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

David Martin Heikkinen - Heikkinen Energy Advisors Douglas Todd Terreson - Evercore ISI Doug Leggate - Bank of America Merrill Lynch Roger D. Read - Wells Fargo Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Paul Benedict Sankey - Wolfe Research LLC Ryan Todd - Deutsche Bank Securities, Inc. Brian A.

Singer - Goldman Sachs & Co. Paul Y. Cheng - Barclays Capital, Inc. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. Pavel S. Molchanov - Raymond James & Associates, Inc. Guy Allen Baber - Simmons & Company International.

Good day ladies and gentlemen and welcome to the second quarter 2015 Hess Corporation conference call. My name is Lisa and I'll 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, Lisa. 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 Federal Securities laws.

These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC.

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

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 highlights from the quarter and an update on the steps we are taking to strengthen our financial position while preserving our long term growth options in the current low oil price environment.

Greg Hill will discuss our operating performance, and John Rielly will then review our financial results. Regarding our financial position, on July 1, we closed on the sale of a 50% interest in our Bakken Midstream assets for a cash consideration of $2.675 billion and formed a joint venture with Global Infrastructure Partners.

This transaction delivers significant and immediate value to our shareholders, and bolsters our financial flexibility in the current low oil price environment.

At closing, the joint venture incurred $600 million of debt through a five-year Term Loan A facility, with proceeds distributed equally to both partners, resulting in total after tax proceeds net to Hess of $3 billion.

Importantly, this joint venture has independent access to capital, including a fully committed $400 million, five-year senior revolving credit facility to help grow our Midstream business.

As previously announced, the joint venture plans to proceed with an initial public offering of Hess Midstream Partners LP common units pending SEC review and market conditions.

With the proceeds from the Midstream asset transaction plus cash on hand and an untapped $4 billion revolving credit facility, Hess has one of the strongest liquidity positions among our peers.

Consistent with our financial strategy, the proceeds from this transaction will enable us to preserve the strength of our balance sheet in the current low oil price environment, provide additional financial flexibility for future growth opportunities, and continue to repurchase stock on a disciplined basis.

With regard to our financial results, in the second quarter of 2015, we posted a net loss of $567 million. On an adjusted basis, the net loss was $147 million or $0.52 per share compared to net income of $1.38 per share in the year-ago quarter.

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

Net production averaged 391,000 barrels of oil equivalent per day, an increase of 23% from pro forma production in the year-ago quarter, excluding Libya. This improvement was driven by higher production from the Bakken and Utica shale plays, the joint development area of Malaysia/Thailand, and Tubular Bells in the deepwater Gulf of Mexico.

In light of our strong performance year-to-date, we are raising our overall company production forecast for 2015 by 10,000 barrels of oil equivalent per day to a range of 360,000 barrels of oil equivalent per day to 370,000 barrels of oil equivalent per day, excluding Libya. Turning to the Bakken.

Net production averaged 119,000 barrels of oil equivalent per day in the second quarter, above our guidance range.

As a result of our strong year-to-date performance, we are increasing our full year 2015 production forecast to a range of 105,000 barrels of oil equivalent per day to 110,000 barrels of oil equivalent per day, up from our previous guidance of 95,000 barrels of oil equivalent per day to 105,000 barrels of oil equivalent per day.

Hess is one of the strongest acreage positions in the Bakken, with more drilling spacing units or DSUs in the core of the play than any other operator. Through the application of Lean manufacturing techniques and supply chain cost savings, our Bakken team continues to drill some of the lowest cost wells in the play.

In the second quarter, drilling and completion costs averaged $5.6 million, down 24% from the year-ago quarter. In addition, our wells continue to rank among the most productive.

As a result, we are able to deliver financial returns that are attractive even at current prices, and are competitive with those in the best shale oil plays in the United States.

In addition, we are leveraging this expertise in Lean manufacturing techniques from the Bakken to drive improvements in our joint venture operations in the Utica where net production for the second quarter average 22,000 barrels of oil equivalent per day.

Given the adverse pricing environment for natural gas and natural gas liquids, Hess, along with our joint venture partner CONSOL, elected earlier this year to reduce drilling activity in the Utica to a single Hess-operated rig for the second half of 2015.

Even with this reduction in activity, we are increasing our full year 2015 production forecast by 5,000 barrels of oil equivalent per day to a range of 20,000 barrels of oil equivalent per day to 25,000 barrels of oil equivalent per day as a result of strong well performance and efficiency gains.

Turning to the deepwater Gulf of Mexico, net production from our Tubular Bells field in which Hess has a 57% interest and is operator, averaged 23,000 barrels of oil equivalent per day in the quarter, as we continue to ramp up production.

As a result of some short-term production issues which Greg will discuss in his remarks, we are lowering our full year guidance for Tubular Bells by 5,000 barrels of oil equivalent per day to a range of 25,000 barrels of oil equivalent per day to 30,000 barrels of oil equivalent per day.

In the Malaysia/Thailand joint development area, in the Gulf of Thailand, net production for the second quarter averaged 47,000 barrels of oil equivalent per day, an increase of 11,000 barrels of oil equivalent per day from the year-ago quarter when we had planned downtime to complete booster compression and wellhead tie-ins.

Regarding our developments, we continued to progress two Hess-operated offshore projects during the quarter.

Full field development of the North Malay Basin project in this Gulf of Thailand in which Hess has a 50% working interest is on track for first production in 2017 which should increase net production from approximately 40 million cubic feet per day currently to 165 million cubic feet per day.

In the deepwater Gulf of Mexico, the Stampede project in which Hess has a 25% working interest is on track for first production in 2018. Gross recoverable resources for Stampede are estimated in the range of 300 million barrels of oil equivalent to 350 million barrels of oil equivalent.

In terms of exploration, our strategy is to create future growth options that deliver long-term value by focusing on proven and emerging oil-prone plays in the Atlantic Basin, areas we understand well and that leverage our offshore drilling and development capabilities.

In the deepwater Gulf of Mexico, we are encouraged by the Chevron-operated Sicily discovery in the Keathley Canyon area in which Hess has a 25% working interest. Well data is being analyzed and an appraisal well to further evaluate the discovery is expected to spud late this year or in early 2016.

On the Stabroek Block offshore Guyana, where Hess has a 30% working interest, the operator, Exxon Mobil, announced a significant oil discovery in late May at the Liza prospect. We are now in the process of evaluating the resource potential on the block and recently commenced the acquisition of 17,000 square kilometers of 3D seismic.

Capital and exploratory expenditures in the second quarter of 2015 were $1.07 billion, down 15% from the second quarter of 2014. We continue to project that full year 2015 capital and exploratory expenditures will be $4.4 billion, more than 20% lower than our 2014 spend. In summary, we delivered another quarter of strong operating results.

We remain confident that our financial strength, resilient portfolio and proven operating capabilities position us well in the current low oil price environment as well as for competitive growth when prices recover. I will now turn the call over to Greg for an operational update..

Thanks, John. I'd like to provide an operational update and review our overall progress in executing our E&P strategy.

Starting with production, in the second quarter, we averaged 390,000 net barrels of oil equivalent per day, substantially exceeding our second quarter guidance of 355,000 to 365,000 barrels of oil equivalent per day and reflecting strong performance across our portfolio; notably in the Bakken and the Gulf of Mexico.

As a result of continuing strong performance we are increasing our full year 2015 net production forecast by 10,000 barrels of oil equivalent per day to a range of 360,000 to 370,000 barrels of oil equivalent per day, excluding Libya.

On this same basis, we forecast net production in the third quarter to average between 355,000 and 365,000 barrels of oil equivalent per day. Our third quarter forecast reflects planned downtime at the JDA, lower activity levels in the Bakken, and hurricane contingency in the Gulf of Mexico.

During the second quarter, we continued to actively drive down our cost structure. We now project a further reduction in our cash operating costs of $60 million to $70 million, bringing cash operating cost savings for the year to over $300 million, and our total cost reduction savings including capital to over $600 million.

We continue to identify opportunities to reduce costs further and we'll keep you appraised as appropriate.

Turning to operations and beginning with unconventionals, in the second quarter, net production from the Bakken averaged 119,000 barrels of oil equivalent per day compared to 108,000 barrels of oil equivalent per day in the first quarter and 80,000 barrels of oil equivalent per day in the year-ago quarter.

Higher-than-expected production availability and improved well performance allowed us to substantially exceed our second quarter net production guidance of 100,000 to 110,000 barrels of oil equivalent per day.

In line with our plan and as previously communicated, we reduced our Bakken rig count from an average of 12 in the first quarter to an average of 8 in the second quarter, which is where we expect to remain for the balance of the year.

Over 2015, we expect to drill 187 wells, complete 217, and bring 225 wells online, compared to last year where we drilled 261 wells, completed 230 and brought 238 online. In the first half of 2015, we brought 137 new wells online and we expect to bring 88 wells online in the second half of the year as the lower rig count takes effect.

As a result of strong performance, we are increasing our full year 2015 net production forecast for the Bakken by 5,000 barrels of oil equivalent per day to average between 105,000 and 110,000 barrels of oil equivalent per day.

We do expect Bakken production to turn modestly lower in the second half of the year, reflecting the lower rig count and the resulting lower number of completions. In the third quarter, we forecast net Bakken production to average between 105,000 and 110,000 barrels of oil equivalent per day.

Through the application of our distinctive Lean manufacturing capability combined with our supply chain cost reductions we continue to drive Bakken drilling and completion costs lower with the second quarter averaging $5.6 million per well versus $6.8 million in the first quarter and $7.4 million in the year-ago quarter.

For full year 2015, we now expect drilling and completion costs to average between $5.8 million and $6 million per well, below our previous guidance of $6 million to $6.5 million per well.

We know from benchmarking that we are delivering some of the lowest cost and highest productivity wells in the Bakken, which in combination means that we are generating some of the highest returns in the play.

With an eight rig program at current strip prices and costs, we have about a 10-year inventory of drilling locations that can generate after-tax returns of 15% or higher. Moving to the Utica. In the second quarter the joint venture drilled 10 wells, completed 15, and brought 9 on production.

Net production for the second quarter averaged 22,000 barrels of oil equivalent per day compared to 7,000 barrels of oil equivalent per day in the year-ago quarter and 17,000 barrels of oil in the first quarter of 2015.

Similar to our Bakken position, our Utica acreage is largely held by production, which allows us to reduce activity in the short term while preserving the long-term upside.

As previously mentioned, due to the current pricing environment the joint venture elected to focus activities on the liquids-rich Harrison County acreage utilizing a single Hess-operated rig across the JV. We continue to drive down our well costs in the Utica.

Through application of our distinctively manufacturing capability and supply chain reductions, we now project our 2015 full-year drilling and completion costs in the Utica to average between $9.2 million and $9.5 million per well as compared to $13.7 million in 2014.

As a result of improving efficiency, we now forecast that the JV will drill 20 to 25 wells and bring 25 to 30 new wells online in 2015.

Well productivity continues to be encouraging and as a result, we're increasing our 2015 net production guidance by 5,000 barrels of oil equivalent per day to a range of 20,000 to 25,000 barrels of oil equivalent per day. Now, turning to the offshore.

In the deepwater Gulf of Mexico, net production averaged 23,000 barrels of oil equivalent per day in the second quarter at our Tubular Bells field in which Hess holds a 57.1% working interest and is operator.

Due to a delay in bringing on the fourth well, coupled with the now-resolved compressor mechanical issues we experienced in the fourth quarter, we are lowering our 2015 full year forecast to between 25,000 and 30,000 net barrels of oil equivalent per day. The fourth well is now in production and is being ramped up to full capacity.

In Equatorial Guinea, net production averaged 43,000 barrels of oil equivalent per day in the second quarter at our Okume and Ceiba fields in which Hess holds an 85% working interest and is operator.

During the quarter, we brought online the OF-15 (18:39) well, the final well in the current drilling campaign at a rate of 3,000 barrels of oil equivalent per day. The mobilization of the rig has commenced and will be completed in the third quarter. 4D Seismic processing is underway to support future exploitation drilling.

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 second quarter. One new producer was brought online and planned maintenance activities were successfully completed.

We continue to expect full year 2015 net production to be in the range of 30,000 to 35,000 barrels of oil equivalent per day.

In the Gulf of Thailand at North Malay Basin, in which Hess as a 50% working interest and is operator, second 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 June, we installed two wellhead platform jackets and commenced construction on wellhead platform topsides as part of the full field development project which is expected to increase net production to 165 million cubic feet per day in 2017. Moving to exploration. The first two wells from our new program delivered encouraging results.

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. Sicily penetrated a four-way lower tertiary structure located in approximately 6,400 feet of water.

As John mentioned, an appraisal well to further evaluate the discovery is planned to spud late 2015 or early 2016. In May, ExxonMobil announced a significant oil discovery at the Liza prospect on Stabroek Block of offshore Guyana in which Hess holds a 30% earned interest.

The operator recently commenced an extensive 3D seismic survey to further delineate both the discovered resource and the potential of the block. In closing, I am very pleased with the performance of our team who once again achieved strong operational results. 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 2015 to the first quarter of 2015. As previously announced, we have reported Bakken Midstream results beginning with the second quarter of 2015. As a result, we have recast prior quarters to reflect the breakout of the Bakken Midstream from E&P.

In our second quarter supplemental presentation located on the Hess website, we have included recast quarterly information of E&P and Midstream for 2014 and the first two quarters of 2015. Now turning to results.

Our adjusted net loss which excludes items affecting comparability of earnings between periods was $147 million in the second quarter of 2015 compared to $279 million in the first quarter of 2015.

On a GAAP basis, the corporation incurred a net loss of $567 million in the first quarter of 2015 compared with a net loss of $389 million in the first quarter of 2015.

Turning to Exploration and production on an adjusted basis, E&P incurred losses of $96 million in the second quarter of 2015 compared to a loss of $221 million in the first quarter of 2015. The changes in the after-tax components of adjusted results for E&P between the second quarter of 2015 and first quarter of 2015 were as follows.

Higher realized selling prices improved the results by $118 million. Higher sales volumes improved results by $71 million. Higher cash operating costs in Bakken Midstream tariffs reduced results by $20 million. Higher DD&A expense reduced results by $46 million.

All other items net to an improvement in results of $2 million for an overall improvement in the second quarter adjusted results of $125 million. In May, we expanded our crude oil hedging program by entering into WTI crude collars covering 20,000 barrels per day through the end of 2015.

As a reminder, we previously hedged 50,000 barrels per day for 2015 using Brent crude collars. Both the Brent and WTI crude collars have a floor price of $60 per barrel and a ceiling price of $80 per barrel.

For the quarter, our E&P operations were overlifted compared with production by approximately 400,000 barrels which had the effect of decreasing our second quarter after tax loss by approximately $8 million. The E&P effective income tax rate excluding items affecting comparability was a benefit of 56% for the second quarter of 2015.

This outcome was favorable to guidance and primarily resulted from the mix of income generated by operations during the quarter. The E&P effective tax rate in the first quarter of 2015 was a benefit of 48%. In the press release, we announced a non-cash goodwill impairment charge of $385 million related to our onshore reporting unit.

This charge was triggered under the accounting standards that require goodwill be reallocated and a review for impairment be performed when an operating segment is split, as was the case of breaking out Bakken Midstream from E&P in the quarter.

The goodwill impairment for the onshore reporting unit reflects the impact of the reallocation of goodwill and the low commodity price environment.

Turning to Midstream activities, the Bakken Midstream segment had net income of $32 million in the second quarter of 2015, compared to $27 million in the first quarter of 2015, while EBITDA amounted to $74 million in the second quarter of 2015 compared to $65 million in the previous quarter.

In the earnings supplement, we have provided quarterly consolidated income statements of the company to facilitate an understanding of the movement in reported numbers caused by separating the Bakken Midstream segment from E&P. Using the second quarter of 2015 as an example, E&P metrics changed as follows.

Cash operating costs improved by $1.15 per barrel to $15.65 per barrel as $42 million of costs are now included in Bakken Midstream. DD&A improved by $0.62 per barrel to $28.22 with $22 million of DD&A transferred to Bakken Midstream.

As a result, overall E&P unit operating costs improved by $1.77 per barrel and were $43.87 per barrel in the second quarter. Bakken Midstream tariff expense was $116 million or $3.26 per barrel which, combined with the improved unit costs, decreased E&P's pre-tax earnings by $52 million or $1.49 per barrel.

This reduction in E&P earnings has been transferred to the Bakken Midstream segment as shown in the press release on page 19. Turning to corporate and interest.

Corporate and interest expenses excluding items affecting comparability and after income taxes, were $83 million in the second quarter of 2015 compared to $85 million in the first quarter of 2015. Turning to cash flow.

Net cash provided by operating activities in the second quarter including a decrease of $170 million from changes in working capital was $541 million. Excluding working capital changes, cash flow from operations was $711 million, a 51% increase from the first quarter. Capital expenditures in the quarter were $1.013 billion.

Common stock acquired and retired amounted to $11 million. Repayments of debt were $17 million. Common stock dividends paid were $72 million. All other items amounted to a decrease in cash of $3 million, resulting in a net decrease in cash and cash equivalents in the second quarter of $575 million.

We had $931 million of cash and cash equivalents at June 30, 2015. Total debt was approximately $6 billion at both June 30, 2015 and March 31, 2015. The corporation's debt-to-capitalization ratio at June 30, 2015 was 22% compared to 21.6% at March 31, 2015.

On July 1, 2015, we closed the Bakken Midstream joint venture with Global Infrastructure Partners for after-tax proceeds of approximately $3 billion which includes the corporation's share of debt proceeds issued by the joint venture at formation. I would like to provide updated guidance for the remainder of 2015.

Starting with E&P, for the full year of 2015, cash costs for E&P operations are reduced $1.50 per barrel of oil equivalent to $16, to $17 per barrel of oil equivalent. The separation of the Bakken Midstream segment is responsible for $1 of this reduction and the additional $0.50 reduction is due to our ongoing cost efficiency initiatives.

For the third quarter of 2015, cash costs are expected to be in the range of $16.50 to $17.50 per barrel of oil equivalent.

DD&A per barrel guidance remains at $28.50 to $29.50 per barrel of oil equivalent for both the third quarter and full year 2015, resulting in total E&P unit operating costs of $45 to $47 per barrel of oil equivalent for the third quarter and $44.50 to $46.50 per barrel of oil equivalent for the full year of 2015.

The Bakken Midstream tariff expense is expected to be $3.55 to $3.65 per barrel of oil equivalent for the third quarter of 2015 and $3.40 to $3.50 per barrel of oil equivalent for the full year of 2015.

Exploration expenses excluding dry hole costs are expected to be in the range of $110 million to $120 million in the third quarter and our full year guidance of $380 million to $400 million is unchanged.

The E&P effective tax rate, excluding items affecting comparability and Libyan operations is expected to be a benefit in the range of 41% to 45% for the third quarter and 44% to 48% for the full year. Turning to Midstream.

For the third and 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. Now, for corporate and interest.

For the third quarter of 2015, corporate expenses are estimated to be in a range of $30 million to $35 million net of taxes and interest expenses are estimated to be in the range of $50 million to $55 million net of taxes.

The full-year 2015 guidance for corporate expenses of $120 million to $130 million net of taxes and interest expenses of $205 million to $215 million net of taxes remains unchanged. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator..

And your first question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please proceed..

Good morning, guys, and good quarter..

Good morning..

One of the things that people have been focusing on is the trajectory of the Bakken and kind of your pace. Greg, you've kind of outlined that.

As you think about glide planing down in third quarter and fourth quarter at this pace, how does that flatten versus your second quarter peak volumes?.

It's a good question. I think with an eight rig program we expect to be able to hold kind of long-term production flat at or near this 100,000 barrels a day which I think we've said on the previous calls.

And I think as John mentioned in his remarks, with this eight rig program at current strip prices and well costs we've got about a 10-year inventory of drilling locations that generate after-tax returns in excess of 15% or higher..

Yeah.

And then, that's helpful, and then as you think about Tubular Bells ramp with the fourth well coming online, how does that roll forward?.

I think again in our guidance, we did lower our guidance because of the operating problems that we discussed and the deferral of the fourth well.

And so, I mean the glide path, we'll stay within our guidance as we gave on the call, right?.

Okay. That's fair.

And thinking about Guyana and the significant discovery, haven't known you guys as long some other exploration companies, can you put significant in a ballpark for me?.

No, we can't. It's just again, it's too early. I think, recall we did encounter more than 295 feet of high quality oil-bearing sandstone reservoirs in this block, and again, the entire block is about 6.6 million acres.

So, as John and I both said in our opening remarks, really the next step is we've started shooting 3D seismic on the block and we continue to evaluate the results of the well but obviously it's very encouraging..

Okay. Thanks, guys..

Your next question comes from the line of Doug Terreson with Evercore. Please proceed..

Good morning, everybody..

Good morning, Doug..

One of the key themes today and also in the industry has been that lower service costs relating to expense in capital productivity.

And on this point, I wanted to see if you'd elaborate a little bit more on your experience thus far; namely, whether the changes that have unfolded have been similar to your expectations and also previous cycles, for John? And also any insight into the pace of change that you're seeing in the market? I mean we talked about, you guys talked about a $600 million figure on the call I think, and so the question is how does that compare to what your expectations were for savings earlier in the year?.

Yeah, I think, I think compares very well. So, just to give you an example. So, the $1.2 million per well that we reduced in the quarter in the Bakken, if you look at where those savings came from, supply chain savings amounted to about 60% of those savings. And then the Lean manufacturing efficiency gains made up the balance of the 40% reduction.

So again, fairly significant results from the supply chain..

Okay. And then also just another quick question on Guyana.

First, will you guys be able to book reserves in the country? Do we know that and also how significant do you think that this interaction is with the opposition from the Venezuelan government? Is that something that we should be concerned about or focused on; how do you think about that?.

On the political side, I'm going to leave that to the politicians. But we don't think it's going to have any impact on our financial position there or our reserve position there..

Okay.

And John, can you guys book reserves there if in fact there are any in the future?.

Yes. Yes, we can..

Okay. Thanks a lot guys..

Thank you..

Your next question comes from the line of Doug Leggate with Bank of America. Please proceed..

Thanks. Good morning, everybody. I also have a couple, if I may and guys I'm afraid I'm going stick with Guyana for a second. I think in your Analyst Day last year you suggested that the block, the whole area had a risk resource net to have somewhere in the order of 500 million barrels.

Now I realize that was a theoretical probability of geological success and so on, but, I'm guessing when you announce this – the operator announces a significant discovery, you've de-risked a number of the parameters such as proving a hydrocarbon system trap, fuel migration, all that good stuff.

So I'm just wondering if you could help qualify how you came up with a 500 million number on how this declared success changes the risk profile of that estimate. And I've got a follow up, please..

Yeah, well, Doug, obviously that 500 million barrels was a risk resource estimate at the time. Clearly, this well has helped derisk that. I can't really give you any more guidance than that but it was a very positive result from the well.

The big risk there that we were trying to understand was there a working petroleum system and clearly there is on the block..

Okay.

I guess I'll – I won't pursue it for now but suffice it to say, that 500 million, is that kind of worst case, if you like? A worst case would've been zero I guess, but in terms of – I guess I'm just trying to understand the scale of the prospect backlog of the area is there – have you and your partner kind of figured out what next steps are at this point outside of shooting seismic?.

It's a fair question. The seismic is the next step, Doug, to high grade the block further and then we will then consider further evaluation activities and really you need to look to the operator for further color on this subject..

Okay. I appreciate that, John. My follow up is really more of kind of, I guess it's really more of a challenge question because you've clearly done a tremendous job releasing or securing at least market visibility on the value of the Midstream; by my calculation is about a quarter of your current enterprise value.

Your share price along with the sector has basically gone straight down pretty much since you made that announcement. So this $17 a share thereabouts that, the associated value of that appears to have been somewhat ignored. So my question is now you've got $4 billion more or less of cash on the balance sheet.

How does this share buyback program compete for capital against other drilling opportunities in a $50 oil price environment? And I'll leave it there. Thanks..

Doug, obviously, use of proceeds very fair question.

And obviously, with the very strong liquidity position the company has it's key to remind everyone as we said on our last call after the Midstream joint venture was announced, that our first, second and third priority in use of proceeds will be to preserve the strength of our balance sheet in the current low oil price environment.

We need to maintain our financial strength, it's vital in this low-price environment; we don't know how low it will go and how long it will go.

So that's going to be the first, second and third priority to make sure that we can fund the projects that we have including our projects that are investing in longer-term growth, be it North Malay Basin or Stampede or some the exploration activities that we have that are very disciplined.

Our second effort or priority then would be to provide additional financial flexibility for future growth opportunities should they meet our strategic, economic and liquidity priorities. And we're going to be very disciplined in that regard given the first priority being to preserve the strength of our balance sheet.

And last but not least, we will continue to repurchase stock on a disciplined basis. So I think it's very important for people to understand the key priority in this environment is for us to preserve the strength of our balance sheet..

John, could I push that a little bit? What is the cash balance that you see to meet those objectives before the buyback? Like I say, $4 billion now, is that enough? Is that too much? What's your order of magnitude as to what you need to meet the first two criteria?.

Hey, I guess, Doug, the way we look at it and I'd like to answer it is – so as you know, we remain committed to managing our business to be cash generative over the long term.

So, with this low price oil environment, what have we done? What's the self-help? So, first, we've reduced our capital spend from $5.6 billion in 2014 to $4.4 billion in 2015 and we will further reduce capital in 2016.

And as Greg mentioned earlier, during 2015, our cost reduction efforts have yielded over $600 million of savings and we continue to be focused on reducing costs further. So, there's the self-help that we are doing.

Now, kind of getting to your point, we do have near-term cash flow deficits at these low prices and it is being driven by our spend of approximately $1.4 billion on projects where we're investing for longer-term growth.

So these projects that John mentioned, it's the North Malay Basin, Stampede, it's Tubular Bells on the development side, and in exploration we have capital spending now for the significant discovery at Liza in Guyana and in the Gulf of Mexico at the Sicily prospect.

So as John mentioned now, our advantaged liquidity position with nearly $4 billion of cash post the completion of our Bakken Midstream JV that allows us to fund these growth projects and preserve our top quartile operating capabilities and we're really using that then to position us to capitalize as prices recover when we can then generate free cash flow.

So, that's kind of a combination with what John said and how we are looking at our balance sheet right now..

All right. I'll leave it there, guys. Thank you..

You're next question comes from the line of Roger Read with Wells Fargo. Please proceed..

Hi. Good morning. I guess kind of following along the lines of the uses of capital here. You clearly have one of the best balance sheets in the sector. What does the acquisition front look like? I mean it's been relatively quiet for the industry but historically, this is – double dip in oil prices would tend to accelerate the process.

So I'm just sort of curious, seeing anything more interesting, how does that need to compare versus your growth opportunities and so forth?.

Well you all follow the stock market as do we in terms of some of these prospective opportunities that could potentially fit our strategic needs in our portfolio. The prices of some of those type of opportunities has come down more than the companies with a strong balance sheet as ours, we're looking.

But again, I said before, our first, second and third priority is to keep our financial strength in the current environment that we think will be with us for some time and to come out of this environment strong.

If there is an opportunity that makes financial sense, strategic sense and doesn't impair our balance sheet strength we will be very disciplined in evaluating it. Obviously, we have not found anything to date..

And any help you can give us on how you would think about the returns of an acquisition versus the returns of drilling? Do they need to be equivalent, one better than the other? Just any further clarity there..

We will always invest for returns, and it will have to be competitive with our alternatives..

Okay. That's it for me. Thank you..

And your next question comes from the line of Ed Westlake with Credit Suisse. Please proceed..

Yes. Good morning. I'm just trying to reconcile your improvements in operational performance and then the CapEx that's unchanged. I mean obviously, the Bakken wells seem to have come in a little bit below your guidance.

I mean, you're still drilling an 8 rig program and I noticed that the Utica wells are also – I mean, well done for getting the costs down dramatically in the Utica.

So maybe talk through why that perhaps isn't showing up in a sort of a CapEx reduction for this year?.

Yeah, Ed, if you think about it, we're basically maintaining an 8 rig program. So as we continue to gain efficiencies in our spud-to-spud, days between spud now is about 18 days. So what that means is that you drill more wells in the year than what you planned. So effectively that CapEx is consumed by continuing that 8 rig program..

Right.

But the implication might be next year there would be some lower CapEx from these savings, as well as the timing of other projects?.

Yeah. I think that's a reasonable assumption..

And then, you know, there was a bit of a debate on I think the full FY call about continuing to drill in South Arne and Valhall where perhaps as long as the reservoirs aren't damaged in terms of pressure management, maybe there's a little bit more flexibility say, oil prices were low and you came back and said, well look the economics still works so we're going to carry on doing them.

I'm just wondering as the prices have wallowed around at this current level whether anything has changed there in terms of CapEx planning for next year?.

I think again, we haven't given our 2015 guidance. But certainly for this year, we're contracted four rig in South Arne and we'll continue to execute that program. It's generating very good returns in South Arne well above our cost of capital. Similarly in Valhall, recall though that we did shut down the IP drilling rig in Valhall this year.

So we've got one rig out and then we have the remaining drilling is with a jackup there. Again, a contracted jackup rig and we're continuing that program..

Okay. Thanks very much..

Uh huh..

And your next question comes from the line of Paul Sankey with Wolfe Research. Please proceed..

Thank you. Good morning. Firstly on cash flow for the quarter, can you just help me get as close as I can to what you think the ongoing cash generation, what the business will be at $60 oil and how representative this quarter was of the ongoing cash flow that you think you'll make at that kind of price level? Thanks..

I mean, if you get $60 oil, obviously you're going to have higher cash flows for our business because we've got a significant amount of oil production, so I mean it's difficult. I would tell you overall when you look at Hess because of our oily portfolio a $1 change in oil prices does increase our cash flows by a little over $70 million.

So, that's the kind of sensitivity you can look at from our portfolio and flex on different oil prices..

Thank you. And what should I consider to be the clean operating cash flow for this quarter, Q2, I think there's some – likely some disproportions in the working capital. Thanks..

Sure. Yeah, so there was $170 million reduction in the cash flow from working capital. So, if you add that back in you get $711 million of cash flow from operations and that's up 51% from the first quarter reflecting the improved oil prices in the second quarter..

Yes and John you guided that essentially next year's CapEx will be lower, I guess assuming that we're at this kind of oil price level?.

Yeah..

So you're not obviously going to say more about the kind of level we should think about? I'm just wondering how long a cash deficit can be run given what you've also said about the importance of the balance sheet?.

Yes. So I mean, again it will be lower. I mean, we'll have to work with our partners and we'll see what prices are as we get into 2016. But as I mentioned, we will be funding these growth projects that we have, so North Malay Basin and Stampede will continue. We will be working with Exxon with spending in Guyana and Chevron on Sicily.

So we have these growth projects to fund. Now, we've got nearly $4 billion with the post the completion of the Bakken Midstream JV, so we're in a great position to be able to fund these growth projects and position us to generate free cash flow as oil prices recover..

Understood. Thank you. One area of potential cost savings would be to merge with another company. Have you considered that particularly in the Bakken? Thank you..

Obviously, we don't comment on such matters. And you know that, Paul..

Just checking, John. Thank you..

And your next question comes from the line of Ryan Todd with Deutsche. Please proceed..

Great. Thanks. Good morning. Maybe if I could follow up on – one more question on CapEx. You've talked in the past about kind of a run rate from the fourth quarter on of $950 million, I think.

Is that still a good number or is the cost savings that you're seeing potentially driving that a little bit lower? Any updates on kind of the pro forma run rate as you're stabilized in the eight rig program?.

Yeah. Again, it's still early for us. We'll be looking obviously at oil prices. We have to work with partners on what we're doing in the partnerships that we have for the fields.

So it's just at this point right now we don't want to be more specific than what I said that we do have $4.4 billion this year, 2016's capital will be lower than that $4.4 billion and we will be looking at everything from the CapEx side as well as on the OpEx side because we're going to be continued to be focused on costs in this low price environment..

Great. Thanks, and then maybe one follow-up on the Bakken.

I guess could you talk, and I dropped off the call unfortunately for a little bit so I'm not sure if you addressed it, but can you talk a little bit of the production which continues to exceed expectations, can you talk – is that more of a function of a quicker pace of drilling than you had expected previously? Is it well performance? Maybe a little bit on what you're seeing on well performance and then finally in terms of the production mix between oil, NGL and gas, what's kind of a right place do you think for us to kind of stabilize that going forward?.

Yeah. So, if you look at the difference between Q1 and Q2 in the Bakken, we did have an increase of about 11,000 barrels a day. There were really three factors associated with that. The first was we had a high number of new wells online in the second quarter. So, we had 67 wells online.

The second factor was we had a 2% increase in the production availability. So, the operations guys have been doing a great job getting the reliability and availability up. And the third factor was we had increased gas capture at Tioga. Obviously, both our own volumes as our own volumes went up, but also third-party volumes as well..

And then just from a product mix standpoint for the 119,000 barrels a day in the quarter, about 85,000 barrels a day were oil or 71% of it. 22,000 barrels a day were NGLs so 19%, and then gas was 71 million SCFs per day or about 10% of the BOE..

And is that a good kind of mix to think about going forward or, we've seen.....

Yeah, I think....

Okay..

I think that is a reasonable mix. I mean you're getting now the ramp up of the Tioga gas plant so we've had some changes as that's moved on. So if you looked at the average for 2014 we were up at – we only had 12% of NGLs and 8% gas so now you're beginning to see some of the uplift from the Tioga gas plant..

Okay. Great. Thank you..

Your next question comes from the line of Brian Singer with Goldman Sachs. Please proceed..

Thank you. Good morning..

Good morning..

You've spoken a lot here on the sharp reduction that you've seen in your Bakken well costs.

Can you also talk to what you're doing on the technology front if the type of well you're drilling has changed at all? And can you talk to any changes you are seeing in well productivity?.

I think our well design has not changed. So again, it's a typical 35-stage sliding sleeve completion in the Bakken, that hasn't changed. Proppant loading of 70,000 to 100,000 pounds per stage depending upon the area. In terms of technology, we've got some 50-stage trials under our belt, so 50-stage sliding sleeve, those trials have gone well.

So once we get a few more in the ground and are convinced of the reliability of the completion system we'll be evaluating whether or not we switch to that as a value-accretive improvement to the Bakken completions. We've tried some slickwater fracs. We do not see that those add enough incremental to value to justify the additional costs.

We've tried some higher proppant loadings and really kind of the same conclusion. It doesn't generate enough incremental value. And I guess the final thing is we are, as you know, experimenting with a tighter infills, nine and eight spacing pilots. We've got about 38 wells online now in that configuration.

Now, only 13 of these wells have been online for more than 90 days. I will say the initial results are encouraging but it's still early days. I'd like to get more wells in the ground and on production before we draw any final conclusions for that.

And so we expect to be in a position by year-end or early first quarter to provide some color on some results on that nine and eight infill..

Great. Thank you. And then your backlog in the Bakken has been coming down based on the number of completed versus drilled wells.

Do you anticipate building backlog in the second half, drawing backlog or holding flat?.

No, we don't. We're pretty much at our rhythm bin size now, which is about 25 to 30 wells at any given moment that are uncompleted and we would expect to carry that level of wells into next year. But that's about as low as it can go..

Great. Thank you..

Your next question comes from the line of Paul Cheng with Barclays. Please proceed..

Hi, guys. Good morning..

Good morning..

A number of quick questions. This is for John Rielly. John, when I'm looking at your international operation, if I strip out the special item and also then strip out the estimate on the FX, the hedging impact, you will report somewhere around the pre-tax profit of $34 million and you have a tax credit of $38 million.

I'm trying to reconcile that, why that you have a profit then, then you will have a tax credit in your international operation?.

Yeah. Sure, Paul. It's – there's – once you get into this law of small numbers, you get into these strange tax rates. There's really nothing unusual. We have some small credits and I'll walk you through an example.

We have small credits sitting on in the international side and some small, kind of call it debits on the other side, for an overall rate that came in, as you know, at the above guidance on that benefit side.

So what happens is this is just a simple example, if you have a loss in Norway of $10 and you have an income in JDA of $10, you put those two together and you have $0 income. But Norway has gotten 80% tax rate, so you're booking an $8 benefit on Norway and JDA has a 10% rate, so you're only booking $1. So you get a benefit of $7 on $0 income.

It's that mix of income that's causing the strange numbers in international..

I see. Okay. On the cash flow, if your DD&A is about $1 billion, your net loss excluding the special items is about $147 million, it seems to suggest that your cash flow from operations should be higher than even after you adjust for the working capital.

Is there any other items that – it seems like there's another $100 million, $150 million that is more than your cash flow, are those item, is going to be repeatable in the future?.

Your math is very good, Paul, as usual. What it is, is because where we're in the losses right now, and I think we've given guidance on that, is that the majority of the tax benefit is deferred. So, you've got a benefit sitting against that loss and that was the one number I didn't hear you say. That was reducing it then down to the $711 million.

Now, it's obviously going to depend on prices and what happens here going forward. I mean, it's the same guidance that I've been giving. In the U.S. and in Norway, we're not paying cash taxes and won't be for five years and potentially longer if these prices stay lower.

So, it all depends on where the profit is but if we stay in a loss position, we will continue to have that deferred tax benefit..

I see. And maybe this is for John Hess.

I assume that you will complete the IPO for the Bakken MLP? If that decision has been made that the cash proceeds – who is going to keep it? Is it going to be split between the joint venture partner or it would be kept inside the MLP?.

So, when the IPO is done, and the proceeds, the proceeds will go to the partners of the JV, that's basically the way that we're looking at. Nothing's been finally decided but that's how it would be – it would be split between the two partners, the 50/50 partners..

John, I think there are a lot of people who ask about the CapEx, maybe if I could, maybe looking at it slightly different. If I look at to maintain your current asset mix, and that the production is flat and taking into consideration of your commitment in the major growth project that you already commit.

What is the minimum CapEx that we need for next year?.

So, what we've been, I guess, talk about with the growth projects that we have. So, we've got a $4.4 billion of budget this year. It includes, so I'm going to add a little bit more because we had some other growth capital in 2015, so we have about a $1.6 billion of investment in offshore development say, an exploration.

So, when you subtract it from the total, we've got about $3 billion, under $3 billion, to maintain kind of current production levels. So, you do have this North Malay Basin and Stampede going into next year and the thing that I can't talk about right now is what happens in Guyana, what happens in Sicily.

So, again, I think the best I can do right now is to say the guidance will be below $4.4 billion but we just can't tell you what that number....

Yeah. And I think another perspective obviously, Paul, as the entire industry is running deficits, all the oil producers of the world are running deficits. And depending upon how low oil prices go and how long they go for, obviously that will figure in our calculus as well about how far we reduce our CapEx program next year.

We have further flexibility to reduce in the Bakken and Utica and we also have flexibility to reduce in our offshore if it's appropriate. We are going to invest for returns, but we also intend to be cash generative over the medium term. So, it's a balance.

Good returns, but if the money is not there, we will reduce our CapEx even further and that's going to be an iterative process between now and the end of the year. And when we finalize our program, obviously, we'll communicate that to the investors out there..

Great. Great. Final question is for Greg.

Greg, is there any data you can share about the two discoveries in Guyana and in the Gulf of Mexico, Sicily, in terms of the pay zone whether that those is primary black oil, condensate gas, any kind of information you could provide on those two discoveries?.

They're both black oil based on what we know right now. On the Sicily discovery in the Gulf of Mexico, it's lower tertiary. And in Guyana, it's a crustaceous play that we're currently looking at right now..

Do you have the – how thick is the pay zone or that kind of information?.

Yeah. In Guyana, we can't give that information yet. On Sicily, you'll have to ask the operator about that. But consistent with Exxon's press release in May in Guyana, the well encountered more than 295 feet of high-quality oil-bearing sandstone reservoir. So, you do have a net pay zone that..

Okay. Thank you..

Your question comes from the line of Jeffrey Campbell with Tuohy Brothers. Please proceed..

Good morning. First, I'd like to return to the subject of the pilot tests.

First question is how widespread are the tests across your acreage? And then following up, if they prove successful what sort of uplift to drilling locations might be possible?.

Yeah. So, they're spread out, but because we're concentrating in the core of the core, they're primarily in the core of the Bakken. So, it's spread out over 14 DSUs, and in those 14 DSUs this year we plan to get 82 pilot wells in the ground. Now as I mentioned, 38 of those are currently online and, but only 13 have been online more than 90 days.

And as I said, the initial results are very encouraging but it's still early days. I want to get a lot more wells in the ground before I make a final decision on that hopefully by year-end, early in the first quarter we'll be in a position to make that decision.

Obviously, if you do go to a nine and eight configuration, it won't apply across the entire field but it will obviously increase your well locations for the Bakken..

Right. And importantly it increases your best well locations..

Yes..

My second question was if commodity prices remained depressed in 2016, will you continue to concentrate Utica drilling in Harrison County or do you have any requirements to hold acreage elsewhere that would require you to drill in another county in 2016?.

It's on the margins. There isn't any significant HBP requirement so obviously if prices do continue where they are, we're going to continue in Harrison County and why do we do that because that's truly the sweet spot of the play. It's the wettest part of the play and it also has a 95% net revenue interest as well on that acreage.

So obviously that helps the economics..

Okay great. And my last question is, I haven't heard too much about Ghana and the discussion of the portfolio.

Is there any update on the Ghana timeline particularly now that you've got a partner there?.

No, there's not. I mean we're just continuing all of the technical studies on Ghana. We're also going through FEED processes, et cetera.

And we're in discussions with the Ghanaian government to understand how the border dispute and the ongoing international law, the Sea Treaty proceedings are going on the block, and how that might affect progress on the block.

But we're committed to advancing the work to the extent feasible, including all those technical studies and pursuing appropriate commercial agreements. One thing we can't do is we can't get a drilling rig or a seismic vessel out there in the disputed area. So, it's pretty much technical studies..

Okay. Great. Thanks very much..

Yeah..

Your next question comes from the line of Pavel Molchanov with Raymond James. Please proceed..

Hi. Thanks for taking the question. I have two quick ones in relation to Bakken Midstream, if I may? You were talking about at the beginning of the year an IPO sometime in 2015.

Is that still the targeted timetable for taking this public?.

Unfortunately, Pavel, we're in a quiet period right now, so I can't give you anything specific. So it's going to depend just on the SEC review and market conditions for the timing of the IPO..

All right, all right, fair enough.

And for Hess to remain the operator of the joint venture is there a minimum economic interest that you have to maintain?.

Yes, there is a minimum economic interest. Yeah, so we would have to drop down though considerably before that would happen..

To be clear, our intent is to control and operate the venture. So, let's be clear on that..

Okay. What is that percentage? Just to clarify..

I think as I said before, our intent is to control and operate the venture. I wouldn't want to speculate otherwise..

Appreciate it..

And your last question comes from the line of Guy Baber with Simmons. Please proceed..

Thanks for fitting me in here and congratulations on another strong quarter..

Thank you. Thanks for hanging in there on the phone call..

Just one strategic question for me. But understanding maintaining financial strength is priority is number one, I was just hoping to press for a bit more color on the potential to add a resource and flexibility via bottom of the cycle acquisition. You've mentioned that meeting strategic objectives, it would be key for you in doing that.

Could you just elaborate on what those strategic objectives are and I'm not sure if you can be specific or not, but any updated thoughts around long-term portfolio mix? Whether you have a desire for more onshore versus offshore or U.S.

versus international or whether you're agnostic on those fronts? Any strategic color on that front would be very helpful. Thanks..

Obviously, we're always looking to upgrade our portfolio. So anything would have to strengthen our portfolio strategically, economically, in terms of providing profitable and visible resource growth. As we look out there, we see our mix thing roughly half unconventionals, half conventional, half onshore, half offshore, half-U.S., half international.

Obviously, it's a dynamic market and we'll be very disciplined about any opportunities that we consider; but commenting further than that would be pure speculation and we don't want to do that. The key is we're going to be disciplined.

And again, our top priority is to maintain our financial strength in a low-price environment because it may be with us for some time..

Thanks for that..

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