Jay R. Wilson - Hess Corp. John B. Hess - Hess Corp. Gregory P. Hill - Hess Corp. John P. Rielly - Hess Corp..

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Doug Leggate - Bank of America Merrill Lynch Guy Allen Baber - Simmons & Company International Ryan Todd - Deutsche Bank Securities, Inc. Paul Y. Cheng - Barclays Capital, Inc. Paul Benedict Sankey - Wolfe Research LLC Brian A. Singer - Goldman Sachs & Co.

David Martin Heikkinen - Heikkinen Energy Advisors John P. Herrlin - SG Americas Securities LLC Pavel S. Molchanov - Raymond James & Associates, Inc..

Good day, ladies and gentlemen, and welcome to the Third Quarter 2015 Hess Corporation Conference Call. My name is Mallory and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. 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, Mallory. 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.

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

Thank you, Jay. Welcome to our third quarter conference call. I will view progress in executing our strategy in the current low oil price environment and provide some highlights from the quarter. Greg Hill will discuss our operating performance and John Rielly will then review our financial results.

The three key principles that guide us are to preserve the strength of our balance sheet, preserve our capabilities, and preserve our growth options. We have moved aggressively over the course of 2015 to reduce our costs, capturing about $600 million in reductions so far, split evenly between capital expenditures and cash operating costs.

For 2016, we intend to significantly reduce our level of spending in order to preserve our balance sheet and liquidity.

While our 2016 budgeting process will not be finalized until the end of the year, we currently expect next year's E&P capital and exploratory expenditures to be in the range of $2.9 billion to $3.1 billion compared to $4.1 billion in 2015, excluding expenditures associated with a 50% interest in our Bakken Midstream joint venture.

This reduction of more than $1 billion represents approximately a 27% decrease from 2015. In the Bakken, we are currently planning to operate four rigs in 2016. We dropped one rig in the third quarter and plan to operate seven rigs for the balance of this year. We also plan to curtail investment in our offshore assets in 2016.

We intend to defer further development drilling in the deepwater Gulf of Mexico, the North Sea, and in Equatorial Guinea. In addition, we will complete a major booster compression project at the JDA in the first half of 2016, which will reduce our spend there next year.

In terms of our financial position, we have one of the strongest balance sheets and liquidity positions within our peer group. At September 30, our net debt-to-capitalization ratio, excluding the Bakken Midstream joint venture, was 13% and we had nearly $8 billion of available liquidity including $3 billion of cash.

In 2016, we expect to fund our base business expenditures and dividends through cash flow from operations and use cash on the balance sheet to fund our growth investments, which include two development projects and exploration and appraisal activities.

While it is prudent to plan for continued low oil prices in 2016, we also believe that Hess is well positioned to benefit when oil prices recover. We are more leveraged to liquids than our peers, with industry-leading cash margins.

Also, our advantaged tax positions in the United States and Norway will accelerate cash flow growth as oil prices improve.

Our portfolio has significant growth opportunities; in the near-term, from the Bakken and Utica; in the intermediate term, from new field start-ups at North Malay Basin in 2017 and Stampede in the deepwater Gulf of Mexico in 2018; and in the longer term, recent material exploration discoveries at Liza in Guyana and Sicily in the deepwater Gulf of Mexico provide significant upside potential for our shareholders.

Both of these discoveries are planned to be appraised in early 2016. Now turning to our financial results. In the third quarter of 2015, we posted a net loss of $279 million. On an adjusted basis, the net loss was $291 million, or $1.03 per share, compared to net income of $1.24 per share in the year-ago quarter.

Compared to the third quarter of 2014, our financial results were primarily impacted by lower crude oil and natural gas selling prices, which more than offset the impact of higher crude oil and natural gas sales volumes, and lower cash costs and exploration expense. During the third quarter, we again delivered strong operating performance.

Net production averaged 380,000 barrels of oil equivalent per day, an increase of 21% from the year-ago quarter, excluding Libya. This improvement was driven by higher production from the Bakken and Utica shale plays and the Tubular Bells Field in the deepwater Gulf of Mexico.

In light of our continued strong performance, we are increasing our forecast for 2015 full-year production to a range of 370,000 barrels of oil equivalent per day to 375,000 barrels of oil equivalent per day, up from our previous guidance of 360,000 barrels of oil equivalent per day to 370,000 barrels of oil equivalent per day.

This increase represents a 16% to 18% improvement over 2014, excluding Libya. In the fourth quarter of 2015, we forecast production to average approximately 360,000 barrels of oil equivalent per day.

Based on 2016 capital and exploratory expenditures in the range of $2.9 billion to $3.1 billion, our preliminary forecast is, for 2016 production, to be in the range of 330,000 barrels of oil equivalent per day to 350,000 barrels of oil equivalent per day. Turning to the Bakken.

Production averaged 113,000 barrels of oil equivalent per day in the third quarter, above our guidance range.

For the full year 2015, we now expect production to average approximately 110,000 barrels of oil equivalent per day compared to our previous guidance of a range of 105,000 barrels of oil equivalent per day to 110,000 barrels of oil equivalent per day.

In the fourth quarter of 2015, we forecast production to average approximately 100,000 barrels of oil equivalent per day to 105,000 barrels of oil equivalent per day.

Based on our current plans for a four-rig program next year, our preliminary forecast for Bakken production is to average in the range of 95,000 barrels of oil equivalent per day to 105,000 barrels of oil equivalent per day. In summary, we delivered strong operating performance while maintaining a robust financial and liquidity position.

With further significant spending reductions underway, we are well positioned in the current low oil price environment and are taking a disciplined approach to preserve our financial strength, competitively advantaged capabilities, and long-term growth options. I will now turn the call over to Greg..

Thank you, John. I'd like to provide an operational update and review overall progress in executing our strategy. We believe strongly that it's prudent to plan for continued low oil prices next year and prioritize preserving the strength of our balance sheet.

In this light, we are planning further significant reductions in our capital and exploratory expenditures in 2016. In the Bakken, we plan to operate a four-rig program next year compared to 8.5 rigs in 2015 and 17 rigs in 2014. In the deepwater Gulf of Mexico, we plan to defer further development drilling at the Tubular Bells and Llano Fields.

In the North Sea, we will complete the current drilling program at the Hess-operated South Arne Field in Denmark in the first quarter of 2016, and will then release the rig and defer further drilling.

In Equatorial Guinea, where demobilization of the rig was completed during the third quarter of this year, we will defer drilling in 2016 to allow time for processing and interpretation of new 4D seismic. At the Valhall Field in Norway, the operator plans to leave the platform rig stacked over the majority of 2016.

And at the JDA in the Gulf of Thailand, we will complete a major booster compression project in the first half of 2016, after which capital for the rest of the year will be significantly reduced.

As John mentioned, when oil prices recover, we are competitively well positioned and have both the capabilities and the opportunities to drive future profitable growth. Now, turning to the third quarter of 2015.

We delivered strong operating performance across our portfolio, further improved our onshore drilling costs, and progressed our offshore developments and exploration activities. Starting with production.

In the third quarter, we averaged 380,000 barrels of oil equivalent per day, exceeding our previous guidance of 355,000 barrels of oil equivalent per day to 365,000 barrels of oil equivalent per day for the quarter, reflecting strong performance from our producing assets.

As a result, we have raised our full-year 2015 production guidance to between 370,000 barrels of oil equivalent per day and 375,000 barrels of oil equivalent per day, excluding Libya. On this same basis, we forecast production in the fourth quarter to average approximately 360,000 barrels of oil equivalent per day.

Our fourth quarter forecast reflects the impact of lower activity levels across our portfolio. Turning to unconventionals.

In the third quarter, production from the Bakken averaged 113,000 barrels of oil equivalent per day, compared to 119,000 barrels of oil equivalent per day in the second quarter, and 86,000 barrels of oil equivalent per day in the year-ago quarter.

High production availability and strong well performance allowed us to exceed our previous guidance of 105,000 barrels of oil equivalent per day to 110,000 barrels of oil equivalent per day for the quarter. In the third quarter, we operated an average of seven rigs in the Bakken and brought 48 wells online.

In 2015, we expect to drill 183 wells, complete 212, and bring 219 online, with an average of 8.5 rigs for the year. This compares to last year, when we drilled 261 wells, completed 230, and brought 238 wells online, with an average of 17 rigs.

For the drilling rigs alone, this represents a 40% efficiency improvement year-on-year as result of the application of our distinctive lean manufacturing capability.

In the fourth quarter, we expect Bakken production to continue to move modestly lower and average between 100,000 barrels of oil equivalent per day and 105,000 barrels of oil equivalent per day, reflecting fewer new wells being brought online.

For the full year 2015, we expect Bakken production to average approximately 110,000 barrels of oil equivalent per day, which is at the upper-end of the guidance range announced on our second quarter call. Through lean manufacturing, we continue to drive Bakken drilling and completion costs lower.

In the third quarter, our D&C costs averaged $5.3 million per well, versus $5.6 million in the second quarter, and $7.2 million in the year-ago quarter. With these low costs and by drilling some of the highest productivity wells in the play, we continue to generate some of the highest returns in the Bakken.

Despite moving to four rigs, we expect to hold production in 2016 relatively flat with fourth quarter 2015 guidance through a combination of efficiency gains, including lower spud-to-spud days, higher well and facility availability and by capturing more NGLs and natural gas at the gas plant.

Our preliminary 2016 forecast is to bring approximately 100 new wells online with production averaging between 95,000 barrels of oil equivalent per day and 105,000 barrels of oil equivalent per day.

As a reminder, substantially, all of our Bakken acreage is held by production and assuming a four-rig program at current strip prices and well costs, we retain a greater than 10-year inventory of drilling locations that can generate after-tax returns of 15% or higher. In total, we have more than 3,000 future drilling locations in the Bakken.

And, as prices recover, we will increase our rig count and activity level as appropriate. Moving to the Utica. In the third quarter, the joint venture drilled five wells, completed five, and brought 11 on production.

Net production for the third quarter averaged 28,000 barrels of oil equivalent per day compared to 11,000 barrels of oil equivalent per day in the year-ago quarter and 22,000 barrels of oil equivalent per day in the second quarter of 2015.

For the full year 2015, we expect Utica production to be at the upper-end of our guidance range of 20,000 barrels of oil equivalent per day to 25,000 barrels of oil equivalent per day. Turning to offshore. At the Tubular Bells Field in the Gulf of Mexico, net production averaged 19,000 barrels of oil equivalent per day in the third quarter.

During the quarter, we experienced a mechanical issue related to a sub-surface safety valve that is stuck in the closed position as well as wellbore skin effects at two producing wells. While these issues are not unusual in the Deepwater Gulf of Mexico, it will require sub-surface well intervention work in the coming months.

As a result, we have now lowered our full year 2015 forecast to approximately 20,000 net barrels of oil equivalent per day. However, we expect production to be higher in 2016 as a result of this remediation work.

At the Stampede development project in the Gulf of Mexico in which Hess holds a 25% working interest in as operator, fabrication work continues on both the TLP hull and topsides. Drilling is expected to commence in the first quarter of 2016 with first oil targeted for 2018.

At North Malay Basin in the Gulf of Thailand, in which Hess has a 50% working interest in as operator, third quarter net production averaged 39 million cubic feet per day through the early production system and is expected to remain at around 40 million cubic feet per day through 2016.

In the third quarter, we progressed fabrication of the central processing platform, which is part of the full field development project. The project is on schedule to be completed in 2017, and is expected to increase net production to 165 million cubic feet per day.

In Norway, at the BP-operated Valhall Field, in which Hess has a 64% interest, net production averaged 35,000 barrels of oil equivalent per day in the third quarter.

Planned maintenance activities have been successfully completed, and we continue to expect full year 2015 net production to be in the range of 30,000 barrels of oil equivalent per day to 35,000 barrels of oil equivalent per day. Moving to exploration.

On the Stabroek Block offshore Guyana, where Hess holds a 30% working interest, we believe Liza, which logged 295 feet of high-quality oil-bearing reservoir, is a significant oil discovery.

The operator, Esso Exploration and Production Guyana Limited, plans to drill an appraisal well in the first quarter of 2016, and is currently completing preparatory technical work and developing drilling plans. We're encouraged by the potential of the Stabroek Block, which is approximately the size of 1,150 Gulf of Mexico blocks.

Over 50% of a new 17,000 square kilometer 3D seismic shoot has now been completed, and we're evaluating both potential development options for Liza, as well as the additional resource potential on the block. In the Gulf of Mexico, we continue to evaluate the results of the Chevron-operated Sicily discovery, in which Hess holds a 25% working interest.

An appraisal well to further evaluate the discovery is planned to spud later this year. In closing, I'm very pleased with our team, who once again achieved strong operational performance in the current low oil price environment amid significant changes in activity. I will now turn the call over to John Rielly..

Thanks, Greg. In my remarks today, I will compare results from the third quarter of 2015 to the second quarter of 2015. Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $291 million in the third quarter of 2015, compared to $147 million in the second quarter of 2015.

On a GAAP basis, the corporation incurred a net loss of $279 million in the third quarter of 2015, compared with a net loss of $567 million in the second quarter of 2015. Turning to E&P. On an adjusted basis, E&P incurred losses of $221 million in the third quarter of 2015 compared to a loss of $96 million in the second quarter of 2015.

The changes in the after-tax components of adjusted results for E&P between the third quarter of 2015 and the second quarter of 2015 were as follows. Lower realized selling prices reduced results by $143 million. Lower sales volumes reduced results by $33 million. Lower cash operating costs improved results by $15 million.

Lower exploration expenses improved results by $9 million. Lower DD&A expense improved results by $9 million. All other items net to an improvement in results of $18 million for an overall reduction in third quarter adjusted results of $125 million.

In the third quarter, our E&P operations were over-lifted compared with production by approximately 100,000 barrels, which had no significant impact on our financial results. The E&P effective income tax rate, excluding items affecting comparability, was a benefit of 47% for the third quarter of 2015.

This effective rate was favorable to the top end of our guidance range by 2% and primarily resulted from the mix of income generated by operations during the quarter. The E&P effective tax rate in the second quarter of 2015 was a benefit of 56%. Turning to Midstream.

On July 1, we formed the Bakken Midstream joint venture with Global Infrastructure Partners by selling a 50% interest that generated after-tax proceeds of approximately $3 billion, including the corporation's share of debt proceeds issued by the joint venture at formation.

Following the completion of this sale, the corporation will fully consolidate the operating results, assets and liabilities of the Bakken Midstream segment in its consolidated financial statements with our partner's share being reflected as a non-controlling interest.

The Bakken Midstream segment had net income of $16 million in the third quarter of 2015 compared with $32 million in the second quarter of 2015, primarily reflecting the impact of the 50% non-controlling interest.

Bakken Midstream EBITDA, excluding non-controlling interest, amounted to $79 million in the third quarter of 2015 compared to $74 million in the previous quarter. Turning to Corporate and Interest.

After-tax corporate and interest expenses, excluding items affecting comparability, were $86 million in the third quarter of 2015 compared to $83 million in the second quarter of 2015. Turning to cash flow.

Net cash provided by operating activities in the third quarter including a decrease of $207 million from changes in working capital was $282 million. Additions to property, plant and equipment were $963 million. Proceeds from dispositions amounted to $2.667 billion. Borrowings were $600 million.

Distribution of loan proceeds to our joint venture partner were $300 million. Repayments of debt were $17 million. Common stock dividends paid were $71 million. Common stock acquired and retired amounted to $64 million.

All other items amounted to a decrease in cash of $52 million, resulting in a net increase in cash and cash equivalents in the third quarter of $2.082 billion. Turning to our financial position.

Excluding amounts held in our Bakken Midstream joint venture, we had approximately $3 billion of cash and cash equivalents at September 30, 2015, compared to $1 billion at June 30, 2015. Total debt, excluding Bakken Midstream, was $6 billion at September 30, 2015, and our debt-to-capitalization ratio was 22.7%.

Now let me update you on changes to our 2015 guidance.

We now project cash costs for E&P operations to be in a range of $16 per barrel of oil equivalent to $17 per barrel of oil equivalent in the fourth quarter, and $15.50 per barrel to $16 per barrel for the full year, which is down from previous full year guidance of $16.50 per barrel to $17.50 per barrel.

DD&A per barrel for the fourth quarter of 2015 is forecast to be $29 per barrel to $30 per barrel and $28.50 per barrel to $29 per barrel for the full year of 2015, versus previous guidance of $28.50 per barrel to $29.50 per barrel.

This results in updated projected total E&P unit costs of $45 per barrel to $47 per barrel in the fourth quarter and $44 per barrel to $45 per barrel for the full year of 2015.

The Bakken Midstream tariff expense is expected to be $3.80 per barrel of oil equivalent to $3.90 per barrel of oil equivalent for the fourth quarter of 2015, and $3.35 per barrel of oil equivalent to $3.45 per barrel of oil equivalent for the full year of 2015.

Exploration expenses, excluding dry hole costs and items affecting comparability, are expected to be in the range of $115 million to $125 million in the fourth quarter, and $340 million to $350 million for the full year, which is down from previous full-year guidance of $380 million to $400 million. Turning to Midstream.

For the fourth quarter of 2015, we anticipate net income attributable to Hess from the Bakken Midstream segment, which reflects our 50% ownership, will be in the range of $15 million to $20 million. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator..

Our first question comes from the line of Edward Westlake with Credit Suisse. Your line is now open. Please go ahead..

Yes. First question really around the cash cycle. I mean, I like what you're doing with the capital discipline. Obviously, you've got Stampede and North Malay that you have to complete.

But as you look to the other side of it when you get to sort of 2017, where do you sort of see cash neutrality for where cash flow covering CapEx and dividend heads out, given cost deflation and activity choices?.

Thanks, Ed. So, I mean, as we look at it, first of all, let me just discuss I guess 2016. Our budget has not been finalized yet. So as you look at 2016, and I think it's exactly as you said, we do expect to cover our base business expenditures and dividends through our cash flow from operations, and even at this low commodity price environment.

And then, we'll use the cash on the balance sheet as needed to fund our growth projects in 2016, which include North Malay Basin and Stampede and our exploration and appraisal activities, which Greg mentioned. So then, as you move on to 2017, North Malay Basin comes online.

So North Malay Basin becomes a cash flow generator and increases our production in 2017. And then, Stampede comes on in 2018, becomes a cash flow generator in 2018.

So as we look at this, and I think in going through the cycle, we're just balancing everything that we've talking about, preserving that financial strength, keeping these operating capabilities and preserving these growth options so that as we move through 2017 and 2018, we're in a good position to begin to start generating cash flow at that point in time..

And then, one of the big exciting areas obviously is Liza. You've got to do appraisal. I don't know how many prospects you've actually managed to map on the block at this stage, but maybe talk a little bit about how aggressive you're going to get after the exploration phase, and then maybe even early production on the field..

appraise Liza and then get started on other exploration prospects on the block. There's numerous lookalikes to Liza, for example. And then the third thing we're going to do is we're starting to evaluate potential Liza development options. So how would we develop this significant development called Liza.

So those are kind of the three things that are going on..

Thanks very much..

Yep..

Our next question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Your line is now open..

Thank you. Good morning, everybody..

Morning..

I've got a couple of questions on the capital budget also.

John, how much of this $3 billion midpoint guidance is what you'd characterize as non-producing capital, exploration and those large projects at this point?.

So, first off, as you know, right, just in light of this low oil price environment, we wanted to get this preliminary 2016's guidance out on our capital and exploratory program. It is difficult at this point, because we haven't completed our budget process, to be really specific on our numbers, just in general across our portfolio.

And we will do that in January. At a high level, though, we're going to be continuing to spend on North Malay Basin and Stampede, and you can think about it in the general same area as it was in 2015. But we will provide specifics on that in 2016.

And then exploration, we'll have to provide – as Greg said, there's still – we still have work to do on Guyana – we'll provide more information on that in January of 2016. But I guess, if you put it altogether, it shouldn't be that much different than the growth capital that we were spending this year..

So, just to be clear, North Malay and Stampede have got about $900 million this year. And exploration, I guess, is about $400 million to $500 million.

So is it reasonable to think about it as roughly about half your spending next year is not contributing to production?.

one, adding resources to the portfolio with North Malay Basin and Stampede, which will become cash flow generators in 2017 and 2018. And then, as Greg has mentioned, we're excited about the potential of adding future resources for Guyana, so we've got that long-term resources being added to our portfolio..

Thank you. So I guess swinging to the Bakken then. What I'm really trying to understand is what four rigs means for the Bakken. So I guess I'm not even quite sure how to ask this question.

If these four rigs stabilize the production on an exit-to-exit basis once you get to the end of 2016, and if I'm thinking about this right, when you get done with those major capital projects, leaving aside what happens in Guyana, does that non-productive capital, if you like, then swing back to what are still probably some of the highest return assets in your portfolio? In other words, do you go back to a 14-rig, 15-rig program in the Bakken towards the end of the decade as our capital frees up? Is that how we should think about it?.

Yeah, so first of all, Doug, what happens to the Bakken, as we kind of said in our opening remarks, with a four-rig program in 2016, we expect the Bakken to stay roughly flat with Q4 2015. So that would add – we've guided 95,000 barrels a day to 105,000 barrels a day for 2016.

Now, the obvious question is, well, how can we hold production flat with four rigs? And it's really three ways. Increase drilling efficiencies and higher availability on existing production because there's less SIMOPS going on. And then increased gas and NGL capture in plant.

Now, if you project out further and ask, how long can we hold production flat in a four-rig case? We could do that for several years. So we could hold Bakken at about 100,000 barrels a day for several years just with the four-rig program.

And obviously, as cash flow becomes free, as we swing off these growth projects, where we divert that capital will be a function of return obviously. But clearly, the Bakken is one of the best projects we have in our portfolio, so it'll be very high in the queue for a future call on capital..

Thanks. Last quick one, Greg, if I may. Just there's been some talk of Exxon moving to an early production system in Liza.

Can you offer any comments on scale and timing?.

Can't really, Doug. The one thing I will say is that we're in preliminary studies to evaluate what might be development options for Liza B, and there's a variety of possibilities there..

Great. Thanks a lot, everybody..

Our next question comes from the line of Guy Baber with Simmons. Your line is now open..

Good morning, everybody, and thanks for providing the initial 2016 guidance for us. We appreciate it.

First one, just I apologize if I missed this, but what commodity price framework are you assuming in the $3 billion preliminary capital guidance? Would that be something close to the strip?.

Yes. Yes. We're looking at current prices, right..

Okay. Great. And then you mentioned curtailing the offshore spend, deferring further development drilling in the Gulf of Mexico, North Sea EG.

Can you just discuss that thought process? We typically would think of infill wells as some of the higher-return opportunities for you, out of Tubular Bells, for example, where you've already invested some of the infrastructure.

So just want to understand how you're thinking about that, how you came to that decision?.

Yeah. I think, again, you have to go back to the opening remarks of both John and I, and John Rielly. Given the continued low oil prices next year, we have said we're going to prioritize preserving the strength of our balance sheet above all else. And so, what that means is, we're going to flex our investment down in those areas where we can.

And we have a lot of flexibility offshore, we have a lot of flexibility onshore, so we're actually bringing the whole portfolio down in order to keep our balance sheet strong..

Okay. Great. And then I had a follow up, just on the thought process when it comes to exploration and the strategic importance in a commodity environment like this. But obviously, you all have had and participated in some significant discoveries.

But just wanted to talk through strategically how you see exploration at this point in time? What type of flexibility you might have in the budget? And also how you think about the potential of, between seeing discoveries, such as with Exxon in Guyana and Sicily in the Gulf of Mexico, through to ultimate production? Versus the alternate possibility of attempting to perhaps monetize that resource early in the lifecycle to accelerate some cash flow and value recognition?.

Yeah. Well, I think that – just I'll take your last question first – I think the first order of business is understand what we have there, right? So particularly in Guyana, we've got a lot of work to do to understand the full potential of the block, so way too early to talk about monetization options or anything like that.

But how do we think about exploration right now? Well, first of all, we believe that conventional exploration is still the best way to add long-term value to grow the business with attractive returns, provided you can do it successfully, obviously.

And I think importantly right now, it can be executed at a much lower cost in the current price environment. So indeed, Guyana is a case in point, where we were able to access that block at a relatively low entry cost, and are now executing this work program at historically low costs, on a cost curve. So it's a good time to be doing this kind of work.

And obviously, as John and I both said in our opening remarks, we're really encouraged by the Liza discovery. It's not only a great well in itself, but it has also proven a working petroleum system on a very large block with lots of prospectivity..

Okay. Great. Thanks for the comments and again for all the disclosure..

Thank you..

Our next question comes from the line of Ryan Todd with Deutsche Bank. Your line is now open..

Great. Thanks and good morning. Maybe if I could try a couple more – and maybe a follow-up on an earlier question.

Can you talk about maybe put a few more numbers around the type of swing in cash flow that you'd see in 2017 from the start-up in North Malay in terms of how much capital rolls off versus what would the potential cash flow generation be at the current strip?.

Sure. So, I mean, this is just general guidance there. We're spending in North Malay Basin, like this year, between $500 million and $600 million. We haven't been specific, but let's just say it's carrying that type of level into 2016.

And what happens in 2017, instead of spending $500 million to $600 million and having that negative cash flow, it'll actually turn cash flow positive in there. So you're at a minimum getting a $500 million to $600 million, now you're generating free cash flow.

So you're potentially $700 million, $800 million swing in cash flow as it relates just to that North Malay Basin asset. And then, Stampede does continue your spending in 2016 and 2017 on the development. And then, we were spending approximately $300 million this year.

But as you move, it will be somewhere in the $300 million to $400 million as we go forward. You'll have that negative cash flow turning into positive cash flow in 2018. So on top of North Malay Basin, at that point in time, you're swinging $400-million-ish at a minimum to $500 million to $600 million to cash flow at that point in time..

Great. Thanks. That's helpful. And then maybe, one more in terms of portfolio construction. I mean, should we – it has been a seller's market, I think we could probably say recently out there in the market.

And when you look at your portfolio right now, I mean, how do you think about the potential for – how do you think about M&A in terms of potentially monetizing non-core assets? Should Utica be considered core or non-core at this point? And maybe on the flipside in terms of acquisitions (40:00), like, what are your current thoughts?.

Sure. We're always looking to upgrade or optimize our portfolio. Obviously, we never comment on M&A. But I think the important thing here is our first, second, and third priority is to keep the strong balance sheet we have strong during this period of low prices..

Okay. Great. Thank you..

Our next question comes from the line of Paul Cheng with Barclays. Your line is now open..

Thank you. Hey guys. Good morning..

Hey..

John, there's I think some Bloomberg News talking about you guys maybe looking at to sell Utica.

Don't know whether you can confirm it? And if you do have that possibility of thinking, what's the rationale behind?.

Yeah. Paul, obviously we're always looking to optimize our portfolio, but we do not comment on M&A..

Okay. And maybe for John Rielly then.

Do you have 2016 – I know it's early – preliminary cost guide for cash and DD&A?.

No..

...

2015, or at least directionally that we're going to see any meaningful drop further from the 2015 level, or that it's really going to be somewhat similar or modest?.

I mean, I understand to try to get as much guidance out, and that's why we put this preliminary guidance in this low price environment, so everybody can get a feel of what we're doing with capital, and also where we think production is going to. However, we're still fairly early in the budget process, even working with our partners.

So at this point, Paul, I can't give specific cost guidance and I'll do that in January on our call, as usual..

Okay. And, John, I actually just curious or then for Greg, at today's defense or I presume it's not really economic to well any oil out from Bakken.

Is that correct?.

Right now, it's more economic, Paul, with the differentials to clear book having narrowed to where they're only about $1 off of WTI to prioritize moving as much oil as you can through pipeline, and we're doing that. But we still flex some of our production to rail.

So where in the past maybe the mix was 50-50, like three months ago, rail versus pipeline, right now, pipeline is about 60% of what we move and rail is about 40%..

John, can you remind me what is the minimum commitment that you have to the JV that you have to rail through?.

So from our minimum – let's just call it our minimum volume commitments that we have with the Midstream. So first of all, we don't see any issue meeting our minimum volume commitments because there's a couple of things that allow us to meet that.

One is additional volumes coming from our build-out of, what we call, our Hawkeye project, which is south of the river. It allows us to get volumes that we couldn't get into our infrastructure from south of the river to the infrastructure north of the river and also just up in North Dakota continued flaring and trucking reductions.

And then as well we have the third-party volumes, additional third-party volumes that will come our way. So again from our minimum volume commitments from the third quarter numbers that you actually see in the press release, our minimum volume commitments for 2016 are already essentially below all those numbers that are there..

But you won't be able to tell me what's that number?.

Oh, sure. I'm sorry. So if you want the actual number, so it's actually in the S-1, but crude oil loading is 38,000 and so in the third quarter you saw it was 47,000 and the crude oil transportation going through it as 43,000 versus 45,000 that we had in the third quarter..

A final one, John and Greg, when you're looking at your Gulf of Mexico deep-water or overall your deep-water portfolio from a supply cost standpoint, are they in the middle of the pack of your overall portfolio or it's at the that high-end of your portfolio?.

So from a cost standpoint on the Gulf of Mexico it is at the (44:35)..

Overall return that – the rate that you put it, I'm trying to understand that, I mean one of your largest competitors that they take a pretty radical approach and totally get out and the argument they make is that in the deep-water portfolio is at the high-end of their portfolio in supply costs, so they believe that they will be better off without even though they actually have some decent success, so just curious that in your portfolio, does it have a similar pattern or you view it differently?.

Okay. No, we would view it differently. But let me just – because I don't know what the other competitor was exactly referring to, so let's just talk our Gulf of Mexico assets that are producing, they are – when you bring the Gulf of Mexico assets in general together, they are at the low cost end of our portfolio average, quite low actually.

And opportunities there to drill further, kind of, exploitation opportunities and bring it into that infrastructure are some of the best returns that we have in the portfolio, so then it just becomes – I don't know if they're thinking about further development, future developments, I don't know.

But again, from – as Greg said, as we look at the offshore right now and where the costs are going in the industry, we see that it's a good opportunity, like Greg had mentioned with Guyana, to be able to be investing in offshore projects right now..

Thank you..

Our next question comes from the line of Paul Sankey with Wolfe Research. Your line is now open..

Hi, everybody. Thanks for all the disclosure. Just a brief one from me, you've been very clear about your strategy in terms of cutting CapEx and maintaining a strong balance sheet. I just wondered if that leaves you any room for buybacks or any other – or whether you're going to sit at this level of financial leverage? Thanks..

Our priority here is to keep our strong balance sheet strong and that comes first before anything else. So, at the end of the day, we're cutting our CapEx and we don't think it makes sense to accelerate production in this environment and, obviously, share buybacks are taking a backseat as well..

Great.

So we'll just sort of model forward around this level of leverage through 2016, assuming whatever oil price we are?.

Obviously, it depends on your oil price..

Would you be looking to spend more in a higher oil price environment or restart buyback?.

I wouldn't want to speculate on that. We want to keep our options open..

Understood. Okay. Thanks, John..

Our next question comes from the line of Brian Singer with Goldman Sachs. Your line is now open..

Thank you. Good morning..

Good morning..

The Bakken's been a critical source of growth and outperformance versus your own expectations.

Can you just update us on down spacing in the Three Forks program as well as any new completion or drilling techniques that may or may not be having an impact here?.

Yeah, you bet. First of all, the Three Forks reservoir is great. We're really drilling in the sweet spot of the sweet spot of the Three Forks right now, so it's actually outperforming the Middle Bakken marginally. So that's very good resources there in the Three Forks.

Regarding down spacing, we've got 51 wells that are on a nine and eight (48:09) spacing pilot. We plan to do 82 wells this year. 51 wells are currently online in the nine and eight (48:17) configuration, now only 20 of these wells have been online for greater than 90 days.

So the initial results are encouraging and we expect to provide pilot results early next year after we get a few more wells with longer production history under our belt. Regarding different completion techniques, we're running 50-stage pilots. So these are 50-stage sliding sleeve wells.

We've got 18 wells out of the 36 wells that we planned this year online. Again, only 13 of those wells have been online for more than 30 days, so it's a little early. But initial production uplifts are in line with expectations and similar to the nine and eight (49:01). We plan to be in a position to provide the results early next year.

Now, on the 50-stage, and the nine and eight (49:09) frankly, the final decision is going to be an economic one. So does the 50-stage well generate a higher return given the higher cost? And if it does, then we would expect to move our standard to the 50-stage design from the current 35-stage design.

Again, it will be an economic return question, not a higher production question..

Got it. Thanks.

As a follow up to that, how long can you keep drilling in the sweet spot of the sweet spot, as you said it, of the Three Forks before you have to move to just the sweet spot or somewhere less sweet?.

Multi-years, multi-years. Not a concern right now..

Great. And lastly, you talked to maintaining and prioritizing your balance sheet strength.

Is there a – can you define that? Is it based on a certain net debt-to-EBITDA target? Are you looking to just retain flat debt levels overall? What is the flexibility you have in that balance sheet when we think about the potential for M&A without it getting too high for your own interest?.

Yeah. So, as we look at it right now, and again, in this low price environment, as you can imagine, the flexibility we have is that we do have $3 billion of cash on our balance sheet. And so that is allowing us to invest through this cycle, bring these longer-term projects on in 2017 and 2018, as well as invest in exploration such as Guyana.

So what we are looking, and I'm going to say more short-term now because we are very focused on where the commodity price environment is, is maintaining that balance sheet and not increasing our debt levels. So that's where we have the ability to be able to use that balance sheet to fund that capital program.

Longer-term, we'll see what happens as projects come on..

Great. So absolute debt, flat. Thank you..

Yep..

Thank you. Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Your line is now open..

Good morning, guys. Thanks for the time. As you look at Hess Infrastructure Partners, you had a $425 million expansion of planned to go on service in 2017.

Is that still in the plans for capital in 2016, net to your 50% interest, obviously?.

So what is – and we will give more guidance in January on that – the big component of the capital for the Midstream is going to be the completion of what I referred to as the Hawkeye project.

Again, it's infrastructure, it's pipelines, it's compression to be able to bring volumes south of the river in North Dakota to our infrastructure north of the river, such as our gas plant and our rail facility. So there will still be significant spend there on that project, but in January, we'll give more specifics on the levels..

Yeah. And that project was the Hawkeye project. So that makes sense..

Yes..

The – on the other, just details of – how much does a Guyana well cost to drill, either appraisal or exploration?.

Still don't know the answer to that, because we're just getting bids in now, the operator, not us, but the operator is still getting bids in. Many of the....

So is the Liza well was the first discovery well – what did it cost?.

I don't want to give you a number because I just can't remember off the top of my head right now..

Okay. And then just thinking through the kind of path forward, and really, I guess you're getting into that, but just fourth quarter, you talked about gas plants coming online and NGLs growing, also less downtime.

Can you just give some numbers of what's the SIMOPS downtime, like amount of volumes that you had shut in maybe in the first quarter that won't be with four rigs running, or – and also, kind of what is your incremental NGLs and gas as you bring on the additional plant capacity?.

Let me answer the operational question first, and then I'll turn it over to John for that. The way to think about this is this year, our availability has averaged about 87%, and that's a combination of SIMOPS and maintenance and things you have to do. What we're projecting next year is that will go up 2%..

Okay..

Fewer SIMOPS. So that will give you kind of a round number that you can model..

That's perfect..

And again, I can't be exactly specific for you, David, as we move into – onto 2016, but so right now, our production by product in the Bakken was about 73% oil, 18% NGLs, and 9% gas. You will see, per Greg's comments, as we get up to the full capacity of the gas plant that we will be increasing on a percentage basis our NGLs and gas.

Just can't be specific to you right now until we get further into the budget process..

That's helpful. Thanks, guys..

Yeah, I just want to come back quickly on the Guyana and just remind folks on the call, remember, these wells are quite shallow. They're only 18,000 feet and they're in 5,700 feet of water. Liza well cost us about $80 million Hess net.

So future wells, as you get down the learning curve, will be cheaper than that, obviously, once you get in development mode..

Our next question comes from the line of John Herrlin with Société Générale. Your line is now open..

Yeah, close enough. Most things have been asked. I've just got a question regarding the potential for impairments. We're seeing a lot of your peers clean house, they're wiping out goodwill, capitalized costs, whatever it may be.

What's the likelihood given the reduced CapEx that some costs you're carrying ultimately opt to impair?.

So I mean, in the third quarter, obviously, with the lower cost environment, we did not have any impairments in our portfolio. But, John, all I can tell you right now is, as it continues and as we finalize our budget, we will assess that and we will report it on our fourth quarter. But I can't give you any more guidance than that..

All right, that's fine. Thanks, John..

And our last question comes from the line of Pavel Molchanov from Raymond James. Your line is now open..

Hey, guys. Thanks for taking the question. You've given very granular guidance on Bakken decline for 2016.

What other geographies are seeing the declines that are factored into your company-wide production target?.

So I mean if you go across the portfolio, I mean, obviously, when you have less drilling activity, as Greg said, we're not drilling in EG (56:21), the Norway, there's a drilling break and things like that, you're just getting the natural decline of the portfolio.

So as you could see, as you mentioned what the Bakken numbers are, we can't be specific at this point until we finalize our budget. But you can kind of say that the reduction is kind of half due to less drilling activities and half due to natural decline to our portfolio..

Okay. Understood.

And I guess on a percentage basis, if Bakken is seeing the steepest decline across your portfolio in 2016, maybe what's the second biggest contributor to the overall decline? I mean would it be North Sea? Or would it be some of your more mature stuff?.

What it is, and it really has to do with the way the net entitlement works. As Greg had mentioned, in JDA, we're finishing up the booster compression project there. So, one, you probably noticed in our numbers, we've had some net entitlement changes this year that's dropped in the third quarter for JDA.

So, on an overall basis, the next biggest component beyond Bakken would be JDA because well there's less cost recovery barrels that we'll have in 2016 as well as with the booster compression, there'll be some downtime at JDS..

All right, very helpful. Appreciate it, guys..

You bet. And I want to give all of the callers one more clarifying comment. The $80 million Liza cost was a gross cost not a net cost. I wanted to clear that up on the call..

And we do have a follow up question from the line of Paul Cheng with Barclays. Your line is now open..

Thank you.

John, I know that you don't have a detailed budget, but curious since you know you're going to do a forward program in Bakken, do you have a number what's the CapEx on Bakken for next year?.

No, no, we don't have that yet. Again, we'll get that in January. Again, so we're just fine-tuning how much is near field infrastructure, things like that. So we'll provide that number in January..

Okay. Thank you..

Sure..

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