Jay R. Wilson - Vice President-Investor Relations John B. Hess - Chief Executive Officer & Director Gregory P. Hill - President & Chief Operating Officer John P. Rielly - Chief Financial Officer & Senior Vice President.

Doug Leggate - Bank of America Merrill Lynch Brian Singer - Goldman Sachs & Co. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) David Martin Heikkinen - Heikkinen Energy Advisors LLC Asit Sen - CLSA Americas LLC Paul Cheng - Barclays Capital, Inc. Ryan Todd - Deutsche Bank Securities, Inc.

Paul Sankey - Wolfe Research LLC Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Guy A. Baber IV - Simmons & Company John P. Herrlin - SG Americas Securities LLC Pavel S. Molchanov - Raymond James & Associates, Inc. Arun Jayaram - JPMorgan Securities LLC.

Good day ladies and gentlemen, and welcome to the Second Quarter 2016 Hess Corporation Conference Call. My name is Chanel 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 call 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, Chanel. 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'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 Officer; and John Rielly, Chief Financial Officer. I'll now turn the call over to John Hess..

Thank you, Jay. Welcome to our second quarter conference call. I will provide an update on the progress we continue to make in managing in the low oil price environment while preserving our long-term growth options. Greg Hill will then discuss our operating performance from the quarter, and John Rielly will review our financial results.

Our company is well-positioned for the current price environment and for the eventual recovery in oil prices. We have one of the strongest balance sheet and liquidity positions among our peers, a resilient portfolio, and an exceptional long-term growth outlook.

In terms of our balance sheet, we started 2016 by reducing our E&P capital and exploratory budget to $2.4 billion, 40% below our 2015 spend and cut activity across our producing portfolio, both onshore and offshore. Since then we have continued to pursue further capital reductions.

In the second quarter of 2016, we reduced E&P capital and exploratory expenditures by 52% from the second quarter of last year to $485 million. We now project our full-year 2016 capital and exploratory expenditures to be $2.1 billion, about 48% below 2015 levels and $300 million lower than our previous forecast.

Efforts are under way to make further reductions as well. We have the balance sheet and liquidity necessary to invest in our future growth. Our three growth projects will make us a much stronger company in the next few years in terms of visible production and cash flow growth as well as improving returns.

As you know, we are investing about $700 million in 2016 in two offshore developments, North Malay Basin in the Gulf of Thailand and Stampede in the deepwater Gulf of Mexico.

These two projects, which will come online in 2017 and 2018 respectively, will add a combined 35,000 barrels of oil equivalent per day, and go from being sizable cash users to significant long-term cash generators for the company.

In terms of our third major growth project, offshore Guyana, on June 30, Hess and co-venture partner and operator ExxonMobil announced positive results from the Liza-2 well in the Stabroek block.

The results confirmed a world-class oil discovery, one of the largest in the last 10 years, with estimated recoverable resource for the Liza discovery of between 800 million and 1.4 billion barrels of oil equivalent.

We believe the Stabroek block has the potential to materially contribute to our resource base and future production growth and create significant value for our shareholders. On July 17, the operators spud the Skipjack well, which is a separate but similar prospect located approximately 25 miles to the northwest of the Liza-1 well.

We expect to have the results from this well by our next conference call. Following the Skipjack well, the operator intends to drill a third well at Liza to further appraise the discovery.

In addition, predevelopment activities are under way, and we look forward to working with our partners and the government of Guyana to move this exciting discovery towards a commercialization decision. We believe Liza will offer very attractive economics and expect the call on capital next year to be manageable, given our strong cash position.

As plans progress, we will continue to keep you informed. Turning to our financial results, in the second quarter of 2016 we posted a net loss of $392 million. On an adjusted basis, the net loss was $335 million or $1.10 per common share, compared to an adjusted net loss of $147 million or $0.52 per common share in the second quarter of last year.

Compared to the second quarter of 2015, our financial results were negatively impacted by lower crude oil and natural gas selling prices and sales volumes, which more than offset the positive impacts of lower cash costs and DD&A.

Net production averaged 313,000 barrels of oil equivalent per day, compared to net production of 386,000 barrels of oil equivalent per day in the year-ago quarter, pro forma for last year's sale of our Algeria asset.

While we continue to have strong performance from the Bakken, overall company production during the quarter was primarily affected by unplanned downtime due to subsurface safety valve failures in related remediation work at the Tubular Bells field and a mechanical issue at one well in the Conger field both in the deepwater Gulf of Mexico, planned shutdowns at several offshore fields, including Tubular Bells and Valhall field in Norway, and reduced capital investment as compared with last year.

Due to the unplanned downtime at the Tubular Bells and Conger fields, which Greg will address in more detail, we are revising our overall company production forecast for 2016 to a range of 315,000 to 325,000 barrels of oil equivalent per day, excluding Libya, from our previous guidance of 330,000 to 350,000 barrels of oil equivalent per day.

Turning to the Bakken, net production in the second quarter of 2016 averaged 106,000 barrels of oil equivalent per day compared to 119,000 barrels of oil equivalent per day during the second quarter of 2015, reflecting our reduced drilling program.

Through the use of lean manufacturing techniques, our Bakken team continues to drill some of the lowest-cost and most productive wells in the play.

Notably, during the second quarter, we reduced drilling and completion costs 14% from the year-ago quarter to an average of $4.8 million per well, even as we shifted from 35-stage to 50-stage wells, which is delivering a 15% to 20% uplift in initial production rates.

For full-year 2016, we are narrowing our Bakken production forecast to a range of 100,000 to 105,000 barrels of oil equivalent per day, representing the upper end of our previous guidance of 95,000 to 105,000 barrels of oil equivalent per day.

Our focus remains on value, not volume, and we do not believe that accelerating production or drilling up our best locations in the current low price environment is in the best interest of our shareholders.

While our Bakken acreage can generate attractive returns at current low prices, we will remain disciplined and begin to increase activity there when oil prices approach $60 per barrel.

As we see that a price recovery is sustained, we will also then resume drilling activities in the Utica and offshore, where we have numerous high return investment opportunities. In summary, we have one of the strongest balance sheets and most attractive long-term growth profiles among our peers.

We remain confident in our ability to manage through the current environment and deliver strong production and cash flow growth as oil prices recover.

Our resilient portfolio provides an attractive mix of short-cycle and long-cycle growth options, including an unparalleled position in the Bakken, two significant offshore developments that will become cash generators starting in 2017 and 2018, and the recent world-class oil discovery in Guyana that has the potential to create material value for our shareholders.

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

Thanks, John, and good morning everyone. I'd like to provide an update on our progress in 2016 as we continue to execute our E&P strategy.

As John said, we are focused on maximizing value, not volume, and have reduced our drilling program to levels that allow us to manage near-term cash flow, while maintaining our operating capabilities in the current low price environment. When oil prices approach $60 per barrel, we will begin to ramp up activity, starting with the Bakken.

As the price recovery is sustained, we will then resume drilling activities in the Utica and offshore. However, given that oil prices have remained below $50 per barrel, we have further reduced our 2016 E&P capital and exploratory budget to $2.1 billion from our previous guidance of $2.4 billion, which represents a 48% reduction from 2015.

This decrease reflects our continuing focus on reducing costs across our portfolio. Now moving to production, in the second quarter, we averaged 313,000 net barrels of oil equivalent per day, which was below our guidance of 320,000 to 325,000 net barrels of oil equivalent per day for the quarter.

As discussed on our last call, we had a series of extended planned shutdowns at the Valhall field in Norway and at the Tubular Bells and Conger fields in the Gulf of Mexico during the second quarter.

In addition, we experienced a mechanical issue that affected one well at the Conger field and had further downtime at the Tubular Bells field to replace a second defective subsurface safety valve. In July, we have experienced a third subsurface safety valve failure.

We are actively pursuing legal claims against the vendor who provided the defective valve at Tubular Bells. The third valve failure at Tubular Bells and the mechanical issue with the Conger well will be remediated in the fourth quarter.

These issues, along with decreased investment levels, led us to reduce our full-year 2016 production guidance to 315,000 to 325,000 net barrels of oil equivalent per day, excluding Libya. We forecast companywide production in the third quarter to average between 310,000 and 315,000 net barrels of oil equivalent per day, excluding Libya.

Our third quarter forecast reflects planned downtime at the JDA in the Gulf of Thailand, the South Arne field in Denmark, and the mechanical issues at Tubular Bells and Conger, as well as hurricane contingency in the Gulf of Mexico and reduced investment levels.

While preserving the strength of our balance sheet in the current environment is crucial, it is equally important for us to be well-positioned for a price recovery by maintaining both our operating capabilities and the opportunities to drive future profitable growth.

It is therefore significant to Hess that at the end of June ExxonMobil announced the drilling results from the Liza-2 well, the second well in the Stabroek block, offshore Guyana, in which Hess holds a 30% interest. The Liza-2 well encountered more than 190 feet of oil-bearing sandstone reservoirs in upper Cretaceous formations.

After successfully concluding an extensive well evaluation program and extended production test, ExxonMobil confirmed Liza as a world-class discovery with a recoverable resource of between 800 million and 1.4 billion barrels of oil equivalent.

The Stabroek block extends to 6.6 million acres, and on July 17, we spud an exploration well on a second prospect, Skipjack, located approximately 25 miles northwest of Liza. We remain excited not only about the Liza discovery but the wider opportunity set on this block, which has the potential to be transformational to our company.

Turning now to unconventionals, net production from the Bakken averaged 106,000 net barrels of oil equivalent per day for the quarter, in line with the guidance of 100,000 to 110,000 barrels of oil equivalent per day given on our first quarter call. We maintained an average of three Bakken rigs in the second quarter.

We plan to drop to two rigs in August and will begin to increase activity when oil prices approach $60 per barrel. Over 2016, we now expect to drill 65 wells and bring 90 new wells online.

In the first half of 2016, we drilled 39 new wells and brought 57 new wells online, and we plan to drill 26 new wells and bring 33 online in the second half of the year as the lower rig count takes effect. In the second quarter, our average drilling and completion cost was $4.8 million per well.

I'm very proud of our Bakken team, who has driven down D&C costs by 14% versus the year-ago quarter, even as we transition from our previous 35-stage completion design to our new 50-stage completion design.

With the higher stage count, we expect to see 30-day IP rates of over 1,000 barrels of oil equivalent per day in the second half of 2016 and expect that these wells in the core of the play will show a 7% uplift in EUR per well.

As a result of the increased productivity and EUR, and lower drilling and completion costs, we have significantly increased the number of well locations that are economic at lower prices.

Because of our continued strong performance, we are narrowing our full-year 2016 net production guidance for the Bakken to 100,000 to 105,000 barrels of oil equivalent per day, at the upper end of the 95,000 to 105,000 barrels of oil equivalent per day range that we provided in January.

Moving to the Utica, the joint venture has drilled no new wells since we released the rig we had operating in the play in early March. Net production for the second quarter averaged 29,000 barrels of oil equivalent per day compared to 22,000 barrels of oil equivalent per day in the year-ago quarter.

Similar to our Bakken position, our Utica activity is focused in the core of the play. Because the acreage in the core is held by production, we can reduce activity in the short term and preserve optionality and longer term upside. We plan to run the asset for cash in 2016 and to resume drilling following a sustained recovery in commodity prices.

As a result of applying our distinctive lean manufacturing approach, over the past few years we've been able to reduce our Utica drilling cost per foot by approximately 75% and our completion costs per stage by approximately 50%.

Using competitor benchmarking, we know that we are achieving some of the lowest D&C costs and drilling some of the longest laterals in the play. These advances position us well to restart activity when prices improve.

Now turning to the offshore and the Deepwater Gulf of Mexico, net production averaged 54,000 barrels of oil equivalent per day in the second quarter. At the Conger field, a mechanical failure on one well resulted in the loss of 4,000 barrels of oil equivalent per day of production during the second quarter.

As I mentioned earlier, this well will be worked over in the fourth quarter.

At our Tubular Bells field, in which Hess holds a 57.1% working interest and is operator, net production averaged 6,000 barrels of oil equivalent per day in the second quarter, due to the remediation work on the second well with a defective valve and a 35-day shutdown to allow for the tieback of Noble's Gunflint to the Williams-owned facility.

As mentioned previously, in July we experienced another valve failure on a third well. This well will remain shut in until completion of remediation work in the fourth quarter.

As a result of the cumulative downtime in 2016 from the three valve failures, we have reduced our full-year 2016 net production guidance for Tubular Bells to 10,000 barrels of oil equivalent per day.

A fifth production well at Tubular Bells was spud mid-June, which is scheduled to be brought online in early 2017, and we anticipate starting water injection in the third quarter. In Norway, at the BP-operated Valhall field, in which Hess has a 64% interest, net production averaged 19,000 barrels of oil equivalent per day in the second quarter.

The planned annual turnaround was completed on schedule in early July. In June, BP and Aker announced the creation of a new operating entity, Aker BP ASA. We look forward to working with the new partner to deliver further operational efficiencies and value from future development.

At the South Arne field in Denmark, which Hess operates with a 61.5% interest, net production averaged 15,000 barrels of oil equivalent per day over the quarter. Looking forward, a 20-day planned maintenance shutdown is scheduled in the third quarter.

At the Malaysia-Thailand joint development area in the Gulf of Thailand, in which Hess has as a 50% interest, net production averaged 236 million cubic feet per day in the second quarter. There is a scheduled 15-day shutdown in the third quarter to commission the new booster compressor.

Moving to developments, at North Malay Basin in the Gulf of Thailand, in which Hess has a 50% working interest and is operator, second quarter net production averaged 33 million cubic feet per day through the early production system and is expected to remain at about this level through 2016.

In the second quarter, we installed three wellhead platforms and a jacket for the central processing platform. We also successfully drilled the first eight of 11 wells for Phase I of the full field development project, which is expected to increase net production to 165 million cubic feet per day following startup in 2017.

At the Stampede development in the deepwater Gulf of Mexico, in which Hess holds a 25% working interest and is operator, the hull left the manufacturing yard in South Korea on schedule. Fabrication and precommissioning of the topsides continue according to plan, and drilling operations continue to progress. First oil remains on schedule for 2018.

In closing, while the second quarter has been challenging as a result of continued low oil prices and short-term production issues, we remain confident in our resilient portfolio and strong long-term growth outlook, which includes our offshore development projects at North Malay Basin and Stampede, our premier positions in the Bakken and Utica, our high margin chalk reservoir positions at Valhall and South Arne, and our position in Guyana, which represents a world-class opportunity.

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 2016 to the first quarter of 2016. The corporation incurred a net loss of $392 million in the second quarter of 2016, compared with a net loss of $509 million in the first quarter.

Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $335 million in the second quarter of 2016. Turning to exploration and production, on an adjusted basis, E&P incurred a net loss of $271 million in the second quarter of 2016 compared to a net loss of $451 million in the first quarter of 2016.

The changes in the after-tax components of adjusted results for E&P between the second quarter and the first quarter of 2016 were as follows. Higher realized selling prices improved results by $155 million. Lower sales volumes reduced results by $31 million. Lower DD&A expense improved results by $36 million.

Lower production expenses improved results by $9 million. Lower exploration expenses improved results by $8 million. All other items improved results by $3 million for an overall decrease in the second quarter net loss of $180 million.

In the second quarter, our E&P operations were over lifted compared with production by approximately 1.7 million barrels, which had the effect of decreasing our second quarter net loss by approximately $5 million.

The E&P effective income tax rate, excluding items affecting comparability, was a benefit of 47% in the second quarter of 2016 compared with a benefit of 41% in the first quarter. Turning to Bakken Midstream, second quarter net income of $11 million decreased from $14 million in the first quarter, primarily due to higher DD&A and interest expense.

EBITDA for the Bakken Midstream, excluding the non-controlling interest, amounted to $68 million in the second quarter of 2016 compared to $70 million in the first quarter. Turning to corporate, after-tax corporate and interest expenses were $75 million in the second quarter of 2016 compared to $72 million in the first quarter.

The increase resulted from higher professional fees and other miscellaneous expenses. Turning to cash flow for the second quarter, net cash provided by operating activities before changes in working capital was $257 million. The net decrease in cash resulting from changes in working capital was $60 million.

Additions to property, plant, and equipment were $615 million. Proceeds from asset sales were $80 million. Net debt repayments were $43 million. Common and preferred dividends paid were $89 million.

All other items resulted in an increase in cash of $8 million, resulting in a net decrease in cash and cash equivalents in the second quarter of $462 million.

Excluding the Bakken Midstream, we had cash and cash equivalents of $3.1 billion, total liquidity, including available committed credit facilities of $7.7 billion, and total debt of $5.9 billion at June 30, 2016. Our debt-to-capitalization ratio excluding the Bakken Midstream was 23.5%.

Now to provide additional third-quarter and full-year 2016 guidance, first for exploration and production. We project cash costs for E&P operations to be in the range of $16 to $17 per barrel of oil equivalent for the third quarter and $16 to $17 per barrel for the full year of 2016, which is up from previous guidance of $14.50 to $15.50 per barrel.

The increase in full-year guidance is due to workovers required at Tubular Bells and Conger and the impact of fixed costs spread over lower production volumes.

DD&A per barrel is forecast to be $28 to $29 per barrel in the third quarter and $27 to $28 per barrel for the full year of 2016, which is down from previous guidance of $28.50 to $29.50 per barrel. The decrease in full-year guidance is due to the change in the mix of production.

As a result, total E&P unit operating costs are projected to be in the range of $44 to $46 per barrel in the third quarter of 2016 and $43 to $45 per barrel for the full year.

The Bakken Midstream tariff expense is expected to be $4.10 to $4.20 per barrel for the third quarter of 2016 and $3.80 to $4 per barrel for the full year of 2016 versus prior guidance of $3.55 to $3.95 per barrel, reflecting lower total production volumes.

Exploration expenses, excluding dry hole costs, are expected to be in the range of $60 million to $70 million in the third quarter and $260 million to $280 million for the full year, consistent with previous guidance.

The E&P effective tax rate is expected to be a deferred tax benefit in the range of 42% to 46% for the third quarter and 41% to 45% for the full year of 2016, consistent with previous guidance.

For Bakken Midstream, we estimate net income attributable to Hess from the Bakken Midstream segment, which reflects our 50% ownership, to be in the range of $10 million to $15 million in the third quarter and $40 million to $50 million for the full year of 2016, consistent with previous guidance.

Turning to corporate, we expect corporate expenses net of taxes to be in the range of $25 million to $30 million for the third quarter of 2016 and $100 million to $110 million for the full year of 2016, which is down from previous guidance of $110 million to $120 million.

We anticipate interest expense to be in the range of $50 million to $55 million for the third quarter of 2016, and $195 million to $205 million for the full year of 2016, which is down from previous guidance of $205 million to $215 million. This concludes my remarks. We will be happy to answer any questions.

I will now turn the call over to the operator..

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

Thanks. Good morning everybody. Greg, I wonder if I could touch on the issues in the Gulf of Mexico? Obviously, when you gave guidance at the end of the first quarter, some of these issues were already known, so I'm just trying to understand how much of the incremental problems occurred post the first quarter.

And if possible, can you speak to the production capacity in the Gulf going into next year? Is that impacted in any way or is the capacity basically – what would you expect the (30:44) capacity to recover to, I guess is what I'm trying to find out?.

Okay. Thanks, Doug. Yeah. As we kind of said in our opening remarks now, we've had three subsurface safety valve failures in Tubular Bells. The second valve affected us in the second quarter and the third valve is going to affect us in the third quarter. And in addition to that, we had a mechanical failure at Conger that was unanticipated as well.

So the net effect of that, if we look at kind of guidance for those assets, is about 15,000 barrels a day difference lowering of our guidance, and about 10,000 of that is at Tubular Bells and about 5,000 of that is at Conger.

So, if we look at capacity going into the end of the year, we should be back up to that 70,000 to 75,000 barrels a day range in the Gulf of Mexico. So if you look – so again, going back to the guidance, it was actually about 15,000 on T-Bells and 5,000 on Conger. I said 10 and 5. It's actually 15,000 and 5,000.

So that gives you a sense for how big the magnitude was of those two issues in the Gulf..

Okay. So the capacity really isn't – all things beyond the mechanical issues, the capacity shouldn't be impacted, got it..

No..

Greg, just a quick follow-on to that, can you speak to the nature of any – what you would expect by way of compensation there? I mean is this a – do you have insurance losses or how does it work exactly?.

Yeah. Well, we're going – we've got our legal claims as we speak, and we're going to be going for the cost of the replacement valve. We're going to go for the cost of the remediation work and also lost profits due to downtime and finally attorney's fees. So we are going after it all..

All right. My follow-up, if I may, as you can imagine, is in Guyana.

Realizing you're not the operator, to the extent you can, can you outline what your expectations are for Skipjack as it relates to the risk profile post-Liza? Is Skipjack a ranked wildcat? Has it been de-risked in some way? And any color you can offer in terms of your expectations now that you're there? Thanks..

Yeah, thanks, Doug. I mean clearly, we are extremely excited about the results at Liza again confirming a recoverable resource of between 800 million and 1.4 billion barrels. The well test at Liza was high quality, very good, confirmed the presence of high quality oil that we saw in Liza-1.

We saw about 190 feet of oil-bearing sandstone in the Upper Cretaceous. And remember that the Liza-2 well was only 2 miles from the Liza-1 well. So all that taken in context means that the POSG of Skipjack has gone up substantially.

So we're excited about it, and certainly the seismic signature looks very similar to the one on Liza, so but until we get a well in the ground we can't be 100% positive as to the outcome, but very encouraging, very excited..

Timing Greg, early September?.

Yeah, we should have the result. I think we said in our remarks we should have the results of the well by our next quarterly conference call..

Got it. All right. I'll leave it there. Thank you..

Thank you. And your next question comes from the line of Brian Singer of Goldman Sachs. Your line is now open..

Thank you. Good morning..

Good morning..

You mentioned in your comments that the call on capital for Guyana for 2017 is expected to be manageable.

Can you talk more on how you expect to finance that, whether it would just be reflected in offsetting decreases in CapEx as other projects come online? Whether it would be debt to near liquidity, asset sales, or whether you would consider additional equity and if you have any sense of what you think that capital commitment might be next year?.

Sure, Brian. And I mean, as John mentioned, we do see this as being manageable at this point. Our current judgment is that the future spend will fit nicely in our portfolio as our major project spending and obligations on North Malay Basin and Stampede will be falling off over the next couple of years.

And so by 2018 North Malay Basin and Stampede will have flipped from material cash users, as John said earlier, approximately $700 million this year, to cash generators. So just with the normal phasing with any development we see, this fits nicely in 2017 and then with more of the spending happening 2018 and beyond.

And as we look at our portfolio at the capital for Guyana, and like you said, there are other capital that will be falling off in 2017, such as like in the Gulf of Mexico and some of the capital we had spent in Denmark this year.

So it does fit nicely into 2017 and we project from our strong cash position that we can fund our capital, including our growth projects, through 2017, even in this low price environment with the current cash on hand..

Got it. Thank you.

And then on the revisions to your guidance, can you talk about the impact in more – and be more specific – in some greater specificity on the deferred activity? How much of that was responsible for the decrease in the capital budget versus cost savings? And where is that all – where is that all coming from? The same question as it relates to the production drop, although I may have pieced together it's 5,000 BOE a day based on earlier comments..

So from just the $300 million that we've reduced our 2016 capital program, the majority of that reduction is due to cost reductions. Obviously, in this low price environment, we're day-in and day-out looking at cost reductions on the capital side and the operating side as well. So it really is across the whole portfolio.

It's not like there's a big chunk in any individual area, so it's in exploration, it's in production, and it's in development. We have some deferred activity that we're just looking at from the price environment slipping out to 2017 as prices improve, but the majority is cost reductions..

Great, thanks.

And was there an impact on the production guidance from that as well or was it all coming from the Gulf of Mexico issues?.

It's minor on the production from the capital reductions. Obviously, we could put capital to work because we have great locations here in the Bakken to put capital to work at these prices, but it's not what we're going to do.

We're emphasizing value over volumes, and we won't ramp up until prices really get close to $60, because we think that's a better economic decision..

And that's despite the number – despite the increase in stages in the Bakken, despite the enhanced stage count there?.

Correct. We just don't think it makes sense to accelerate that production right now, because you know, in the wells, in the first year of the well, it declines 70% in these unconventional reservoirs. So, again, we'd like to see higher prices before we bring on this good core of the core Bakken acreage..

Thank you very much..

I think those 50 stages really bode well though for the resumption of activity because, again, IP rates have gone up 15% to 20% and EURs are up 7%. So that will bode extremely well for ramp-up in activity..

Thank you..

Thank you. And our next question comes from the line of Ed Westlake of Credit Suisse. Your line is now open..

Okay. Two unrelated questions, the Upstream magazine I think has reported that Skipjack has an even larger aerial extent than Liza.

Maybe if you can sort of comment a little bit about Skipjack relative to Liza on a predrilled basis?.

Ed, you'll have to talk to the operator about that. I will tell you that, on seismic, it looks very similar..

Okay. And then on the Bakken, Schlumberger were talking last week about how much the industry is going to have to give back as a share of their cash flow to the service companies, as well as obviously put rigs back to work to get U.S. production to grow. Obviously that's a bit of a pitch from them.

But how much risk do you think there is over time to your $4.8 million well costs in the Bakken as you go forward? Have you done any sensitivities to inflation levels?.

Yeah. I think Ed – I think, as we've said before, obviously there could be some minor friction costs associated with a startup, but we've done a lot to try and preserve our lean manufacturing capability, particularly on the rig crews, by doubling up and tripling up so that we can really manage a smooth transition in a ramp-up.

And then our belief is that, with our lean manufacturing gains continuing, that any friction costs we'll be able to cover just as we have in the past with using our lean manufacturing techniques..

And then on the pressure pumping side with the attrition you're seeing in the fleet over time, say, not an issue for next year or the year after, but as you get into maybe 2018, I mean, how much would that add do you think, if you went back to normal margins?.

Yeah. I think it's just too early to tell. I think there's going to be a lot of factors that drive those numbers, how much equipment is no longer available for service, how rapid is the ramp-up in the industry? There's a lot of moving pieces there that will determine how much that will ultimately be.

But again, I think with lean manufacturing our aim and our goal is to cover as much of that as possible by using those techniques..

And finally – this may go back to the operator again, but what's the constraint on perhaps adding a rig in Guyana, because obviously exploration takes time, and rightfully so. But from an equity perspective, there's a lot of shale activity going on at the same time in other basins, so speed is something that investors sometimes want.

So maybe just talk through the constraints.

Is it geological or cash flow or other things in terms of adding a rig?.

No, I think we're in active conversations with the operator on the rig levels, both for next year for appraisal and development and all those things that we want to do and additional exploration. We're actively in conversations with the operator about that as we speak.

And while next year's program still needs to be finalized, the focus definitely will be on exploration activities on the block as well as the predevelopment work, working with the partners and the government to move forward expeditiously on a commercialization decision on Liza..

Thank you..

Thank you. And your next question comes from the line of David Heikkinen of Heikkinen Energy Advisors. Your line is now open. Please go ahead..

Thanks, guys. Actually E got my question..

Thank you. And our next question comes from the line of Asit Sen of CLSA. Your line is now open. Please go ahead..

Thanks. Good morning. So two questions, first on cost deflation and second a quick one on Bakken.

On cost deflation, Greg or John, given your involvement in both short-cycle shale and the new upcoming long-cycle deepwater projects, I just wanted to get your sense of what you are seeing in terms of cost deflation or your visibility, given recent comments by the oil service majors. So that's number one.

And what percent of your CapEx – I would imagine most of it over the next 12 months to 18 months is committed? And second on Bakken, Greg, could you remind us, how many rigs do you need to keep production flat?.

Sure. So to hold production flat at broadly 100,000 barrels a day, we've said that we need four rigs to do that. Now, with the 15% to 20% uplift, the 50-stage fracks, it's probably somewhere between 300,000 and 400,000, as a result of that uplift.

Regarding the cost reductions, I think obviously in the onshore, I think that's largely flattened out, so I think further cost reductions there will be minimal. The ones that we are accomplishing are due to lean manufacturing, which is continuing to chop out waste and inefficiency and all those things.

And I want to really comment on that because if you think about our performance of delivering a $4.8 million well, a substantial reduction from the prior year and the prior quarter, that was while also increasing the stage count from 35 to 50. So that's a major performance improvement, and all of that was lean manufacturing.

So I think that we'll continue in our operation to drive those costs down, because we know that there's even more efficiencies in spud-to-spud. And so we're going after those in earnest. In the offshore, I think there have definitely been some major price reductions, so rigs, boats, and all the associated equipment is down substantially.

We're already seeing some of those benefits in Guyana, for example, on the rig rates and seismic boat rates and all that. And then the last kind of penny to drop I think is really the yards in Southeast Asia. So if you look at their capacity loading, it's going to drop substantially over the next 12 months.

And I think that will open up another cost reduction opportunity. So for us, Guyana is coming almost at just the right time because you'll have low costs not only in drilling, but also in development if we sanction a project there for the development project as well..

Very helpful. Thanks Greg..

Thank you. And your next question comes from the line of Paul Cheng of Barclays. Your line is now open. Please go ahead..

Hey, guys. good morning..

Good morning..

Greg, just curious that, have you guys got the process talking to your vendor and trying to extend the contract period and lock in some of the very cheap service cost today, or do you think you have time to wait?.

No. I think, Paul, we're beginning those conversations. As John mentioned, as prices approach $60, we all wonder when that will be, but as prices approach $60, we want to be ready for that ramp-up. So we're starting the conversations now with certainly our vendors in the onshore..

Are you going to, say, wait until that you see $55 plus before you sign those contracts or do you think you're going to sign those contracts relatively soon?.

As we make those decisions Paul, we'll keep you informed..

Okay.

On the Tubular Bells, can you tell us that who is the vendor? And also that have you already gone through a detailed inventory track on everything that they have provided you to see if there's additional issues?.

Yes, we have, and the vendor is Schlumberger. Obviously it's extremely disappointing. It relates to some quality control and some of the components in the valves.

And as I mentioned from the previous question, we are going to go after the cost of the replacement belts, the cost of the remediation work, lost profits due to downtime and all the attorney's fees. It's very disappointing..

And is Schlumberger also providing those safety valves for Stampede?.

Yes, but they've been upgraded. We've gone through those valves and they've been upgraded and the quality control problems have been fixed as far as we can tell..

Okay. And the next one is for John Rielly. John, the second quarter your cash flow from operations annual run rate is about $1 billion, and that's about $46 oil price.

Is that a reasonable normal run rate given the pricing environment, or this is some positive or negative one-off adjustment that we need to make related to that run rate?.

So for the run rate at that price from cash flow from operations only, the only adjustments that you would make, and that is we've had the additional remediation costs at Tubular Bells, so for that production, obviously affected by the shutdowns in the quarter, and then the additional cost for Tubular Bells remediation in the quarter, so you're in that $30 million to $40 million type range on that adjustment..

Okay.

And either for Greg or John, talking about Liza, I know it's early stage, any kind of rough preliminary estimate what oil prices you need in order to generate a 15% internal rate of return for that project? And how is that comparing to the Conger discovery that you made?.

So it's early and I think this is the type of information that the operator will be giving out. So what are the benefits of Liza, let's just say, because we always want to make sure we talk about the difference of Guyana, and Liza in general, versus let's say offshore Gulf of Mexico Paleogene.

So in offshore Guyana these wells are only 13,000 feet below the mud line, so 18,000 total depth. So the depth is much – is shorter than obviously the Gulf of Mexico so drilling wells will be cheaper. The reservoir is quite good, so we should get good flow rates out of Guyana for that.

There is no salt cover, which one helps with imaging, as we were talking about the Skipjack prospect, but again takes casing strings out while we're drilling wells. So, again, that makes it better. And then the other thing from a – I can't talk about the particulars, but it is a PSC.

So you get benefit obviously at lower prices with higher cost recovery. So putting all those together makes Guyana – I'm going to say completely different than the Gulf of Mexico and therefore in lower price environments Guyana competes.

So I think beyond that you'll have to talk to the operator, and as we get to FID and Exxon puts out that costs and numbers like that, as when FID happens, you can get a better feel for those economics..

Got it.

Can you give us a rough idea that what's the timeline when you decide whether you go for the early production system, or that – I mean, is there any timeline we should be watching?.

Obviously, Paul, as we mentioned before, predevelopment work is under way, so obviously it's underway because we and our partners and the government are encouraged that we have the type of information that we could move forward on a commercialization decision on Liza. And when we do, we will keep you informed..

Okay. A final one, Greg, you haven't mentioned anything about Ghana and in terms of the discovery and that negotiation with the government.

Any update there?.

Sorry, my mic was off. As we've said before, we're really unable to proceed with the development of this license until there's a resolution of the border dispute. So we're continuing feed. We're continuing all the project work, and we're also in discussions with the government to modify the license deadlines with respect to the border dispute.

And then once that situation is resolved, we'll be in the position to make an informed decision on where we go next..

Okay.

And in Liza, that broad – when the exploration period will expire?.

It's mid-2018 for the exploration period..

2018? Thank you..

Thank you. And our next question comes from the line of Ryan Todd of Deutsche Bank. Your line is now open. Please go ahead..

Great, thanks. Maybe a question on asset sales at this point.

I mean, do you see a role for asset sales in helping to manage capital requirements over the next couple of years? Anything in the portfolio that you would see as potentially non-core at this point? And maybe part of that are you happy with your existing working interest at Guyana, or would you consider farming that down at some point?.

Yeah. Our first priority is to preserve the strength of our balance sheet and to fund the growth opportunities that we talked about. In that respect, we are really well-positioned with $3.1 billion of cash at the end of the second quarter.

In the normal course of business, we're always looking to optimize our portfolio, be it selling assets, buying assets, but any of those opportunities would need to compete for capital against our existing attractive growth options, including the Bakken, Utica, North Malay Basin, Stampede, and obviously Guyana.

So from an M&A perspective, buying or selling, it's lower on the priority list because of the cash position we have and the growth we've already captured..

Okay, thanks.

And then maybe slightly related to that, your decision to – your decision on Sicily, I mean, is that just a reflection of allocation of scarce capital? Is it in line with your previous comments that you were talking about Guyana versus Gulf of Mexico development, or is there something about the asset that wasn't particularly attractive? And did you – was there an effort made to sell the position or are you just withdrawing from the position?.

So first of all, I think it was – it's a combination of factors, so it's the current price environment, the limited time remaining on the leases, and as you have intimated, we've got some great growth prospects in our portfolio.

So as we kind of looked at Sicily in the context of our existing portfolio, we said, you know, it's going to struggle to compete for capital against all the great opportunities we have.

So that's when we made the decision, even though we found hydrocarbons there and there's a lot of oil in place there, we made the decision to say, no, it's not going to compete in our portfolio, so we are not going to elect to do any more work on the block..

And did you try to sell that position or was it just an exit?.

No, it'll just be an exit. Yeah..

Okay. Thank you..

Thank you. And our next question comes from the line of Paul Sankey of Wolfe Research. Your line is now open..

Hi, guys. Thank you. You've covered a lot of ground here. One thing that intrigues me about Hess is the way your tax rate will essentially benefit you if prices rise. Can you talk a little bit about that? I think it's an important part of the bull case for Hess. Thank you..

You are absolutely right, Paul. So in the U.S. and in Norway, we've said we will not be paying cash taxes for the next five years because of the investments we've made in both of those countries. And quite frankly, with the way prices have been here recently, it's going to extend beyond five years.

So we will benefit from that from a cash flow standpoint ,and we'll get that uplift. And it's part of the thing that we talk about, that like $1 right now is approximately $70 million of cash flow for us, or $10 obviously being $700 million.

If you were looking at that from a results standpoint that would only be in the $45, $50 type range, the difference being the tax benefit and essentially that cash benefit that we have. So we will get that uplift when prices improve and we go back to drilling.

And so from additional volumes and the cash flow that comes in, we'll get, if you want to say, increase because of the cash tax position that we're in..

Understood. And I know you've totally changed the subject to one you've talked a lot about already, but the Guyana situation is I think the press release especially coming from ExxonMobil is one of the most – biggest I've ever seen in terms of the use of the word world-class and the range of the prospect.

Can you just talk a bit more about really how you see yourselves in terms of whether this is to let's say to throw up yet another potential development of a similar scale to Liza or another? Would you be looking to reduce your position or do you really want to run this one through and stay with the fact that you've got a world-class operator in such a material stake? I'm just struggling sort of to get my arms around the scale and how the scale relates to Hess and whether you can help us with – whether if it was within its current range, you would want to stay fully invested at the current level or if there's some sort of trigger point, just to help us out.

Thank you..

Yeah. We're very comfortable staying at the current level, Paul. Obviously, this will take time to unfold as evaluation work and predevelopment work is done. We think the block has extraordinary potential, and that will be very good for our shareholders.

And the work that we're doing we see it phased over time, so we see our ability to fund it to be manageable. We talked about next year and then John talked about the years after that.

So with the visibility that we see so far, we should be fine from a funding perspective, as well as the fact that this is probably one of the best uses of our capital, so we will want to stay in..

Yeah. I understand that. Okay, thanks a lot..

Thank you. And your next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Your line is now open..

Good morning.

You touched on this briefly, but can you add any color regarding Aker BP operating Valhall once the merger is complete? I mean, is there some anticipation that this might prove superior to BP's operatorship in some way?.

Yeah, I think it's – I think it's early to say actually. John and I met with the senior leadership of Aker BP and I will say that we left very encouraged. They have a culture similar to ours, meaning an independent, and they like to get after stuff and they're innovative. And in particular, they're practitioners of lean.

And as you know, supplying lean on Valhall through BP has led to a substantial reduction in abandonment costs, well abandonment costs, by up to 50% as a result of applying lean, and then drilling costs for new wells on the order of 30% with much more to come.

So we're excited about having another partner in this venture that also is a lean practitioner. We think there will be a lot of power in that in really driving down the cost and delivering value from Valhall..

Okay. Thank you.

As you move towards commercialization of Liza, do you anticipate any special issues, bearing in mind that oil infrastructure development at Guyana is essentially going to be starting from scratch?.

No. None that you wouldn't have anywhere else. I mean, the oil will most likely be tankered so I don't foresee any issues there. And certainly things will be built probably in other parts of the world to get started. And so I don't think there's any particular concerns about Guyana..

Okay, great. Thank you. And my last question is you've touched on it broadly. Your JV partner identified two completions and five timelines in Utica in the second quarter.

And since your remarks even today suggest that the Bakken should generally attract capital before the Utica, can you add a little color as to how Utica attracted activity in the quarter?.

Yes. I think we had some wells that we completed in the quarter, so we brought – we completed two, and we bought five wells online in the second quarter. And that essentially completes the activity that we plan to do in the Utica this year.

I always like to remind people, our Utica position is unique because it is in the core of the core, it is held by production, and it only has 5% royalty. So because of that, that really delivers superior economics even at low prices relative to the people around us.

So just like the Bakken, as prices approach $60 and we see some margin improvement unique to the liquids in kind of the environment in the Utica, we would expect to get back to work in the Utica as well as the Bakken as we approach those numbers..

Okay, great. Thanks very much. I appreciate it..

Thank you. And your next question comes from the line of Guy Baber of Simmons. Your line is now open..

Thanks for taking my question. Just as a follow-up to the last question, you mentioned the resumption of drilling at the Utica and offshore at a sustained higher price.

Can you talk a little bit more about what price you need to see? I think you mentioned $60 sustainably before, but how you would look to deploy capital and where you would go first and what the order looks like? But it sounds as if Utica would be ahead of Gulf of Mexico infill drilling or other offshore infill drilling opportunities.

Is that a fair comment?.

No, I think it – we'll evaluate it as the situation unfolds. I think the point is we've got an awful lot of profitable development opportunities in our portfolio, and how those shake out as prices improve, we'll answer that at that moment in time.

It's going to be a function of rig rates and supply costs and all those things that go into economic decisions. But I think the point is that outside of the Bakken, we have exceptional opportunities to grow this business, not only in the Utica but also in our offshore assets, be it the Gulf of Mexico or the chalk assets in the North Sea.

So as John said in his opening remarks, I do think we have an exceptional growth portfolio that can deliver outstanding growth as a function of price..

Okay, great. And then I had two follow-ups on capital spending. You mentioned there were efforts underway to make further reductions to the $2.1 billion budget.

Is there anything specific that you would call out, or is it just the continued application of lean manufacturing? And then secondly, as we think about the capital spending profile over the next couple of years, is it a fair characterization that you all are comfortable with CapEx above and beyond your cash inflows to a certain extent, just given the strength of the balance sheet and the strength of your growth projects?.

So from the further capital reductions it is just continuing lean across our whole portfolio and organization just to drive out costs. So it's an ongoing kind of culture that we have to continue to drive down the cost. So that's really what that would be from a cost standpoint.

As far as capital goes, it's early right now, so what we are talking about here is what we've been doing in 2016. And it's still early for us. And we'll give further updates here as we get into early 2017, especially on Guyana, because that will be a part of the growth capital that now gets added in.

So what we'll be doing, we will be spending in Guyana, for all those reasons that we've talked about today on the returns that we believe we see in Guyana, so we'll be spending there. We'll be finishing North Malay Basin, and we'll be finishing Stampede to bring on that 35,000 barrels a day in 2018.

So along with that, depending on where we see price moving to, if we don't see it moving more to $55, $60, you'll see more of the same of what we're doing in our portfolio right now. As prices move up, then we're going to start going back to those opportunities that Greg just talked about that we see across the portfolio..

Thank you very much..

Thank you. And your next question comes from the line of John Herrlin of Societe Generale. Your line is now open..

Yes. Thank you. Most things have been asked, so I'll be brief.

With the Bakken, with these 50-stage frack wells, how much sand and floats (65:29) are you putting down, Greg?.

Sorry, my mic was off again. Per-stage proppant loadings, it ranges to where you are in the field. We really do it DSU by DSU, but on the order of 80,000 to 100,000 depending on where you are in the field. So that's kind of the proppant loading per stage..

Okay. Thanks.

And not to beat Liza into the ground, for your predevelopment activities, could you better characterize what they are, because I don't think people fully understand it?.

In Guyana you mean? Well, I think it's just the usual....

Yes right. Exactly.

Are you arranging marine transportation? Are you looking at yards? What's the predevelopment activity right now?.

Well, I think it's the usual pre-project, concept select, trying to figure out which concept you're going to have, potentially how many wells you're going to drill, how many producers, how many injectors, et cetera, et cetera. So that's all the predevelopment work that's going on..

Okay, thanks..

Yes..

Thank you. And your next question comes from the line of Pavel Molchanov of Raymond James. Your line is now open..

Hey, guys. Two questions, the first one back to the approaching $60 number you mentioned. About a month ago, the 12-month strip for WTI was actually in the mid-50s.

When you saw that, did you think maybe not take the extra rig off, going from three to two in August as you're currently planning? Was that ever under consideration?.

Look, we always look at different options to maximize value for our shareholders. But having said that, no, our commitment was to go down to two rigs to preserve cash, but also we think it's about value not volumes.

And we really, at the end of the day, while you always think about making midcourse adjustments to maximize value, the decision was and it still is to go to two rigs.

And then as prices start to improve, as the market rebalances, and I think the market is in the process of rebalancing because non-OPEC production is down, offset by OPEC production, but you're still growing demand in the world over 1 million to 1.5 million barrels a day, somewhere in that range, inventory draws are going to happen, probably accelerate in the fourth quarter.

And with that we see that positive to prices starting to recover and going up. So as we get closer to $60, that's when we'll start putting plans in place to start to go up in our rig count in the Bakken. And we're sticking to that..

Okay. And then second question about the Bakken MLP. So this year – or this month marks the one-year anniversary of your deal with Global Infrastructure Partners.

Is it safe to say that you're going to want to stabilize your Bakken volumes before you move forward with the IPO? Is that part of the prerequisite to getting that done?.

Yeah. So the way that we are looking at it right now, we are committed to doing the IPO. And so it is part of our plans to do that, us and our partner GIP, but it is when market conditions warrant. And so one is the MLP market itself, which has improved, but we will continue to watch that. And then it's exactly as you just said, Pavel.

As from the oil price standpoint, to get the prices up, for us to put more rigs back to work and in this great position that we have in the Bakken, that's when we start to see that. And that growth combined with any improvements in the MLP market is when we would be looking at timing of that..

Okay. Appreciate, it guys..

Thank you. And your next question comes from the line of Arun Jayaram, of JPMorgan. Your line is now open..

Yeah. Good morning. Arun Jayaram from JPM. Just a quick question on Tubular Bells. You guided to 10 for the year.

Could you give us a sense of what you expect the exit rate to be at Tubular Bells once the remediation activities are completed, plus what the fifth well will do in terms of deliverability as we think about 2017?.

Okay. So we'll give guidance here as we get into early 2017 on Tubular Bells and say where this next well is. But let me just give you general of where we are right now. So with the current wells and wells fee off, we're approximately around 15,000 barrels a day here producing at Tubular Bells.

There will be a shutdown in the third quarter at T-Bells, and then we are not going to remediate this well C, which is approximately 5,000 barrels a day net to us in the fourth quarter. So just with that well you're getting to the 20,000 or a little above when we have the wells together.

Then with this next producer we'll come on and we'll give you information, because we're not – I'm not sure exactly when that's going to come on at this point right now..

Okay. That's fair enough.

And just a quick follow-up, is the $300 million or so of capital that you took out of this year's budget where did that come from?.

I was saying this earlier. So we did – it's basically the majority is cost reductions and it is literally across our portfolio. So there's not one significant item. It's in exploration, it's in production, and it's in development.

So, again, the majority from that with some deferral of activity as well, so there's really no big names or big assets that I could point you to from that. It's just continuing to drive down costs across the portfolio..

Okay. Thanks a lot..

Sure..

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