赫斯 (HES) 2017 Q2 法說會逐字稿

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

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

Thank you, Jay, and good morning, everyone. Welcome to our second quarter conference call. I will provide an update on our progress in executing our strategy, including a number of major milestones achieved in the quarter. Greg Hill will then review our operating performance, and John Rielly will review our financial results.

We believe our company has the best long-term growth outlook in our history as well as one of the best in the industry. It is value driven with an increasing resource base, production growth, lower cost per barrel and improving financial returns. Our growth is underpinned by 4 key areas: The Bakken, North Malay Basin in the Gulf of Thailand, Stampede in the deepwater Gulf of Mexico and offshore Guyana.

With regard to the Bakken, we have an industry-leading strategic position with more drilling locations in the core of the play than any other operator. We are currently operating 4 rigs that, with 60-stage fracs and increased proppant levels, should deliver production growth of approximately 10% a year over the next several years. With our productivity and technology improvements, we now forecast virtually the same production growth with 4 rigs that would have taken 6 rigs a year ago. We will decide whether to add 2 additional rigs as originally planned based on an improvement in crude oil prices and the results of our enhanced completions.

Second quarter net production in the Bakken averaged 108,000 barrels of oil equivalent per day compared to 106,000 barrels of oil equivalent per day during the second quarter of 2016. For the full year 2017, we forecast Bakken production to average approximately 105,000 barrels of oil equivalent per day, at the high end of our previous guidance of 95,000 to 105,000 barrels of oil equivalent per day due to strong performance by our Bakken team and results of our new completions.

In the Gulf of Thailand, the North Malay Basin full-field development achieved first production of natural gas earlier this month. Hess is the operator with 50% interest, and PETRONAS is our partner with the remaining 50%. We are still in the process of commissioning the field and expect net production to reach its planned plateau rate of 165 million cubic feet a day of natural gas during the third quarter. North Malay Basin is expected to generate strong and stable production and cash flows for many years to come.

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. Net production is expected to increase throughout 2018 and reach a peak rate of approximately 15,000 barrels of oil equivalent per day.

Turning to Guyana, where Hess has a 30% interest in the Stabroek Block and ExxonMobil is the operator. In June, we announced positive results from the Liza-4 well, which encountered more than 197 feet of net pay. Yesterday, the operator announced successful results from the Payara-2 appraisal well with 59 feet of net pay, which confirms a second giant oil field discovered in Guyana and increases Payara gross discovered recoverable resources to approximately 500 million barrels of oil equivalent. Gross discovered recoverable resources for the Stabroek Block, which include discoveries at Liza, Liza Deep, Snoek and Payara, have now been increased to an estimated 2.25 billion to 2.75 billion barrels of oil equivalent. In addition to the considerable resources discovered to date, we see additional multibillion barrels of unrisked exploration potential on the Stabroek Block.

In June, we also sanctioned the first phase of a planned multiphase development of the Liza Field, which is expected to have a gross capital cost of approximately $3.2 billion for drilling and subsea infrastructure and will develop approximately 450 million barrels of oil, with first production expected by 2020. The development will utilize a leased floating production storage and offloading vessel that will have the capacity to process up to 120,000 barrels of oil per day. The Liza Phase 1 development offers very attractive financial returns and a rapid cash payback with a manageable pace of investment.

Hess' net share of development costs is forecast to be approximately $955 million, of which $110 million is already included in our 2017 capital and exploratory budget. Of the remaining net development costs, approximately $250 million is expected in 2018 and approximately $330 million in 2019, with the balance in 2020 and 2021. Our success in Guyana is transformational and positions our company for a decade plus of resource and production growth with improving returns and cost metrics.

Funding these growth opportunities requires a strong balance sheet and liquidity position, which remain a top priority for our company. At June 30, we had $2.5 billion of cash and total liquidity of $6.8 billion. And we continue to take steps to keep our financial position strong. In April, we successfully completed the initial public offering of Hess Midstream Partners LP, resulting in net proceeds of $175 million to Hess Corporation. The MLP structure will allow us to further unlock value with a combination of embedded growth in EBITDA as Bakken production continues to increase and through future dropdowns. Hess Midstream Partners LP will announce its second quarter results tomorrow.

Our success in Guyana also provides us with the opportunity to consider the divestment of mature, higher-cost assets, which can accelerate their value while upgrading our overall portfolio and also providing additional funding for our high-return growth opportunities.

Last month, we announced an agreement to sell our enhanced oil recovery assets in the Permian Basin for a total consideration of $600 million. This transaction is on track to close on August 1. In addition, we expect net cash flow to improve over the next several years as our $700 million of annual spend for North Malay Basin and Stampede winds down, and these 2 projects go from being sizable cash users to significant long-term cash generators for the company.

In the current low price environment, we continue our efforts to reduce both capital and operating costs. For the second quarter, E&P capital and exploratory expenditures were $528 million, and we now project our full year 2017 capital and exploratory expenditures to be $2.15 billion or $100 million below our previous forecast. It should also be noted that our major growth projects, the Bakken, North Malay Basin, Stampede and Liza, are all expected to have cash unit operating costs that are substantially below our current portfolio average.

Now turning to our financial results. In the second quarter of 2017, we posted a pretax loss of $425 million, which reflects improved operating results compared to the pretax loss of $678 million in the second quarter of last year. On an after-tax basis, our net loss was $449 million or $1.46 per common share compared with a net loss of $392 million or $1.29 per common share in the second quarter of 2016, reflecting a lower effective tax rate in 2017 resulting from a required change in deferred tax accounting.

Second quarter production was above our guidance range, averaging 294,000 barrels of oil equivalent per day, excluding Libya, driven by strong performance across our portfolio. Net production in Libya was 6,000 barrels of oil equivalent per day in the second quarter.

For the full year 2017, we now expect net production of 305,000 to 310,000 barrels of oil equivalent per day, excluding Libya, which is at the upper end of our previous guidance, even with the sale of our Permian EOR assets that have net production of approximately 8,000 barrels of oil equivalent per day. Production growth resumes beginning in the third quarter, and fourth quarter production is expected to average 7% to 10% higher than last year's fourth quarter, pro forma for the sale of our Permian EOR assets. In addition, we expect next year to show strong growth, driven by higher activity levels in the Bakken, a full year of production from the North Malay Basin, the start-up of the Stampede Field and a full year of drilling at Valhall.

In summary, we are well positioned to deliver value-driven growth to our shareholders with our strong short-cycle position in the Bakken; our 2 offshore developments in North Malay Basin and Stampede expected to deliver a combined 35,000 barrels of oil equivalent per day; and our world-class development in Guyana, which also offers significant further exploration potential. We continue to prioritize a strong cash position and balance sheet to fund this growth, which we believe will create compelling 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 of our operational performance in 2017 as we continue to execute our E&P strategy.

Starting with production. In the second quarter, we averaged 295,000 net barrels of oil equivalent per day, excluding Libya. This was 14,000 barrels of oil equivalent per day, above the midpoint of our guidance range of 275,000 to 285,000 barrels of oil equivalent per day, reflecting strong performance across our portfolio, particularly in the Bakken.

The third quarter will be a major inflection point for us in terms of production growth. We forecast net production to average between 295,000 and 305,000 net barrels of oil equivalent per day, excluding Libya. The start-up of production from the North Malay Basin full-field development is expected to more than offset the impact of the sale of our Permian EOR assets as well as a now-completed, unplanned 10-day shutdown in July at the JDA in the Gulf of Thailand to replace a flare tip. Our positive production momentum will continue in the fourth quarter, with a full quarter of production from North Malay Basin, a continuing ramp-up in the Bakken and as we bring online new wells at the Valhall Field in Norway and our Penn State Field in the Gulf of Mexico.

As John noted, given our strong operating performance year-to-date and even with the sale of our Permian EOR asset, which is currently producing about 8,000 barrels of oil equivalent per day, we now forecast full year 2017 production to average between 305,000 and 310,000 barrels of oil equivalent per day, which is the upper end of our previous guidance range.

Turning now to onshore operations. Net production from the Bakken averaged 108,000 barrels of oil equivalent per day for the quarter, significantly beating our guidance of approximately 100,000 barrels of oil equivalent per day as the productivity of our new wells continues to perform higher than forecast. As noted in our last call, we added a third operated rig in the Bakken in March and a fourth in April. As a result of our strategy to preserve capability during the downturn, we were able to onboard these 2 rigs safely and with a high degree of efficiency.

During the second quarter, we drilled 23 wells and brought 13 new wells online compared to the year ago quarter when we drilled 20 wells and brought 26 wells online. We also completed 14 wells in the quarter. We continue to test higher stage counts and proppant loading in line with our focus on maximizing the value of our DSUs. We currently have 6 60-stage wells online and 11 wells completed with proppant loading of up to 140,000 pounds per stage. While still early days, we continue to be encouraged by the initial results from our new completions.

Drilling and completion costs for our 60-stage, 70,000 pound per stage wells are averaging between $4.5 million and $5 million, which is approximately $0.5 million below our initial guidance range. This result reflects our distinctive lean manufacturing approach, which continues to drive improvement in our operations. Drilling and completion costs for the higher-proppant wells are in line with our previous guidance of $5.5 million to $6 million.

To mitigate the risk of rising sand prices, in the second quarter, we prepurchased our sand requirements for the balance of 2017, which is expected to save us between 15% and 20% versus current spot prices. Based on encouraging production performance from our trials and the positive outputs that our predictive models are showing, we have decided to move to 60-stage completions as our new standard while continuing to evaluate the impact of higher proppant loadings up to 140,000 pounds per stage. Earlier results and predictive model outputs suggest a potential 10% to 15% uplift in EUR as a result of the higher stage counts and proppant loading. In addition, we are able to raise full year 2017 average IP 90 guidance to between 800 and 850 barrels of oil per day, an increase of 100 barrels of oil per day compared to our earlier guidance.

The material increases in performance that have been achieved this year now allow us to hold Bakken production flat with 2.5 rigs versus 3.25 rigs required a year ago. Given the strong performance of our Bakken wells in the first half of the year, we forecast net Bakken production for the third quarter to average between 105,000 and 110,000 barrels of oil equivalent per day and the fourth quarter to average between 110,000 and 115,000 barrels of oil equivalent per day. This results in an increase to our full year guidance for the Bakken of 5,000 barrels of oil equivalent per day to approximately 105,000 barrels of oil equivalent.

Now moving to the offshore. In the deepwater Gulf of Mexico, net production averaged 51,000 barrels of oil equivalent per day over the second quarter as planned shutdowns were successfully completed at non-operated host facilities for the Conger and Llano Fields. No significant shutdowns are planned for the third quarter, and production is forecast to average between 60,000 and 65,000 barrels of oil equivalent per day for the Gulf of Mexico. We also successfully drilled a new production well in the Penn State Field. The well is currently being completed and is expected to be online in the fourth quarter.

In Norway at the Aker BP-operated Valhall Field, in which Hess has a 64% interest, net production averaged 24,000 barrels of oil equivalent per day over the quarter. We drilled and are currently completing the first well of a 7-well campaign and have spud the second well. The first well was drilled 38 days ahead of schedule and is now expected to come online late in the third quarter. A 10-day shutdown is planned for the third quarter, over which net production is expected to average approximately 23,000 barrels of oil equivalent per day before increasing to approximately 29,000 barrels of oil equivalent per day in the fourth quarter.

Moving to offshore developments. First gas was introduced to the platform on July 10 from the full-field development of the North Malay Basin in the Gulf of Thailand, in which holds -- Hess holds a 50% interest and is operator, with PETRONAS as our partner. The North Malay Basin project delivery was achieved, with first gas only 3 years after project sanction. We are still in the process of commissioning but expect net production to build to approximately 165 million cubic feet per day net during the third quarter and the asset to become a significant long-term cash generator for the company.

At the Stampede development in the deepwater Gulf of Mexico, in which Hess holds a 25% working interest and is operator, the tension leg platform was installed, and hookup and commissioning are progressing to schedule. One well has been drilled and completed, and completion operations are underway on the second and third wells. First oil is planned for first half of 2018.

Now moving to the offshore Guyana. In June, we sanctioned the first phase of the multiphase development of the Liza Field, in which Stabroek Block operated by ExxonMobil and in which Hess holds a 30% interest. This is an asset of exceptional scale, with a high-quality, multi-DRC permeability reservoir and attractive financial returns at oil prices down to $35 Brent. Phase 1 will utilize a leased floating production storage and offloading vessel that will have the capacity to process up to 120,000 barrels of oil per day. First oil is expected by 2020, only 3 years after sanction.

With regard to the continuing exploration appraisal of the Stabroek Block. As John noted, in mid-June, we announced positive results for the Liza-4 well, where we encountered 197 feet of high-quality oil-bearing sandstone reservoirs. Yesterday, ExxonMobil announced the successful results of the Payara-2 well, which encountered 59 feet of high-quality oil-bearing sandstone reservoir. This positive result increases the gross discovered recoverable resource at Payara to approximately 500 million barrels of oil equivalent, confirming the partnership's second giant oilfield discovery in Guyana. The well results increased the currently discovered gross recoverable resource on the Stabroek Block to between 2.25 billion and 2.75 billion barrels of oil equivalent.

We plan to continue to progress exploration of the wider Stabroek Block during the remainder of 2017 and 2018, where we see numerous remaining prospects across multiple play types, representing multibillion-barrel unrisked upside potential on the 6.6 million-acre block. Current thinking is that after completing the evaluation of Payara-2, the rig will move to the [Turbot] prospect and then to the Ranger prospect.

Earlier this month, we also announced early entry to Block 59 in Suriname together with our co-venture partners, ExxonMobil and Statoil, and in which Hess holds a 1/3 interest. This 2.8 million-acre block shares a maritime border with Guyana and extensions of the play fairways that we see in Stabroek. Block 59 is also contiguous to the 1.3 million-acre Block 42 in Suriname, in which Hess holds a 1/3 interest with our co-venture partner, Chevron and Kosmos.

In closing, we have once again demonstrated excellent execution and delivery across our portfolio. Our production momentum continues with ever-stronger results from the Bakken, the commissioning of the North Malay Basin full-field development and planned first oil from Stampede in the first half of 2018. Together with our partners in Guyana, we have sanctioned the first phase of development of the world-class Liza Field, and the potential of the Stabroek Block continues to get bigger and better.

I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the second quarter of 2017 to the first quarter of 2017. In the second quarter of 2017, we reported a net loss of $449 million compared with a net loss of $324 million in the previous quarter.

Turning to exploration and production. E&P incurred a net loss of $354 million in the second quarter of 2017 compared to a net loss of $233 million in the first quarter of 2017. The changes in the after-tax components of E&P results between the second quarter and first quarter of 2017 were as follows. Lower realized selling prices reduced results by $51 million. Changes in sales mix, driven by Gulf of Mexico maintenance, reduced results by $26 million. Higher DD&A expense reduced results by $16 million. Unrealized losses due to crude oil hedge ineffectiveness reduced results by $16 million. All other items reduced results by $12 million, for an overall decrease in second quarter results of $121 million.

The E&P effective income tax rate was a benefit of 8% for the second quarter of 2017 compared with a benefit of 13% in the first quarter, excluding Libyan operations.

For the second quarter, our E&P sales volumes were underlifted compared with production by approximately 290,000 barrels, which did not have a material impact on our results.

Turning to Midstream. In the second quarter of 2017, the Midstream segment had net income of $16 million, which was down from net income of $18 million in the first quarter of 2017 due to a nonrecurring charge of $3 million related to our Permian midstream business. EBITDA for the Midstream before the noncontrolling interest amounted to $96 million in the second quarter of 2017 compared to $94 million in the first quarter of 2017.

Turning to corporate. After-tax corporate and interest expenses were $111 million in the second quarter of 2017 compared to $109 million in the first quarter of 2017.

Turning to second quarter cash flow. Net cash provided by operating activities before changes in working capital was $332 million. The net decrease in cash resulting from changes in working capital amounted to $167 million. Additions to property, plant and equipment were $480 million. Net proceeds received by Hess Corporation from Hess Midstream Partners IPO were $175 million. Proceeds from asset sales were $79 million. Net repayments of debt were $52 million. Common and preferred stock dividends paid were $90 million. All other items were a net increase in cash of $9 million, resulting in a net decrease in cash and cash equivalents in the second quarter of $194 million.

Changes in working capital during the second quarter included nonrecurring payments totaling approximately $130 million related to line fill for the Dakota Access Pipeline, termination payments for an offshore drilling rig, premiums on crude oil hedge contracts and prepayments for frac sand in North Dakota.

Turning to our financial position. Excluding Midstream, we had cash and cash equivalents of 2 billion -- $2.45 billion; total liquidity of $6.8 billion, including available committed credit facilities; and debt of $6,035,000,000 at June 30, 2017. In August, we expect to receive net proceeds of approximately $600 million from the sale of our enhanced oil recovery assets in the Permian Basin.

Now to turn to guidance. First, for E&P. Our updated 2017 guidance includes the anticipated impact of the Permian sale, which assumes a completion date of August 1. We project cash costs for E&P operations in the third quarter to be in the range of $14.50 to $15.50 per barrel and $13 to $14 per barrel in the fourth quarter, reflecting the impact of higher fourth quarter production from North Malay Basin and Bakken. The lower cash costs projected for the fourth quarter of 2017 will continue in 2018, with Stampede commencing production and Bakken volumes increasing. Full year 2017 cash cost guidance is now $14 to $15 per barrel, which is down from previous guidance of $15 to $16 per barrel due to ongoing cost reduction efforts and strong production performance.

DD&A per barrel is forecast to be in the range of $25 to $26 per barrel in the third quarter of 2017 and $24.50 to $25.50 per barrel for the full year of 2017, which is up from previous guidance of $24 to $25 per barrel. The increase in the full year guidance is due to better performance by Tubular Bells and the Bakken, both of which have higher DD&A rates than the portfolio average. As a result, total E&P unit operating costs are projected to be in the range of $39.50 to $41.50 per barrel in the third 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 $65 million to $75 million in the third quarter, with full year guidance remaining unchanged at $250 million to $270 million. The midstream tariff is projected to be in the range of $130 million to $140 million for the third quarter and $520 million to $535 million for the full year, which is updated from previous guidance of $520 million to $550 million.

The E&P effective tax rate, excluding Libya, is expected to be a benefit in the range of 10% to 14% for the third quarter. For the full year, we now expect a benefit in the range of 11% to 15%, which is down from previous guidance of 12% to 16% due to a change in mix of operating results.

Now 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 third quarter and $65 million to $75 million for the full year, which is updated from previous guidance of $65 million to $85 million due to the sale of our enhanced oil recovery assets in the Permian Basin.

Turning to corporate. We expect corporate expenses to be in the range of $30 million to $35 million for the third quarter and full year guidance of $135 million to $145 million, down from previous guidance of $140 million to $150 million. We anticipate interest expenses to be in the range of $70 million to $75 million for the third quarter and $295 million to $305 million for the full year, which is unchanged from previous guidance.

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

(Operator Instructions) Our first question is from Brian Singer of Goldman Sachs.

Start out in the Bakken, as you think about the decision to take that rig count or not to take that rig count up to 6 to 4, can you talk to some of the points of guidance you expect to make that decision, oil price, et cetera? And it seemed like in the Bakken, one of the reasons, maybe beyond the productivity for the very strong production, came from a higher mix of gas and NGLs. And can you talk more to how much more upside there could be on the gas and NGLs from flaring less?

Let me take your first question, Brian. So what's going to drive the decision to increase the rig count, as John mentioned in his opening remarks, we're currently operating 4 rigs that, with the 60-stage fracs and the increased proppant levels, 4 rigs should deliver a production growth of approximately 10% a year over the next several years, which is nearly the same production growth with 4 rigs that would have taken with 6 rigs a year ago. So because of those factors, the decision is really going to be based upon the crude oil outlook at the end of the year, and also, will we continue to see higher and higher performance from those enhanced completions? So those are going to be the 2 things that we're going to be looking at. In regards to your NGL and gas, as you know, we just brought on the Hawkeye facility in the first quarter. And so we continue to gather more and more third-party volumes as we go through as well as our own volumes south of the river. So...

Yes. The oil and gas mix at the wellhead is the same. This is just a question of us capturing more gas due to south of the river having the infrastructure there, reducing our flaring footprint. So it has nothing to do with well performance.

Great. And the follow-up, and I may have misheard it, but I think that when you talked about the DD&A per barrel forecast going up attributed to stronger well performance in Tubular Bells and the Bakken, if the well performance is stronger, can you just talk to why that's increasing the DD&A rate versus that lowering F&D costs/DD&A?

Sure. So from our forecast standpoint on Tubular Bells, Tubular Bells actually produced 19,000 barrels a day on average in the second quarter. And so when you calculate the DD&A, it's still based on the same reserves that we had at the beginning of the year. And now with production, we may get an update in reserves as we move through the year. But as of right now with the quarter, you're using the same calculation, so all we're getting is more barrels with the same DD&A rate that we had previously. So the DD&A rate for Tubular Bells is above our portfolio average rate. So the more barrels it produces, it just increases our overall DD&A. And right now, with the Bakken, same thing, and we'll continue to see with the uplift in EURs, with adding more and more reserves. But right now, the Bakken DD&A rate is above our portfolio average. So as we bring on more volumes there, it does increase the DD&A, all noncash, all happy to get because both Tubular Bells and Bakken are delivering more cash flow as a result of it. But it -- just from a pure accounting requirement on the DD&A, it just gives us a higher DD&A.

Got it. And so it sounds like it's more timing than not. Obviously, the IRR goes up if you're getting that production out more quickly. But do you think that the EURs in both areas are actually on the rise? Or in places like Tubular Bells, is it that just the production is getting out more quickly?

So they both are getting higher. So I mean, you've heard what's been happening with our type curves in the Bakken. So we are producing -- our EURs are performing above our type curve forecast, which will obviously then lead to higher reserves. And Tubular Bells as well, we're doing the -- kind of the slow ramp and bringing it up to production. Tubular Bells is currently producing around 20,000 barrels a day. So we are getting, like you said, better returns, and over time, that will get into our reserve numbers.

Our next question is from Arun Jayaram of JPMorgan Chase.

Yes. Just wanted to first talk about the results of Payara-2 and what are the implications as we think about a potential Phase 2 in Guyana.

Yes. Thanks, Arun. Well, obviously, this upsizes the resources quite substantially. So we've gone the range from 2.25 million to 2.75 million barrels of oil recoverable. So we are working with the operator now on -- in planning and engineering study is underway for obviously additional phases of development. And as that comes to fruition, we'll provide additional information on those future phases. However, obviously, this increases the resources very substantially.

Yes. We're reasonably confident the operator is moving forward with a second ship. And with these recent results, there's a strong likelihood we'll have a third ship. But it's going to be phased over time, so it's going to be very manageable from a financial perspective. But the thing here, it's going to give us an increasing resource base, put us on a very sustainable growth trajectory but significantly lower our cost per barrel that will give us resilient returns in a $35 or $40 world. So I think it's really going to advantage the company in terms of improving cash-on-cash returns once production comes on in 2020.

Great. And my follow-up, John, you mentioned in your prepared remarks about the potential for Hess to look at divesting some of your mature, higher-cost assets. Could you just maybe give us a little bit more color around that in terms of what you're thinking about and perhaps timing of when we could see something like this?

Yes. No, very fair. As we see, we're in the investment mode, which, depending on oil price, may mean continuing having a financial deficit. I think it's very important to know that we will selectively use asset sales to fund that deficit, and you're talking about mature, higher-cost assets, very much as we did with our sale of EOR assets in the Permian. But the key thing here is our growth is underpinned by the 4 key assets we talked about, 70% of our growth is underpinned by the 4 key assets we talked about, 70% of our CapEx, the Bakken, the 2 developments offshore and the Gulf of Mexico, Gulf of Thailand and Guyana. Our other assets actually do play an important role in the portfolio in terms of cash generation with growth potential as oil prices improve. But we will selectively look at some of those assets in the normal course of business if it make sense to sell them to continue to optimize our portfolio very much as we did with the Permian.

Your next question is from Doug Leggate of Bank of America Merrill Lynch.

Quick follow-up to Arun's question, if I may. So all we're understanding in Payara right now is that the rig is still in location. Can you speak, Greg, to the predrill on the prognosis for the deeper well that become a tail that was going to be targeted as well? Has that been penetrated or are you still on location?

Yes, I might pick that one up, Doug, because we coordinated this with the operator, our partner ExxonMobil. The Payara, first, I think the most important thing here is the Payara-2 appraisal well was very significant. It confirmed a second giant oil discovery in Guyana and also increased the gross discoverable resources just from Payara to 500 million barrels of oil equivalent. So it's going to be very economic, it's going to be a great investment and great return. And the key opportunity we have there, as you know, was we were able to deepen the Payara-2 well by only approximately 300 meters or 1,000 feet to evaluate the deeper exploration objective, which provided a low-cost opportunity to evaluate potentially material prospects. I can say now, this is the same position from our partners as well. The well encountered high-quality sands. They were water bearing, but they had oil shows throughout. So the results were and are very encouraging from both the reservoir quality and hydrocarbon system perspective and evaluation of the well results is ongoing. And I think the other key point is there is considerable resources discovered to date, but we see additional multibillion barrels of unrisked exploration potential in the Stabroek Block ahead of us.

I appreciate the answer, John. Maybe just thinking about Guyana very quickly, because the pacing of cash flows is obviously a question that folks are asking. When you look at the development scenarios, are you still comfortable that Liza, early production phase, essentially self funds subsequent phases? And if you could clarify the tax position because I understand the PSC was ultimately published by the press earlier this year? So if you could address that, and then I've got a quick follow-up on the Bakken, please.

Sure. So from the funding, you saw in our release, right? It's approximately $950 million is the capital associated with the first phase with $110 million already in our budget this year going to $250 million then to $330 million and the remainder split between '20 and '21. So very manageable within our capital budget. And the way we think about it, though, nothing's been set yet with the operator. But if you're going to get to our second FPSO, you're probably talking a 2- to 3-year period from today where we'll really start the same type of process. So if you take a look at that same phasing, that phasing will happen again 2 years from now and then we will have the production startup of Liza Phase 1. And as typical in a PSC, you can get -- begin to get your cost recovery of your cost bank and that will help fund the second phase. Now specifically on taxes, Doug, I am limited because the terms are confidential. As you said, I know there's been some PSC leaked, but we can't talk about it with specifics except to say, I think, as both John and Greg have mentioned that when we run out and you run out like the Liza Phase 1 economics, this provides good returns down to $35 Brent. So again, with the quality of the reservoir, the lower cost environment we seeing offshore and the combination with the PSC provides that good returns down to $35 in Guyana. It really, truly is an exceptional discovery and development.

My quick follow-up is, Greg, very quickly on the guidance. So that revised type curves in the Bakken, does that include the higher proppant loading or just the move to 60 stages? And I'll leave it there.

No, I think that the -- when we said upsizing by 10% to 15%, that assumes a higher proppant loading as well. Now what I can't tell you, Doug, is are we going to settle on 120,000 pounds per stage, 140,000, 130,000? We're still in the midst of basically figuring that out. But the early results from the 11 wells that we have online with 140,000 pounds per stage is very encouraging. So that gives us confidence to say that this is a 10% -- 10% to 15% uplift in EUR, it also allowed us to increase our IP 90s by some 100 barrels a day on average for the remainder of the year. So it's a combination of both.

Our next question is from Bob Morris from Citi.

Greg, just following up on the Bakken question, you mentioned the 10% to 15% uplift in the EUR, but looking at the IP 90s in the second quarter versus the first quarter, those were up about 30%. And I know some of that is the additional gas capture, but how much of that is just contribution from those 11 wells with 140,000 pounds per stage that may be on for 90 days. I don't know how many were online for 90 days. But how do we -- how would you reconcile that much higher uplift in IP 90s you saw in Q2 versus Q1 from what wells were online?

Yes, okay, so good question. So really, the Q2 IP 90 performance was very good because we're drilling in the core of the core, which is the Keene area. And that's really the best and that we have in the core of the Bakken and those wells are actually performing even higher than what our forecast was. Now as we go into the second half of the year, we're going to move outside the Keene area with a couple rigs. They're still good wells, they're just not as good as Keene, but they're still very good wells.

Hey, Bob, the only other thing I wanted -- I just wanted to add is those IP 90s are only oil. That's -- those are barrels of oil, so it has nothing to do with gas capture.

True, good point.

Yes, so that's even better. Great. Second quick question. You confirmed that in Guyana, the next 2 prospects would be (inaudible) and Ranger. And given how fast these wells are drilling, I would expect it would have results on both of those by year-end. Would that be correct?

Well, obviously, that depends upon evaluation and kind of what you find. But yes, I mean, most likely, we would have the results in both by year-end.

Our next question is from Guy Baber of Simmons.

Just wanted to continue the discussion here on Guyana and the exploration program going forward and the multibillion barrel potential you all talked about. Can you talk a little bit more about [Turbot] and Ranger? What type of prospects those are? Where they might be located on the block? And then just at a high level, how are you thinking about that pace of program, the pace of that program through 2018? Maybe how many exploration wells you plan to target over the next 12 to 18 months or so?

Yes, Guy, thanks for the question. So let's start with [Turbot]. So Turbot is very similar to Liza, meaning it's a stratigraphic play type that is on this rim of this bowl that we talked about. It's to the southeast of where Liza is located. And then if you move to Ranger, Ranger is further out in the basin and it is a very different play type, which is a -- appears to be a carbonate build up with on lapping sediments. Very large structure, but they are very different play types. So again, Turbot is more akin to Liza kind of a play type, whereas Ranger is completely different kind of play type. As far as it goes forward on exploration, remember, we have until 2026 to explore on the block. So effectively, 9 years from where we are today. The pace for next year, you can assume a one rig kind of a pace doing exploration. So that's about $150 million a year, so in net to Hess. And within that exploration campaign next year, there may be some more appraisals on Liza because we see more upside on Liza as well.

Very helpful. And then you all mentioned using or potentially looking at the portfolio and asset sales in part of the funding mechanism for shortfalls. Can you also talk about what the potential might be for drop-downs into the MLP type of cash that, that could afford the parent? Just trying to understand at a high level the runway there, kind of what the ultimate opportunity for drops might be? How you might think about that just from a high level in terms of the pace as well?

Sure, so I'll address that. And we do view this as a win-win for Hess and for our Midstream business as well. So what we would be thinking of drops, nothing like imminent that will go from the JV we have down to the MLP because this is a public entity because of the organic growth that both John and Greg have laid out that we have with our 4-rig program. What we are working with on our JV partner is we have within Hess still plenty of 100%-owned type midstream assets that we could put in the top-tier JV such as our North Dakota water handling business, which we spoke about. So that is something that can be dropped into the JV. And then later, so it bumps up the EBITDA runway at the top-level, and that asset then subsequently can be dropped into the public vehicle as the EBITDA growth continues in the MLP. There are other assets that we have in the North Dakota, other 100% owned assets that besides the water handling that we'll be looking to put in. And then we'd look across our portfolio even including assets in the Gulf of Mexico such as our Stampede PLP. So there's other types of assets that we'll be looking at and it will be part of kind of us as I said, a win-win part of our funding in this lower price environment for Hess, and it's giving more EBITDA runway to the midstream business.

Yes, I think, the key takeaways here is continued tight capital and expense control, selective asset sales of mature higher cost per barrel assets, using the MLP as a future funding mechanism, all together with Guyana and our growth opportunities that we're investing in put us on a trajectory to be cash generative in a $50 world once Guyana comes on. And I think that's the key takeaway and that's the objective for our company.

And the last thing I'd add, Guy, to your question on the play types, these play types are also what we see extending into the Suriname blocks, which is why we have gotten interested in 2 of those as well.

Our next question is from Roger Read of Wells Fargo.

Good to be back on the call after, I think, 2 years or something like that. Anyway, just to get to Guyana. The $35 breakeven, if I remember correctly, $40 was the number. Can you give us an idea of is it just the greater reserves? Or is there something else you'd detected in the appraisal wells that's helped lower that breakeven number?

No, I think there's a number of factors why the breakeven is what it is. So let's start with the reservoir. A very prolific reservoir, porosity, permeability, which means that your producers in Phase 1 are going to recover about 56 million barrels per well. Secondly, the wells are very shallow. They are only about 12,000 to 13,000 feet below the mud line, so -- and don't have any of the typical drilling things that you'd find in the Gulf of Mexico that require multiple casing streams. So the well cost here are 1/3, call it, of the Gulf of Mexico. I think the third thing is that we're doing this at the low point in the cycle. So FPSO, surf, drilling, all those things are occurring at the low point in the cost cycle. And then finally, although we can't be specific, it has a good PSC that really helps you at these lower prices. So all 4 of those things contribute to the very low breakeven.

Okay, great. That's helpful. And then to the Bakken, just in general, the idea of your in and out spin position obviously for the next couple of years until Guyana does come online. As you think about, I would imagine better well performance and maybe stable well cost, any desire to kind of step on the accelerator or to pull your foot off the gas kind of given, let's say, a sub-50 oil environment just as a starting point for that?

I think as John said, I mean, a couple of things that will govern that decision on certainly increasing the rig count will be oil price and the performance of these enhanced completions. I think in any case, we're running the Bakken for value and for cash and not growth for growth's sake, right? So I think that's a key tenet in how we're actually running the Bakken. Regarding decreasing the rig rate, I mean, that is a potential opportunity if oil prices get low, even lower. That's a pin that we could pull if we have to. That's currently not our plan, but obviously, we could if we had to.

Rig count we have, we're very comfortable being at a 4-rig rate in the $40 to $50 world. I think that's the key point.

Okay, I appreciate that. And as a quick follow-up to that, if you did have to pull back at all, any contractual limitations on that? Anything you're kind of locked in to? You mentioned buying the sand in advance, but I was just curious if anything else was kind of nailed down or committed?

Yes so we've got our rigs committed for 3 years and pumping for 2. However, all of those contracts have flexibility in them, both in the up and the down. So no major issue if we decided to reduce rate. As John said, that's not our plan. We're very comfortable with 4 rigs in the Bakken at this $40 to $50 range. I think, another important point on that, we have over 800 wells that generate an after-tax return of 15% or higher at $40 WTI flat. So we've got a very healthy inventory of outstanding return wells.

Our next question is from Paul Cheng of Barclays.

Greg, earlier that you say that Bakken, you're going to one based on cash and value. At a forward program, can you give us a rough idea that what oil price you need in order for you to be cash flow breakeven from Bakken?

At current prices, Paul, we're generating significant precash flow from the Bakken. So it would, as Greg said, we've got 800 wells that give 15% type return at $40. So look, I know you and I have talked about this in the past on the cash cost level for the Bakken. It is below our portfolio average, so prices would have to go significantly lower to cause us not to be breakeven, not to have free cash flow.

John, maybe I misread what you say. It sounds like you are saying that the Phase 2 for Guyana is going to be FID in 2019. Is that what you say? Because you're saying that the phasing of the next phase of development will be 2 years out? Is that how I should interpret?

So what we were talking about is how the phase in the capital and went on the second phase. So this, you should really ask the operator on the timing of that phasing. But now, with the results of Liza-4 and it being so good, and now Payara-2 again getting up to 500 million barrels, we feel pretty confident that there is going to be a second FPSO. So now it's timing with the operator is we sanction Liza-1 here, the first one in 2017, so somewhere, I was just estimating in a 2- to 3-year period that you'd be sanctioning the second one.

Right. I guess, my question on there is more like that I thought that we go for the early production in Phase 1 partners because you're using the (inaudible) I suppose, and you're going to incorporate that into the Phase 2 and Phase 3 if there's Phase 3. And so from that standpoint, should we look at it such that you're not going to sanction until the Phase 1 start up? Or that you may actually sanction it, say, a year before? So I'm trying to understand, not trying to pin you down on the exact time, about the thinking that how the Phase 1 development is going to be used?

Yes, so I think, Paul, there will be dynamic data that we're gathering as part of Phase I. But you should think about that as a parallel path with doing FEED on Phase II. So as you're learning, as you're going, you'll incorporate those learnings because it's really going to come down to the dynamic data that's going to give you learnings on the well behavior. So that won't really make a difference until later in the project, the Phase 2 project. So parallel path, dynamic learning as you go and incorporating those as you are building and drilling Phase 2.

And John, when you cut the CapEx by $100 million this year, is that reduction the nature is because some work is being postponed or simply just on the efficiency gains? And if that's the case, is it all from Bakken or from where?

So it really isn't an activity-based production. It really is efficiency and cost reduction efforts. I mean, you've seen what's been happening on the cash cost side. So day and day out, we're focusing on reducing cost on the OpEx in capital. And Bakken actually isn't the biggest driver of our CapEx budget reduction because we actually are moving, as Greg said, to the 60 stages and the higher proppant. What we've been able to do with efficiency there, though, is not increase the budget in Bakken even with moving to that. So then, it's more across the portfolio. You heard North Malay Basin did start up a little bit early so we had some reductions from North Malay Basin. I think you've been hearing where Stampede is, that it's out in the Gulf, so we've actually got some reductions there as well. And then the remaining piece is just across the portfolio.

My final question and just one comment. The final question is that if after the Stampede in North Malay ramp-up, to keep your production flat and the mix between oil and gas, that any rough idea on what is the ending CapEx requirement today based on that? And the final one is just a request on the midstream, to see whether you can continue to put why the more of the segment detail break down in your press release.

Sure. Let me answer your second one first. The only reason we don't have the midstream information in this press release is because, as John mentioned in his opening remarks, Hess Midstream Partners, now it's a public company is having its first earnings call tomorrow. So after the Midstream earnings call tomorrow, we will post in our supplement all the Midstream information that we had previously provided. So we just didn't want to front run their earnings call. As far as capital to maintain kind of our oil, gas mix, our production type flat, the typical way I look at it is take your number of barrels that you are producing in a year, this can be for any company, Paul, and then take your F&D rate. If it's 15, if it's 20. So with us, if you're using anywhere in a range of $15 F&D to $20 F&D, you're in that $1.7 billion to low $2 billion to be able to maintain production at a flat rate. So it is there. With Guyana, obviously, we've got some low F&D type projects coming into the portfolio as well as Bakken. But over the long run, that's, to me, a typical way to look at how you can maintain your production flat.

Our next question is from Ryan Todd of Deutsche Bank.

Great. Maybe just as we look into 2018, maybe a follow-up on CapEx. I mean, as we think of the moving pieces on capital, can you remind us of, maybe as we think the next maybe even '18 and '19, how much spend will be rolling off versus incremental spend could be ramping? And where -- if we were to hold that 4-rig program, how low could the capital budget trend over the next couple of years?

Sure. Let's -- so assuming the 4-rig program, and let me just at least do '18 versus '17. So we have 4 rigs in '18. On an average this year, we're going to be running 3.5 rigs in the Bakken. The other thing will be for '18, we'll be using right from the start the higher stage counts and the higher proppant loading, whatever that level is. So Bakken capital will go up in 2018 for both those reasons. But not a tremendous amount, but there will be an increase there. The other, let's just go with what else will increase in the portfolio. As you know, the Phase 1 of Liza was sanction. We have $110 million in the budget this year. It's $250 million in 2018, so that will be where the other increase is. And then offsetting those is both North Malay Basin and Stampede. So we have about $700 million of capital this year. Look, we will be providing guidance as normal in our January call, but you could look at somewhere around $400 million between the 2 on North Malay Basin and Stampede. So that will be a significant offset. We had some drilling going on in the Gulf of Mexico, which looks like will be reduced in 2018 as well. So hopefully, that can give you just general levels of where CapEx are and we'll update in 2018.

Sorry, on North Malay and Stampede, is that -- it could be down $400 million? Or it could be down from $700 million to $400 million?

Sorry. Yes, it will be down from $700 million to $400 million. And then the only other thing I just remembered is with Valhall, we did start the platform rig a little bit later in '17, so we will have -- we'll be running that platform rig for the full year in 2017. So it could be a slight increase in Valhall's capital.

Okay. That's very helpful. And then maybe one follow-up on the Bakken. It's a great update there on well performance. Can you talk about how we should interpret those across the broader extent of your acreage and maybe across like the 2,800 wells of inventory that you talked about, are those the type -- can you do the 60-stage fracs? Is that going to become the base case across the broader acreage position? And the 800, 850 barrels a day, the IP 90 rates, is that across the smaller subset in the core? Or is that broadly applicable, you think, across a larger portion of the 2,800 wells that you have in inventory?

Yes, Ryan. So the 60-stage will have broad applicability. So that has become our standard design now in the core of the Bakken. Recall, we've got about 1,500 wells that generate 15% or higher after-tax return at $50 per barrel. Now that number was based on our old design, 50-stage, 70,000 pounds per stage. So as we update our models, we expect that, that number will get even higher of the number of wells at breakeven at 50. So breakevens are going down, EURs are going up, IP 90s are going up, all of which bodes pretty well. So the one piece of data that we're not -- we can't be exact on yet is what is the proppant loading going to be? 140,000 pounds look good, we're trying to find the edge of interference. We might back off a little bit from that and hopefully, by the end of the year and going into 2018, we can be more definitive on exactly what that proppant loading is going to be. But 60-stage is now the standard.

Ryan, could I -- just to make sure I got the message out to you on CapEx. So with all those in and outs that I talked about here, you should not expect our CapEx, really, to be going up next year because of the reductions in North Malay Basin and Stampede and as well as the lower CapEx in the Gulf of Mexico. We'll be staying in the low end of that $2 billion range. So just to make sure I got that clear with you.

Our next question is from Paul Sankey of Wolfe Research.

You referenced the tremendous number of moving parts, several of them are very positive. Just -- and you talked about, for example, $35 oil as a decent return for Guyana. But at the same time, you've referenced the current oil prices being a current low price environment, which isn't suggested by the strip. Can you update us on the highest level on where you're aiming the company for in terms of the oil price that you assume? And what you're going to be just breakeven in terms of your CapEx, your growth? What type of growth you would want, at what type of price, of course, your earnings?

Paul, we're assuming $50 dollars as the oil price that we're going to have for some time. And while we're in the investment mode now because of Guyana and we earn very good returns in the future from that and also the Bakken as well with the 4-rig count, we're putting the company to be in a position that when Guyana comes on in a $50 world, we will be cash generative.

And could you just continue that into the Bakken, John? Because I think in the past, you've spoken about 60. It seems that's changing. Can you just update me on where that's going to be?

I mean from the Bakken again, to make sure I get this out. Right now at these prices or lower, the Bakken generates free cash flow. And as Greg mentioned, we got 800 wells even at $40 WTI to generate 15% return. So as John said, we do have deficits right now. Our target over that medium-term once Liza comes on stream is to be net cash flow positive, $50. That's post dividend as well. And we believe we can do that while providing attractive and competitive rates of production growth and returns. So currently, where we are right now, our cash flow from operations, say, in 2017, covers all our producing assets capital and our dividend at these current prices. As we move into '18, though, our North Malay Basin and Stampede projects will become cash generators. So again, it's going to help lower that deficit. And then what we'll do until Guyana comes on stream is we'll continue to use our strong cash position. Remember, we have the Permian asset sale coming in the third quarter to supplement our cash flow to fund those growth projects, which is Bakken. We're going to keep with the Bakken in 4 rigs, especially at the current prices as you've heard because it does generate good returns, and then Guyana. And because of the value that both Bakken in Guyana generate for us and we're past the development spend on North Malay Basin and Stampede, we can drive to have an increasing cash flow, free cash flow position post Guyana coming on in the $50 world.

That's exactly what I wanted to hear. And could you just continue that into earnings please, John? You've mentioned and explained a slightly confusing DD&A that you mentioned earlier in the call. But when can we expect to see the earnings positive?

And so earnings is where it's going to be the noncash DD&A, obviously, we have that high rate that we go on right now. Bakken and Guyana will continue to drive down that rate as Bakken reserves get added and then as well as additional reserves we get booked with Guyana and that production comes on stream. The exact point, Paul, I don't know what the breakeven on net income will follow kind of the cash flow, free cash flow number. So again, it will be post Guyana.

Great. And just as a follow-up, it seems that you're not being rewarded for a mixed business model that the market wants focus. When you talked about the potential for disposals, is there a potential for a major further restructuring so that you get rewarded for the quality of some of these assets without sort of mixing them and being diluted by the market valuation of mixed business models, which seems to be structurally lower for less-focused companies?

Yes, with all due respect, Paul, when you model us versus, I would say, other companies that have balanced portfolios, I actually think we're holding our own. So I guess, beauty is in the eye of the beholder, but from the numbers we run, we're actually starting to get recognition that what we have in Guyana is truly game changing. In our investor pack, we show that the returns it will generate, the EURs per well, the cost per barrel like $7 a barrel of development costs is quite distinguishing. And so when you compare our business model versus the pure plays, whether it's offshore or shale, we actually, I'd say, are probably holding our own in the middle of the pack. Now we want to be at the top of the pack. And I think as we execute our strategy, we will. So I think that's the takeaway that I would respond to you with.

Our next question is from Jeffrey Campbell of Tuohy Brothers.

Congratulations on the continuing uplift and the resource offshore Guyana. I just want to ask 2 quick questions back on the theme of the mature asset sales, the first one being just being asset operator such as in South Arne versus being a non-op interest holders such as a Valhall, will that have any material influence on your thinking in the future?

I wouldn't want to speculate on any asset sales. Being an operator offshore is fundamental to our strategic positioning going forward. Being an operator in the unconventional is fundamental as well. It also helps us when we are a partner with someone else's who is an operator, so we're going to say both as an operator, both onshore and offshore. And whatever selective asset sales we have in the future, we'll be focused on maximizing value, bringing value forward and lowering us on the cost per barrel curve. And there will be some selective opportunities that we look at as we go forward to meet some of our funding gap to fund our growth opportunities. And remember, John Rielly pointed out that we'll also be looking at the MLP as well for our joint venture above the MLP.

Right, that was very interesting color, I thought. Bearing in mind the desire to lower the corporate BOE cost, are there portions of the Bakken that could actually be a potential sale at some time if you needed it? And one reason I'm asking this is because I remember not too long ago, there was a discussion around maybe experimenting with plug and perf in submitted liners and that sort of thing and the less than core acreage to see if perhaps results can be improved. So I'm just kind of wondering what you're thinking about the Bakken outside of your obviously identified core.

So just as an example. Earlier this year, we did do a sale, it was approximately $100 million for what we were considering noncore acreage that we wouldn't get to because of the quality of our DSUs until sometime in the future. So again, it's an example, as John said, we're going to look where the value is. If it was worth more to someone else because they were going to drill it earlier than we would and we did do that sale. So what we do is try to work together with our midstream business to get the overall best integrated value that we can for both Hess and the Midstream on our acreage. And so, could further sales of noncore acreage happen in the Bakken? Yes, yes, that could happen.

Our next question is from John Herrlin of Societe Generale.

Just some quick ones from me. Greg, you said that the wells run you about 1/3 of Gulf of Mexico in Guyana. So what will the completed well cost be? About $40 or less?

John, it's John. The well cost in Guyana, so we're not being specific. We got to ask the operator. So what has been happening for us and the numbers that you know out there are -- let's just call it a dry hole cost. If you're just going down to the bottom TD on an exploration well, it's only net to us like $15 million, okay? So gross that up, it's like 50 million for a direct dry hole. So then you get into our exploration wells on whether we're coring or testing, there's going to be more. And then overall development wells, the cost of those wells are baked into that overall gross $3.2 billion of the development process. But we have not broken out individually the wells. I guess, that would be more for the operator to do.

Okay, that's fine. In the Phase 1, Greg also mentioned that there was 56 million barrels of recovery. So are you looking at about 10 producers?

It's actually 8 producers.

Okay, good. That's fine. And since you're on the phone, John, how much was for the working capital changes, the incremental sand recontract in the Pikesville? Can you break it down?

We weren't going to be specific. So what I would tell you on the 2 biggest were the [Dapple] line field, it was 1.2 million barrels that we had to, as part of our being an anchor shipper in Dapple , so that was the biggest. The next 1 was the rig termination payment that we had that was the rig that was working on Tubular Bells and we've completed that in this was the last payment on that. So those 2 are biggest and then the remainder is between the hedge premiums and the frac sand.

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