from Ryan Todd of Deutsche Bank.

Maybe just 1 first question on some of the guidance you provided with the asset sales on a move towards a $10-barrel OpEx target and $150 million in cost savings by the end of this decade. Are there any efficiencies built into the assumption? Or is it just a result of drilling off higher-cost barrels and overhead? Or could we see upside to those numbers from additional efficiencies? And maybe what level of activity in the Bakken is embedded in those numbers?

So what we have in those numbers to get down to the $10 is I'm not assuming any efficiencies per se in there. So I mean, again, it's -- our teams have been really good on continuing to drive down our cash cost across our portfolio. So there are potential upside to those numbers. So you do have the higher-cost barrels that will be coming out. And then you have the $150 million of cost savings, which I did not factor into those numbers there. Then what helps you drive is kind of the -- going back to what Greg was talking about on a pro forma production momentum. So you have North Malay Basin, which is coming in at the full rate starting in 2018. That is one of the lowest cash cost assets we have in the portfolio. Stampede coming on. Gulf of Mexico assets, very low cost. So that will continue to drive down the cash cost. And then you have the Bakken. So activity levels that we talked about in here, we've got the 4 rigs in here. We know we're considering going to 6. We have the 4 rigs and the additional production that you can talk about. Our oil production growth of 10% per year with that low cash cost will also drive down the cost. And then obviously, when Guyana comes on, you get the final piece to drive it down. So yes -- no, we're not assuming any heroic efficiencies or anything in there. It's the quality of our assets and the investments in these high-return assets, along with the start-up of our developments, that will drive this cost down to $10 and below.

Great. And then maybe in light of all that talk about portfolio activity, any comment on how the Utica fits into this in terms of longer-term plans and ability to attract capital within the portfolio?

Yes. I think the Utica, as you know, the only challenge with the Utica right now is just the netbacks because it's infrastructure constrained. We see those infrastructure constraints opening up in 2018/2019. I always have to remind people it's a good position in the Utica. It's in the heart of Lakewood window. It only has 5% royalty. It just needs some help on price. It offers good growth. Currently, it doesn't -- and currently, it does not compete with the Bakken, obviously, so it's going to be a function of price as to what we do with Utica. But it's got good returns at a reasonable gas price, so...

Our next question is from Paul Cheng of Barclays.

Greg, on Turbot, I assume you will be an individual development, not a tie back. And from that standpoint then, what is the minimum resource size in order for that to be economic at $50 Brent?

Yes, Paul. It's -- obviously, it's -- we're very excited by the discovery, as we mentioned in our opening remarks, because it opens up a new province or area in the southeastern part of the block. It's too early to kind of speculate on how much volume it's going to take, et cetera. It's got its own sort of unique attributes. But it's very encouraging and very exciting. We will want to get an appraisal well in it sometime in 2018. Once we have that appraisal well, we'll have a better idea of go-forward development plan for the -- I'll call it, the greater Turbot area.

And the Turbot at 75 feet, you see a continuous column or there is several different columns.

It's broken into just a couple of sand packages. But there is one very large thick package within that column, so that's going to be a big target.

So that when you say they're very big, you say, what, 60, 50 or up to 75 or 40?

No of the 75. I think it's around 60 of it.

Okay. And the mix on Bakken, Greg, you -- earlier, you mentioned that one of the reasons why -- or the primary reason why the IP 90 changed from the second to third quarter is because of the core of the core well, the conversation changed. Can you tell us that what is the average differences between the core of the core well and the rest of your portfolio?

Well, I think, again, Paul, you have to look at kind of what our guidance is for the year. So 800 to 850 is what we guided for the IP 90s for the year. And again, in Q2, the core of the core, which is was the Keene area and it was only 8 wells, was the IP 90s coming in there are around over 1,000. So I would just say look at the average. The 800 to 850 is a good reflection of the average of the core that we're drilling this year. But within that, there's some very outstanding wells, obviously.

Because it seems like Keene is maybe more likely in the 1,300 to 1,500, I would presume.

No, because in Q2, the IP 90 results were reflected there were only 8 wells in Keene, right?

So it will be even higher than that.

Yes. And Paul, just let me clarify that. So in Q2, we are -- we quoted over 1,000 IPs. Again, that's 8 wells right in the heart of the Keene. So that is the average of 8 wells. And they were all about the same. So they were all around that 1,000 to 1,100 oil IP 90.

Okay. Very good. And on the 2,800 additional drilling locations that you have in Bakken, roughly, how many of them are in the -- what you call, the core of the core?

Well, I think a better way to think about that is, which we've done in our investor conferences, there's a slide in our pack, is if you look at the inventory now, I'm going to describe this as 50-stage, 70,000 pounds because it hasn't been updated for a 60-stage and 140,000 pounds. So these numbers will change. They'll get better. But certainly, it's 50,000 -- or at 50-stage, 70,000 pounds, we have about 1,500 wells of the 3,000 that generate an after-tax return of 15% or higher at $50 Brent -- or $50 WTI, sorry. So that gives you an idea that at least half of the 3,000 wells generate a very high return at this kind of prices. So that gives you a sense, right, for how much is there.

Okay. All right. And then final one is for John Rielly. John, on the $150 million restructuring, can you give us some additional -- elaborate a little bit more in terms of some details on number of head you're going to cut, the area that where -- that they're going to come from, the functionality, that kind of things?

So it will be across the board. I mean, I think you'll -- you will see the majority from an income statement line item will be in the G&A line item. But we will have -- some that will be -- some of our reduction will be in our operating cost as well. And just like -- we will be finishing all our work on that and our organization redesign in 2018. And we will have transition cost in 2018 that offset some of these savings. So it's really from 2019 on is where you'll see this $150 million cost savings kind of flowing through our numbers.

And can you tell us that what is the number of headcount that you plan to reduce? And where is the -- is it in your corporate headquarter? Or is it going to be in your Houston office? Or what kind of function because it will be a pretty big number?

Yes, it's a big number. I mean, obviously, with Norway, EG and then -- and Denmark being sold, there is reduction in our portfolio. And what we're doing is just rationalizing our fixed cost base that we have here to support our production portfolio. And it's just going to be part of that. We've done high-level design on this. The reductions will be across all aspects, be it central functions, be it corporate, be it E&P. So we're looking at all of that. And as I said, we'll -- you will start to see it in '18 because we will be enacting it. It's just that we will have transition cost in 2018 and get the full benefit in 2019.

Yes, because I just -- stretching my head a little bit, given that in Baja, you are not the operator, so I would imagine the cost in your back-office support cost associated that is not that great -- or not that high. And just for Denmark and EG, seems like the elimination of those 2 offset translated into $150 million in reduction in G&A cost. That seems a very high number.

So we've -- look, we have put it on paper and we feel comfortable -- very comfortable with that $150 million. You've got to factor in a lot of ancillary cost. So you've got supply chain activities in every one of those areas. We've got tax activities in every one of those areas. We do have finance support in all of those areas, IT support in all of those areas. So we've looked at all of that. And so it's -- it will be headcount. It will be other operational-type cost that will be reduced. And I would tell you, I feel very comfortable about the $150 million by 2019. Again, we will incur this transition cost in 2018.

Great. Just a final one. Is that means that the bulk of the -- from a P&L standpoint, so I mean, in your CapEx (inaudible) number or this is showing up in your U.S. E&P earning number?

The bulk of this was because the support is really for our E&P. So the bulk of it will be in the E&P numbers being able to reduce our cost within E&P. But there's going to be clearly corporate cost reductions as well.

Our next question is from Bob Morris of Citi.

It's kind of quite a long time here, so I'll be brief here a bit. In looking at 2018, even with a flat budget, at $50 oil, $3 gas, you'll have spent cash flow and, I guess, the returns in the Bakken and adding perhaps 2 more rigs, but how do you think about the cash flow outspend in that environment? Is there a limit as to -- with the cash on the balance sheet, how much you're willing to outspend cash flow in 2018? Or how do you monitor that?

Yes. I think the key point here is the Bakken itself has to be cash generative. One of the reasons we went to 2 rigs and then 4 was to ensure in a low-priced environment, it would not only grow, but be cash generative. But one of the holdbacks on the Bakken was the corporate cash position. Now that the corporate cash position is better, we can invest in the higher-return, low-cost projects. The Bakken, really, is one of those first calls on capital along with Guyana. And that really underpins sort of the base spend along with some of the investment that we still have to do in Stampede and the JDA, even though they're going from cash users to cash generators. So that really speaks for, like, 90% of the spend that we're going to have next year. And I can assure you, we're going to keep it very tight, minimize the outspend. But most of the outspend is being driven by the need to invest in Guyana, which, again, offers superior returns to almost anything else in the E&P business. So we're very mindful of the corporate position. And that's why we're really redeploying the proceeds from the high-cost, lower-return and mature assets to the lower-cost, high-return assets, which really positions the company for a much lower unit cost than improved cash generator and return on capital employed for many years to come.

That's great. That makes sense. And then Greg, just quickly here. You mentioned that the average EURs this year for the Bakken are sort of trending to just over 1 MBOE, but that appears to be a mix of the $50, $70 and the $60, 140 wells and if we break out the data on just the $60, 140s, those appear to be trending at something a little bit better than 1.2 MBOE. Is that on target there?

Yes, I think it's -- I think you're in the range. Again, it's early days, so I want to see more type curve performance before I'd be definitive, but you're definitely in the range. I just want to clarify one thing John said. The spend in Malaysia next year is not JDA. It's actually North Malay as we have to add some more wells to stay at capacity.

Thank you. Yes, I meant Malaysia overall. Exactly.

Our next question is from David Heikkinen of Heikkinen Energy.

You actually got all my questions.

Our next question is from John Herrlin of Societe Generale.

Yes. A couple for Greg and then one for John. Regarding Turbot, Greg, how would you characterize the structure, vis-à-vis Payara or this Liza because it's a big step out? Is it a similar kind of structure? Could you describe a little bit more?

Yes, it is. It's -- I mean, it's basically a stratigraphic trap, so it's like the Liza complex, again, playing the stratigraphic traps that get trapped in the rim of the bowl as the sediments before they plunge down into the basin. Very similar.

Okay. Regarding inflation, you locked in some sand purchases earlier this year for this year. Are you going to do that again in '18? And what are you seeing on the inflation side in terms of cost or if it's early?

Yes, you bet. So I think it's -- again, I think as I said last time, it's really a tale of 2 cities, right? So in offshore, we see flat to further declining cost. Rigs and shipyard construction, in particular, are experiencing further downward pressure, which is being reflected in the Guyana development. Onshore, industry cost trends are increasing. But as we mentioned, we have taken steps to contain the cost by not only locking in rig and pumping rates, but also prepurchasing sand and putting in place some longer-term contracts on many of those services. So at least in 2018, those steps that we've made in our lean manufacturing approach, we think we can deliver our 2018 program with minimal inflation. There will be some, but it will likely be single digit. It won't be massive now. As we do our budget in 2019, we'll be relooking at all that. The pressure on sand has gone off as more minds have opened up. That was a transitory thing. And that's why we locked in the proppant. And we're still in the money on that deal, so that turned out to be a good deal on the end.

Okay. My one for John Rielly is the headcount. Obviously, you just sold assets, so how much smaller is -- of the Hess workforce could it be, ballpark?

So at this point, we're not going to provide that number. It's -- the cost reduction of $150 million are going to run across the board. There will be headcount reductions. There will be vendor cost reductions just due to the size of the portfolio, again, smaller. But it's just premature for me to give those type of numbers.

Yes, we've had over the last 2 years probably a 30% reduction in headcount, and there's more to come. So people want the sizing. Obviously, it's a work in progress. It has to do with the reshape portfolio. We'll reshape the organization, minimize corporate and then really rightsize the organization to support the asset portfolio we're going to have. So we don't want to front run the announcement on that. But at the end of the day, I want you to know there's been significant reductions already.

Our next question is from Ross Payne of Wells Fargo.

Free cash flow, you're currently producing a decent amount of it. And even after asset sales, you'll have a reasonable amount. Is it one way to look at this as the current free cash flow covers the core CapEx for the company and then the asset sales are funding most of Liza? And second of all, it's $1 billion for Phase 1 of Liza. Can we estimate about the same number for Phase 2 and maybe another $1 billion for Phase 3?

So your estimates, you're exactly right on the cash flow and that the asset sales are coming in to fund this great opportunity that we have in Guyana. As you said, you have that Phase 1 cost. We don't have any guidance out there. The only thing I will tell you is that the initial Phase 1 FPSO is -- has a capacity of 120,000 barrels per day. It has not been landed what Phase 2 and Phase 3 are, but it could be likely to be at a larger size than that 120,000. But outside of that, we haven't had any additional guidance that we're able to give out at this point in time.

Okay. And then on the share repurchase, would you pretty much want to hear what Phase 2 and possibly Phase 3 is going to look like before you step into stock repurchases? With the excess cash, it looks like you're going to be bringing in from this plus Denmark.

Yes, I mean, the thing on Phase 2 and Phase 3, I would say Exxon is pretty far along on getting that definition. We just want to a little more clarity on that. So it's not that far out in time when we would be able to get that clarity. And then while we want to maintain a strong liquidity position to make sure we can prefund Guyana, which is a great investment, once we have that clarity, obviously, we will clearly consider cash returns to the shareholders as appropriate.

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