Jay Wilson - Vice President Investor Relations John Hess - Chief Executive Officer Gregory Hill - Chief Operating Officer John Rielly - Chief Financial Officer

Arun Jayaram - JPMorgan Doug Leggate - Bank of America Brian Singer - Goldman Sachs Ed Westlake - Credit Suisse Guy Baber - Simmons Doug Terreson - Evercore ISI Paul Cheng - Barclays Paul Sankey - Wolfe Research Ryan Todd - Deutsche Bank David Heikkinen - Heikkinen Energy Jeffrey Campbell - Touhy Brothers

Good day ladies and gentlemen, and welcome to the Fourth Quarter 2016 Hess Corporation Conference Call. My name is Nicole and I'll I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President Investor Relations. Please proceed.

Thank you, Nicole. Good morning, everyone, and thank you for participating in our fourth 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 fourth quarter conference call. I’ll review highlights from 2016 and plans for 2017. Greg Hill, will then discuss our operating performance and John Rielly, will review our financial results. First, I would like to share our view of the oil market, particularly in light of the recent OPEC agreement. We are entering a new chapter in oil prices. After two years of a lower for longer price environment global investment in exploration and production has been severely curtailed, nearly in half from approximately $700 billion in 2014 to $380 billion last year. While 2017 should see modestly higher investment than 2016, we believe this level of spend will not be enough to bring forward the necessary production over the next several years to meet future oil demand growth and offset production declines globally. We see continued strong demand coupled with the anticipated reduced supply resulting from OPEC and non-OPEC supply cuts and natural field declines, more than offsetting increased U.S. shale oil production, leading to higher oil prices this year and into 2018. Our company is extremely well positioned for this improving price environment. We have a decade or more of visible reserve and production growth and our continued focus on operational excellence and financial discipline is driving improving returns and lower costs across our portfolio. Our visible growth trajectory is underpinned by four key areas; the Bakken, where we have a leadership position and we’ll go from two rigs to six rigs over the course of 2017. Two offshore developments North Malay Basin and Stampede, which are expected to contribute significant production and cash flow when they come online in 2017 and 2018 respectively. And the world-class Liza and recent Payara oil discoveries in Guyana. With sanction of the first phase of the Liza development expected mid-year and continuing appraisal and development activities underway. In 2017, we will continue to be disciplined in investing in our growth projects, while maintaining a strong balance sheet and liquidity position. On January 12, we announced 2017 capital and exploratory budget of $2.25 billion. About 70% of our 2017 budget is allocated to our four major growth areas. With activity increasing in 2017, our focus will be on execution. In terms of safety, cost control, project delivery and working with our partners to advance our discoveries in Guyana to development. Now turning to our 2016 financial results, our adjusted net loss was $1.5 billion and cash flow from operations before changes in working capital was $840 million. Compared to 2015, our financial results were negatively impacted by lower crude oil and natural gas sales volumes and selling prices, which more than offset the positive impacts of lower operating costs and DD&A expense. From an operational standpoint, while we reduced activity across our producing portfolio in 2016, our team has much to be proud of. Driving operational efficiencies across our portfolio, delivering reductions in capital expenditures and cash operating cost, progressing our offshore developments and achieving major success with our focused exploration program. In 2016, full year net production was 321,000 barrels of oil equivalent per day excluding Libya. In 2017, our production is forecast to average between 300,000 and 310,000 barrels of oil equivalent per day excluding Libya. It is important to note that first quarter 2017 production is expected to increase in excess of 10% from first quarter levels. Driven by the startup of North Malay Basin in the third quarter, increased activity levels in the Bakken and the restart of drilling at the Valhall Field in Norway, all of which builds momentum and positions the company for strong production growth in 2018. At year-end 2016, our proved reserves stood at 1.1billion barrels of oil equivalent and our reserve life was 9.2 years. We were placed 119% of production in 2016 and an SG&A cost of approximately $13 per barrel of oil equivalent. Now turning to the Bakken, Hess has one of the highest quality acreage positions in the play, with more future drilling locations in the quarter than any other operator and an advantage infrastructure position. Through our application of lean manufacturing techniques, our Bakken team has achieved among the lowest drilling and completion costs and most productive wells in the basin, offering very attractive financial returns. Bakken production in 2016 averaged 105,000 barrels of oil equivalent per day, reflecting our reduced drilling program. Bakken production in 2017 is forecast to average between 95,000 and 105,000 barrels of oil equivalent per day. With the increased activity in the Bakken and the improvement in the MLP market, Hess infrastructure partners is preparing for an initial public offering LP common units in 2017. Turning to our offshore developments, Full-field development of North Malay Basin in the Gulf of Thailand is on track to achieve first production in the third quarter of 2017. The Stampede development in the deep water Gulf of Mexico is progressing and remains on schedule for first oil in 2018. Together they’re expected to add a combined 35,000 barrels of oil equivalent per day in transition from being sizable cash users to significant long-term cash generators for the company. With regard to Guyana, we are excited about the significant resource potential on the 6.6 million acres Stabroek Block. The Liza-3 well result last October, confirmed Liza as one of the industry’s largest oil discoveries in the last 10 years, with estimated recoverable resources of more than 1 billion barrels of oil equivalent. We expect to be in a position to sanction the first phase of development in 2017, with production expected in 2020. This month Payara-1 well confirmed a second significant oil discovery with the same high quality reservoir. Payara and an additional deeper reservoir identified directly below the Liza field are accretive to the estimated recoverable resources already confirmed at Liza and further demonstrate the prospectivity of the Stabroek Block. The Stabroek Block offers very attractive economics and will be very material for our company. The Liza and Payara oil discoveries underpin a large discovered resource on the block that has significant upside in terms of appraisal and future exploration potential. The reservoir quality is world-class with high-porosity and permeability. The wells can be drilled in a third to a half of the time and cost of those in the deepwater Gulf of Mexico and we are entering the development phase at what will likely be the bottom of the offshore cost cycle. In summary, we are well positioned to deliver visible and sustainable growth and value to our shareholders. We are increasing activity in the Bakken, which will bring growth back into our onshore portfolio and support a potential IPO of the midstream business to unlock additional value. Offshore, our developments in the Gulf of Thailand and the deepwater Gulf of Mexico are poised to add significant volumes and become long-term cash generators. And in Guyana, the Liza field is one of the industry’s largest oil discoveries of the last ten years, which we and our partners will continue to appraise and progress toward development. Overall, we see 2017 as the start of an exciting new chapter of value driven growth and increasing production momentum for our company and our shareholders. I’ll now turn the call over to Greg for an operational update.

Thanks John. I’d like to provide an operational update for 2016 and review our plans for 2017. Clearly the past year was challenging in terms of oil prices and we responded by reducing our capital spend and operating cost. Last year was also marked by strong execution on many fronts including the continued advancement of our North Malay Basin and Stampede developments and exceptional exploration results in Guyana, firmly establishing a new world-class oil province. With regard to production, in 2016 we averaged 321,000 barrels of oil equivalent per day excluding Libya. In the fourth quarter, production averaged 307,000 barrels of oil equivalent per day excluding Libya, which was above our guidance of 305,000 barrels of oil equivalent per day. During the quarter, production from Libya resumed and on a net basis averaged 4,000 barrels per day in the fourth quarter. Production from Libya remains highly uncertain therefore we’ll continue to exclude it from our guidance. As John mentioned, in 2016 we achieved a reserve replacement ratio of 119% and SG&A cost of $13 per barrel of oil equivalent. Net proved reserve additions totaled 143 million barrels of oil equivalent. About half of the additions were in the Bakken, reflecting higher EURs associated with their shift to 50-stage completions and lower cost. Other areas with additions include North Malay Basin, South Arne and the Utica. In 2017, we forecast companywide production to average between 300,000 to 310,000 barrels of oil equivalent per day. Our production has been decreasing over the last several quarters as a result of reducing our capital expenditures to manage in the lower price environment. Our production will continue to decline in the first half of 2017 as a result of this reduced spend and a high level of planned maintenance at four of our offshore assets in the second quarter. We forecast production to average between 290,000 and 300,000 barrels of oil equivalent per day in the first quarter and between 270,000 and 280,000 barrels per day in the second quarter. Production is in forecast to increase in the third quarter with the start-up of North Malay Basin to between 305,000 and 315,000 barrels of oil equivalent per day. Production will continue to grow in the fourth quarter as Bakken production increases as a result of the rig ramp up and the first new Valhall well comes online. Fourth quarter production is forecast to average between 330,000 to 340,000 barrels of oil equivalent per day, resulting in production growth in excess of 10% or some 40,000 barrels per day from the first to the fourth quarter of 2017. Turning to operations, the Bakken continues to deliver outstanding results. We continue to improve our drilling and completion performance with fourth quarter D&C cost dropping 10% versus the year ago quarter to $4.6 million. We now have enough production history to conclude that we will get an average 13% uplift in EUR per well from our 50-stage completions compared to our previous estimate of 7%.As a result, we’ve increased our estimate of ultimate recovery from our Bakken acreage to 1.7 billion barrels of oil equivalent from our previous estimate of 1.6 billion barrels of oil equivalent. In the fourth quarter, initial production rates for wells that reached IP30 during the quarter averaged a record 1,091barrels of oil per day versus 843 barrels of oil per day in the third quarter. This result reflects all wells during the quarter being 50-stage completions and in the core of the core of our acreage. Going forward we will shift our guidance to IP90 rates which we feel are more reflective of a well’s actual performance. In 2017, we forecast IP90s to average between 700 and 750 barrels of oil per day compared to 620 barrels of oil per day in 2016. Net production from the Bakken averaged 105,000 barrels of oil equivalent per day in 2016, which was at the top end of our beginning of the year guidance range of 95,000 to 105,000 barrels of oil equivalent per day. In the fourth quarter, net production averaged 95,000 barrels of oil equivalent per day, which was below guidance due to extreme winter weather which resulted in road closures and an unusually high number of shutting facilities and wells. The net negative impact of weather in the fourth quarter on the Bakken was about 7000 barrels of oil per day. With the recovery in oil prices to the mid-50s, we plan to increase our rig count from the two rigs we currently have operating to six rigs by the end of this year and expect our rig count to average approximately 3.5 for the year. In 2017, we plan to drill approximately 80 wells and bring approximately 75 new wells online over the year. We will continue to focus our drilling in the core of our Bakken acreage where our sliding sleeve completions, site spacing and higher stage counts deliver optimal value. Of the 75 wells we plan to bring on line this year, approximately 50 wells will be our new standard 50-stage design and we expect the D&C cost for these wells to be in line with the 4.8 million that we averaged in 2016. We will also be conducting two new completion design pilots this year in our drive to continually optimize the value of our industry-leading acreage position. The first pilot will be increasing the stage count to 60 from the standard 50-stage design. We plan to test this in 10 wells to ensure the reliability of the system and our forecasting well costs in these 10 wells to range between $5 million and $5.5 million. The second pilot will involve higher proppant loading. The 60-stage sliding sleeve may be approaching the technical limit and mechanical design. Therefore, we now want to test the technical limit on proppant loading in a sliding sleeve well. We plan to increase proppant loading in 15, 50-stage wells and forecast these wells to cost in the range of $5.5 million to $6 million dollars. For both of these trials, reservoir stimulation indicates a potential IP180 uplift of 10% to 15%. If successful, our future development plans and production outlook for the Bakken will be modified accordingly in 2018. The extreme winter weather conditions have persisted throughout the month of January and as a result we forecast production in the first quarter of 2017 to average between 90,000 and 95,000 barrels of oil equivalent per day. For the full-year of 2017, we forecast our Bakken production to average between 95,000 and 105,000 barrels of oil equivalent per day. With the building rig count, we expect our Bakken production to average between 105,000 and 110,000 barrels of oil equivalent per day during the fourth quarter of 2017, which would represent a growth rate of approximately 15% from the first quarter to the fourth quarter of 2017. Moving to the Utica, in 2016 net production averaged 29,000 barrels of oil equivalent per day compared to 24,000 barrels of oil equivalent per day in 2015. In the fourth quarter, net production averaged 26,000 barrels of oil equivalent per day. As a result of continued wide basin differentials, we intend to maintain our drilling pause in the Utica. In 2017, production is forecast to average between 15,000 and 20,000 barrels of oil equivalent per day. However, given the high quality of our Utica acreage position, our high average net revenue interest of 95%, as well as the first quarter well performance that we delivered in 2016, the asset will be an excellent resource to develop as natural gas and NGL price realizations improve. Now turning to the offshore, in the deepwater Gulf of Mexico, net production averaged 61,000 barrels of oil equivalent per day in both the fourth quarter and for the full-year 2016. We forecast Gulf of Mexico production to average approximately 65,000 barrels of oil equivalent per day in 2017 and to reach approximately 75,000 barrels of oil equivalent per day in the fourth quarter of 2017. This production growth reflects the addition of a new well and the restart of an existing well following a work over at the Tubular Bells field in the first quarter. A restart of a well at the Conger field also following a work over and a planned new well at the Penn State field, which will come online in the second half of this year. In Norway, at the Aker BP-operated Valhall field in which Hess has 64% interest, production averaged 28,000 barrels of oil equivalent per day in 2016 and 32,000 barrels of oil equivalent per day in the fourth quarter. The transition from BP to Aker BP-operatorship was completed in the fourth quarter and we're looking forward to working together with the new operator to maximize the value of the Valhall asset. Drilling from existing platform rig is planned to resume in March. In 2017, net production is expected to average between 25,000 and 30,000 barrels of oil equivalent per day. At the South Arne field in Denmark, which Hess operates with a 61.5% interest, net production averaged 13,000 barrels of oil equivalent per day in 2016 and 14,000 barrels of oil equivalent per day in the fourth quarter. The field is expected to average approximately 12,000 barrels of oil equivalent per day in 2017. In the fourth quarter, the Danish government awarded an extension of the South Arne license through to 2047. This secures the long-term future of this asset and provides for future phases of development. In Equatorial Guinea where Hess is operator with an 85% interest, net production averaged 32,000 barrels of oil equivalent per day in 2016, reflecting the drilling pause in place since mid-2015. Net production in 2017 is forecast to average approximately 25,000 barrels of oil equivalent per day. Interpretation of the latest 40 survey has been completed and has identified multiple new targets. However, the production outlook for 2017 reflects continuation of the drilling pause over the year. At the Malaysia-Thailand joint development area in the Gulf of Thailand in which Hess has a 50% interest, net production averaged 35,000 barrels of oil equivalent per day in the fourth quarter. Net production averaged 34,000 barrels of oil equivalent per day in 2016 and is expected to average approximately 35,000 barrels of oil equivalent per day in 2017. No further drilling activity will be required to meet contracted volumes for the year as a result of the booster compression project that was completed in the third quarter of 2016. Moving now to our development projects, at North Malay Basin in the Gulf of Thailand in which Hess holds a 50% interest and is operator, three remote wellhead platforms were hooked up and commissioned in the fourth quarter. The drilling campaign is on schedule with two wells being drilled in the fourth quarter bringing the total number of wells drilled so far to 13. All wells have either met or exceeded pre-drill expectations. The last heavy lift for the central processing platform topsides is completed and sail away is scheduled for the first quarter of 2017. Net production through the early production system averaged approximately 26 million cubic feet per day over 2016. Once full field development is completed in the third quarter of this year, we forecast net production to increase to approximately 165 million cubic feet per day and to remain at this rate for many years, becoming a significant cash generator for the company. At the Stampede development in the Gulf of Mexico in which Hess as a 25% working interest and is operator, we successfully completed installation of subsea equipment at both drill centers and completed all topsides heavy lift on to the hall. Looking forward, in 2017 we will install the TLP and topsides on location, complete the subsea installation, and continue our drilling program. First oil remains on target for 2018. Turning to Guyana, exploration and appraisal drilling activity continues at the 6.6 million acres Stabroek block in which Hess holds a 30% interest. As announced earlier this month, the Payara-1 well located approximately 10 miles northwest of Liza discovery, was drilled by the operator Esso Exploration and Production Guyana Limited to a depth of 18,080 feet and encountered more than 95 feet of high quality multi-Darcy permeability, oil bearing sandstone reservoirs. Two sidetracks were subsequently drilled to take core and further evaluate the reservoir. Both sidetracks found high quality oil bearing sands. The original well and the two sidetracks were drilled, logged and cored in 56 days. A production test is now planned to further evaluate the reservoir. Appraisal drilling is planned later this year to help define the full resource potential of the Payara discovery. After completing the well test on Payara-1, the rig will move to drill the Snoek exploration prospect, which is located approximately six miles south of the Liza-1 discovery well. The next well in queue is Liza-4 appraisal well, which will pass the eastern part at Liza field. This will be followed by a Payara-2 appraisal well. Earlier this month, we announced that the Liza-3 appraisal well, which reached target depth in the fourth quarter, identified an additional high quality deeper reservoir directly below the Liza field, which is estimated to contain recoverable reserves between 100 million and 150 million barrels of oil equivalent. This additional resource is expected to be developed in conjunction with the Liza discovery. The operator plans to continue to appraise the Liza and Payara discoveries are in parallel continuing to evaluate the wider resource potential of the Stabroek block for additional exploration drilling and seismic analysis over 2017. In closing, in 2016 we once again demonstrated strong execution performance and took proactive steps to manage through the weak oil price environment by significantly reducing our capital span and operating costs while continuing to progress our future growth options. I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2016 to the third quarter of 2016. The corporation incurred a net loss of $4.892 million in the fourth quarter of 2016 compared with a net loss of $339 million in the third quarter. The largest driver for the loss in the fourth quarter was a non-cash accounting charge of $3.75 billion on net deferred tax assets in the U.S. Denmark and Malaysia. This non-cash adjustment is required under accounting standards following a three-year cumulative loss. The deferred tax charge has no cash flow or economic impact. The company's underlying tax position remains unchanged. Beginning in 2017, our financial results will not recognize a deferred tax benefit or expense in these three countries until the deferred tax assets are reestablished. Our guidance for 2017 includes the anticipated impact of this charge, which will result in a lower effective tax rate going forward. Fourth quarter results also included an after-tax charge of $693 million to fully impair the carrying value of our natural gas project offshore the North West Shelf of Australia as a result of our decision to defer further development, so we can allocate capital to other projects that generate higher returns including the Bakken and Guyana. Other after-tax charges totaling $145 million were recognized for exit costs for an offshore drilling rig, loss on debt extinguishment, impairment of older specification rail cars, severance and surplus materials and supplies inventory. Excluding items affecting the comparability of earnings between periods, our adjusted net loss was $305 million in the fourth quarter of 2016, compared with an adjusted net loss of $340 million in the third quarter. Turning E&P on an adjusted basis, E&P incurred a net loss of $257 million in the fourth quarter of 2016, compared to a net loss of $285 million in the third quarter of 2016. The changes in the after-tax components of adjusted results for E&P between the fourth quarter and the third quarter of 2016 were as follows. Higher realized selling prices improved results by $37 million. Lower sales volumes reduced results by $23 million. Lower DD&A expense improved results by $29 million. All other items reduced results by $15 million for an overall decrease in fourth quarter net loss of $28 million. In the fourth quarter, our E&P operations were over lifted compared with production by approximately 300,000 barrels, which did not have a material impact on fourth quarter results. The E&P effective income tax rate, excluding items affecting comparability, was a benefit of 43% in the fourth quarter of 2016, compared with a benefit of 41% in the third quarter. Turning to midstream, the Bakken midstream segment had net income of $3 million in the fourth quarter, compared to $13 million in the third quarter. Higher revenues in the fourth quarter reflect a recognition of deferred minimum volume deficiency payments that were partly offset by lower throughput volumes caused by severe weather in North Dakota. Fourth quarter results also include a pre-tax charge of $67 million or $21 million after taxes and the 50% non-controlling interest to impair older specification railcars. EBITDA for the Bakken midstream before the non-controlling interest, amounted to $99 million in the fourth quarter of 2016, compared to $73 million in the third quarter. Starting January 1st, 2017, our midstream segment now includes the company's interest in the Permian gas plant in West Texas and related CO2 assets and our North Dakota water handling assets, which principally consists of gathering infrastructure. These assets are wholly-owned by the company and are not included in our Hess Infrastructure Partners joint venture. Turning to corporate, after-tax corporate and interest expenses, excluding items affecting comparability, were $72 million in the fourth quarter of 2016, compared to $68 million in the third quarter. Turning to cash flow for the fourth quarter, net cash provided by operating activities before changes in working capital was $128 million. The net increase in cash resulting from changes in working capital was $198 million. Additions to property, plant, and equipment were $487 million. Net repayments of debt were $592 million. Common and preferred stock dividends paid were $90 million. All other items resulted in an increasing cash of $46 million resulting in a net decrease in cash and cash equivalents in the fourth quarter of $797 million. Fourth quarter cash flow from operations before changes in working capital of $128 million reflects a reduction of approximately $200 million associated with the charges for rig exit costs, severance, and surplus inventory and higher well work over costs in the quarter. Turning to cash and liquidity, excluding the Bakken midstream, we ended 2016 with cash and cash equivalent of $2.7 billion, total liquidity of $7.3 billion, including available committed credit facilities and total debt of $6.73 billion. Turning to guidance, first with E&P, we project cash costs for E&P operations to be in the range of $16 to $17 per barrel of oil equivalent in the first quarter of 2017, and $15 to $16 per barrel for the full year of 2017 as compared to 2016 cash costs of $15.87 per barrel. Full-year cash costs per barrel are lower than the first quarter, reflecting the startup of North Malay Basin project in the third quarter and increasing production from the Bakken in the second half of 2017. DD&A per barrel of oil equivalent for the first quarter of 2017 is forecast to be $25.50 to $26.50 and $24 to $25 for the full year of 2017, down from 2016 DD&A of $26.57 per barrel. This results in projected total E&P unit operating costs of $41.50 to $43.50 per barrel in the first quarter of 2017, and $39 to $41 per barrel for the full year of 2017, down from 2016 E&P unit operating costs of $42.44 per barrel. Exploration expenses, excluding dry holes, are expected to be in the range of $65 million to $75 million in the first quarter of 2017, and 250 million to 270 million for the full year of 2017, similar to 2016 exploration expenses of $261 million, excluding dry hole expense. The Midstream tariff, which now includes tariffs associated with our Permian gas plant and related CO2 assets and additional North Dakota water handling assets, is expected to be in the range of $115 million to $125 million for the first quarter of 2017 and $520 million to $550 million for the full year of 2017. The EMP effective tax rate excluding Libya is expected to be a benefit in the range of 11% to 15% for the first quarter and 17% to 21% for the full year 2017 versus a benefit of 42% in 2016. As mentioned we will not be recognizing deferred taxes in the U.S., Denmark and Malaysia which causes the lower effective tax rate. This lower effective tax rate will have no effect on cash flow. Turning to Midstream, in 2017, we anticipate net income attributable to HESS from the Midstream segment to be in the range of $15 million to $25 million in the first quarter and in the range of $70 million to $90 million for the full year. Turning to corporate, in 2017 our corporate and interest expenses will not receive deferred tax benefits as discussed and therefore our guidance reflects pre-tax numbers due to the absence of a tax provision. In 2017, we estimate corporate expenses to be in the range of $35 million to $40 million in the first quarter and in the range of $140 million to $150 million for the full year. We estimate interest expense to be in the range of $75 million to $80 million in the first quarter of 2017 and in the range of $295 million to $305 million for the full year of 2017. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

Thank you. [Operator Instructions] Our first question comes from the line of Arun Jayaram of JPMorgan. Your line is now open.

Yeah, good morning. First question just relates to better understanding, the CapEx and the completion activity in the Bakken and just trying to think about 2018. I know you spent 429 million in the Bakken and did 100 wells [ph] and I know you had some ducts that helped you little bit. In 2017, you are guiding to $700 million in CapEx, at the completion count is going down like 25, just wondering if you could maybe help me reconcile that and could reflect some higher infrastructure spending but just thinking about the completion versus the CapEx in 2017 and tops around completion activities as we think about 18.

Yeah, so let me just kind of breakdown the - there is a total of about $660 million being spent in the Bakken next year. About $50 million of that is for non-operative participations in some wells that we are expecting this year. So that leaves about $610 million for I will call it Bakken operated and if you look at that $610 million and break it down, the bulk is drilling in completion. So about $465 million is for drilling and completion at all the related facilities associated with that. There is about $95 million also in that category but that is money spend in 2017 for future years, so that’s the ducts that get carried into 2018 and also the pads that we'll construct in 2017 or early 2018. And then there is about $50 million left for major maintenance and some field upgrades more statistical that we put in the budget. Hopefully that’s helpful.

That’s very helpful. And just my follow up question is, if you could just maybe better help us understand some of the first half ‘17 maintenance related shutdowns that you forecast. I think you all added [ph] four projects that will experience some down time, can you give us some more color on that, pretty much appreciated.

Yeah you bet, I mean most of that - almost all had downtimes in the second quarter and about 13,000 barrels a day down first quarter versus second quarter or second quarter versus first quarter associated with those major shutdowns offshore. About 5,000 of asset Llano [ph] in the Gulf, about 6000 is Equatorial Guinea and couple of thousand barrels a day at Conger also in the Gulf of Mexico. So that’s a majority of it.

Okay thanks a lot, appreciate it.

Thank you. Our next question comes from the line of Doug Leggate of Bank of America. Your line is now open.

Thanks. Good morning, everybody. Greg the update in the Gulf of Mexico, I am just wondering if we could take a little bit in moving part this year, you mentioned but what is the current status and expectations for Tubular Bells trajectory in the full year?

Doug, it is just too early to say on Tubular Bells and that’s because we are basically increasing the chokes and not only that the well that was worked over and they came on in December 31, but also the new well they came on late December as well, so we are just in the early stages of ramping Tubular Bells back up I want to get it stable, we are also getting wider injection stables, I really want to see kind of the well results from that before I be specific on that, so potentially maybe we could provide an update once we get stable.

So what are you assuming in your full year guidance for Tubular Bells.

We aren’t going to give that and again Doug, I am not trying to be evasive, I just really want to see these wells ramp up and see what they are at.

My second one, hopefully a quick one is and I have got one more on Guinea, if I may, just assuming oil prices coming trajectory through the year gives a little higher, what is the first call in cash for HESS in 2017?

So if oil prices come in higher you know what we are doing with the rig ramp in Bakken, we have always said that first call in cash will be the Bakken. So we will continue to look and accelerate how we will bring the rigs in and so that’s what we would be thinking about at this point. So the first call would go to the Bakken.

Okay, thank my final one - I am going to try this, I am not sure I am going to get a lot of mileage out of you guys on Guinea, but I will give it a go. So on the last call, John Hess, you suggested we would know the upper end of Liza, I realize that the Exxon guidance is above a billion but upper end would be 1.4 plus the 100 to 150 I guess gets you to 1.5. But my question is Greg suggested that you are going to drill eastern flank of the field. So can you tell us what proportion of Liza structure is derisked to get the 1.5 to get some ideas to what proportion the overall field capacity will ultimately look like? I'll leave it there thank you.

Very fair question Doug, as we pointed out after the Liza 3 well, we confirmed and partners did as well that we were in excess of a billion barrels of oil I think it is very important to note when asked Liza deep will be accretive to the number, Payara will be accretive to the number. [indiscernible] and potentially Liza 4 will be accretive to the number, so to give specificity at this point in time would just be too early. We got to finish the appraisal that we are underway but there is upside to the numbers that we gave guidance on last quarter.

So and just a quick follow on, are we going to get a second rig down here given the potential move to FID?

That’s under discussion with the operator Doug, obviously after we take out FID, we want third drilling development wells at some point.

All right, thanks everybody.

Okay thank you.

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

Thank you. Good morning.

Good Morning.

Can you talk to your cost inflation assumptions that are built into your capital budget guidance and what if anything you are seeing now, I thought I heard you mention that you are going to be able to keep Bakken cost, Bakken well cost flat in 2017 and if I have heard that right, but can you talk to what risks that you could see as the year progresses and mitigation on that.

Yeah, I think in 2017, we anticipate seeing some pressure in the onshore, commodity based chemicals and potentially as well. But we are pretty confident, you are exactly right, we are pretty confident that we can hold our well cost flat in the Bakken on 50 stage completion in the core at kind of that at $4.8 million average number that we had in 2016. The way we are going to offset increases I mean in sand, commodity base, chemicals, those kind of things is basically by continuing to apply our lean manufacturing capability which we have consistently as you know have been able to pull a $100,000 to $200,000 a quarter out of the well cost. And there is still a bit more room left for that improvement as well.

Got it, thanks. And then separately as your completions in the Bakken are evolving, can you talk to how significant you see further technological improvement in the Bakken or whether you think we’re in the latter innings and does the success in improving EUR solidifies the Bakken as your key shale horse for the company or rather give you more confidence to look at other areas.

Well, let me talk about the completions in the Bakken first, as we said in our opening remark, we are doing a couple of pilots this year. And so in the core of the core which is where we have been focused, where we have that very tight, nine in eight spacing we demonstrated that the best way to optimize value in that core of the core is by using Sliding Sleeve Technology and then steadily increasing the stage counts, which effectively kind of increases the pro-well proppant loading that gives you a nice uniform frac all the way down the well bore and as you know we have worked with our supplier to continue to engineer more and more sliding sleeves in the 10,000 foot lateral. Now we believe that we could be approaching a technical limit on the number of sleeves somewhere between 60 and 70. That’s just given the tight tolerance as between all the ball sizes. So given that we may be approaching that maximum stage count with a sliding sleeve system, we now want to push the technical limits on the per stage proppant loading. So given our tight nine in eight spacing which is only about 500 feet between the wells, we are going to pilot those higher loading to find out where the optimum point might be to further increase value while not causing significant well to well interference. So when we know what is with the proppant loading that we have, we haven’t seen any significant well to well interference so that says you can probably get more proppant in the well and still be okay. So we are going to test the limits of that this year and see exactly how much that is. And so certainly on the sliding sleeve system, in terms of your question on where we are on technology, I think again as we approach 70 stages and got a lot number I think we are start to reach the technical limit there and next things will be proppant loading for us in the core of the core. But again that sliding sleeve system because it is so inexpensive and so efficient to install it is the highest optimum completion technique in the core of the core. As you move outside the core which we will being testing that an in the later years 2018, 2019, data seems to indicate that maybe slickwater completions or even higher proppant loadings with plug and perf maybe the answer out there and that’s purely because there is a lot natural fracturing when you get out of core of the cores. So you are going to need more sand and more energy in the reservoir to connect all those fracture to that. So that’s kind of where I see it going.

And Brian your question about our position in the Bakken and how we feel about it and potentially, expanding our shale footprint in the US. In terms of the Bakken obviously improvements Greg and his team have made in the lean manufacturing, improving productivity, advancing application and technology, obviously everything governed my lean. We are very pleased with the investment opportunity; we have there, the increasing ultimate resource count that we have that reflects the increasing IPs. In terms of expanding our shale footprint, we are always looking to optimize the value of our portfolio in the normal course of business, however given our robust portfolio of captured growth opportunities with excellent return, starting with the Bakken, but also the low-risk high return inflow opportunities that we have in our offshore hubs and now Guinea outright acquisitions are low on our priority business.

Great, thank you very much.

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

Hey, good morning. And I am sure we are not going to up in this year all the results, but as you told F&D cost analyze I mean are you able to share like total development cost for the field?

No Ed, we'll share that when we take FID and so we'll give - during sanction [ph] you'll get a lot more color on cost and volume and production rates and all that. That will most likely be around midyear as when we take FID on Liza Phase 1.

Could we get recovery per well or that will be at the same time, just as we try and model ahead of the announcement.

Yeah, we will give you as much disclosure as we can at sanction.

Okay and then on Payara, I mean obviously sort of a narrow net pay I mean is if that does perhaps suggest a small recovery and perhaps more expensive development and I mean anything in that well to suggest that’s the wrong approach EG, like pressure regime, did you test deeper zones there as well, maybe some color on how Payara stacks up against Liza on a per unit basis?

No, I think a couple points. You bet, yeah it is early days I think let me be clear. Payara is separate and distinct from Liza. So it is ten miles away and having said that the reservoir quality was outstanding, [indiscernible] permeability and same kind of porosity that we saw in Liza. So we are very pleased with the initial results on Payara but we are going to have to do further appraisal to determine the ultimate size of the Payara discovery, the area will extend.

And then maybe switching gears, I mean you signaled acceleration production growth into 2018. I appreciate there is a lot of variables but I don’t know if this point you can share a range particularly I see Bakken will move up, but if well does recover this in a room to perhaps even increase recoveries of Valhall, [indiscernible] all of these decisions just to get - give us a sense as to what the past into ‘18 looks like.

Yeah, so I think the only thing we can say with certainty at this point is you know the Bakken will - we are investing a lot in 2017 in the Bakken. You begin to really see production increase in 2018 in the Bakken. Obviously the second major catalyst in 2018 is Stampede. Beyond that we really can't be specific on an activities there because as we said it is going to depend upon oil price, I think the other thing it will happen in 2018 is as you'll have a four year North Malay Basin because of course you’re only getting a partial year this year. So there is a lot of production catalyst upsides in 2018 and you begin to see that in the back half of this year. Our low point as we said is the second quarter but then by in the third and the fourth quarter you really start to ramp and as I said in my opening remark, if you look at the first quarter versus the last quarter, the delta on production if you just take the midpoint, the range is above 40,000 barrels a day. So we really start to surge in the last half of the year.

Thanks very much.

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

Good morning. Thanks for taking my question. I wanted to ask about your reserve report which I thought was pretty impressive but reserves in F&D obviously can be lumpy but the $13 barrel F&D you highlight was a pretty solid result. So the question is do you think that is the type of F&D cost that's representative for your company through cycle. Or where there is some reserve lumpiness that may have contributed to that and then more broadly just wanted to get thoughts about how you are thinking of the evolution of your F&D for the total company over the next few years and what do you think as sustainable level?

Sure, I mean like you said, this will be qualitative because you know the reserve at F&D can be lumpy. For the most part let me just tell you what drove our reserve and the very good FD&A that we reported. So half of it is as Greg mentioned earlier it is really driven in the Bakken and it is moving up to those 50 stage fracs. We are getting higher EURs and there and over time as we continue to move up to potentially 60 stages and things like that. F&D in the Bakken is going to be an increasingly accretive if you want to say to our past F&D numbers. So that investment we'll be investing in lower cost reserves. So that’s one, let me go longer terms, so we don’t have the numbers yet right as Greg just mentioned and we get the FID in Guinea. But we clearly see for all the reasons that John Hess mentioned and Greg mentioned in the opening scripts that the positive attributes that you see in Guinea, low well cost, their recoverabilities, the high quality reservoirs that we see the F&D is definitely going to be accretive again post our past F&D cost. So our continued investment in Guinea and now that’s going to be lumpy when you get the reserves in, but that's going to be very positive to our F&D reporting going forward. Then within the year itself that you would see North Malay Basin, we picked up some additional reserves, but that's just increased drilling and as we spend money there, the only one that you could see that was kind of, if you want to call lumpy or not tied to CapEx as much with South Arne, we did have a license extension in South Arne, so that was extended out to 2047 and we picked up about 20 million barrels there in South Arne. The rest of it was just from our normal portfolio adds in the positive things that we're doing in E&P.

That’s very helpful. And then my follow-up is, I just want to better understand the flexibility embedded in your plans to ramp from two to six rigs in the Bakken. So, can you talk about the variables that might have you ramping up faster than that or slower than once you've indicated? Are there price-related trigger points you can share with us or any other issues you're monitoring around people, equipment? And if you could just help us with a framework for how you're thinking about managing that pace I think would be helpful.

Yeah, so I think for the first half of the year we'll be adding kind of a rig a quarter and then for the back half of the year, the rigs will probably come in the fourth quarter and that just has to do with the scheduling of the wells, getting the pads ready, all of that sort of thing. Now, there is potential to accelerate those rigs. Maybe another rig comes in the third quarter rather than two in the fourth quarter. We're looking at all of that. But for us, the limiting factor for us is we want to bring these wells on safely. And the cadence for us seems to be that we can bring a rig on about one a quarter and confidently say that we can do that safely and efficiently. So, those are our two drivers, safety and efficiency in terms of how fast we can ramp those rigs.

Thank you.

Thank you. Our next question comes from the line of Doug Terreson of Evercore ISI. Your line is now open.

Good morning, everybody.

Good morning.

First, let's hope that John, the oil price or outlook ends up proving correct, because I think it will all be better off in that scenario. So, just to clarify, first of all, on the Bakken comments, what was the point that despite all the commentary that's in the market about personnel, equipment availability, et cetera, you believe that your drilling time and cost per well are going to be pretty close to flat year-over-year in ‘17 that as long as you're drilling in the core, was that pretty much the message on that?

Yeah, it was, Doug. And as we've spoken about before, during the downturn we tried to preserve a lot of capability in the Bakken, particularly on the contracting side, so that we can enable a smoother transition as you ramp back up. So, we're reasonably confident that in 2017 we can manage that very efficiently, which is why we set our 50-stage fracs in the core. We believe we can hold the costs at that kind of $4.8 million number that we achieved in 2016.

Okay, perfect. And then strategically, in the United States and also overseas in E&P business, when you consider reversion to the mean that we've seen on returns for the big oils and declining [indiscernible] returns on E&P, it seems like competitive conditions are pretty intense out there and then we've also had a fairly staggering rise in energy private equity funding over the past couple of years, which doesn't help that much either. So, while you guys were early in refocusing the company on advantaged areas, done a really good job there. My question is that when you think about the future, what are the strategic imperatives for companies like Hess such that you can continue to navigate this competitive condition successfully in the future? I mean, what would you have to do to ensure the shareholders are rewarded, given this changed condition? Or do you think that the threats not so significant that it requires a response?

No, I think you're absolutely right. It's a competitive world out there for oil resources and obviously the two years of a ‘lower for longer’ price environment has challenged for everyone. Having said that, we think our company is extremely well positioned. And what's going to guide us, Doug, is value, allocating capital, the highest returns and we continue to look at shale opportunities in the United States. You're right to point out that that's a very crowded market and big question mark on returns going forward because of some of the prices being paid. Where we're actually seeing better opportunities to invest our capital is in the offshore that is much less competitive and we're getting very, very attractive opportunities that will fit our cash flow profile but also give us opportunities to make significant value for our shareholders going forward. So, obviously led by Guyana but the opportunities we have in the Guyana’s basin, I think, has legs. There are some other offshore opportunities we see there. So, we're going to be driven by value and in the long run we believe that strategy is the one that will reward our shareholders the most.

Okay. Good answer, John. Thanks a lot.

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

Hey, guys, good morning. The first one is for John Rielly. John, you mentioned that you're not going to have any recognize, any deferred tax in U.S., Denmark, and Norway. Is that purely just a function of price? And at what point that you - those areas that you have the price is high enough and you start making money? So, we assume that you start recognizing the deferred tax benefit in the cash flow or that is going to be a while?

Okay. I just want to clarify. So, it's U.S., Denmark, and Malaysia.

Malaysia.

Yes, those are the three areas. And so, as a result, again this is just a bookkeeping requirement that is in the accounting rules because of this three-year cumulative loss that we have or any company would have, you would have to take down your net deferred tax assets. When we try to or have losses going forward, we can't book deferred tax benefits in those three countries until we reestablish the deferred tax assets. So, your question is when is that going to happen and that is not exactly also in the rules. So, it's going to kind of be a facts and circumstances analysis at a time. So, first of all, we will be emerging and starting to show profits, but then you have to see just like your point, what are the market conditions at that time and any other relevant evidence at that point. So, usually putting a deferred tax asset back on your books is going to require a little bit more positive evidence including now that you're out of this three-year cumulative loss position. So, again I just want to make sure everybody does understand there is no effect on cash flow. There is no economic impact to this at all, so from this charge or the lower effective tax rate going forward.

The second question is for Greg. Greg, just when I’m looking back, when North Malay, the early production systems there, I think the expectation is that [indiscernible] 40 million cubic feet per day until the full development on it and your ramp to 165. Obviously, last year that declined below 40. So, the lower production, is it - what then really is causing you? Is it equipment issue? Is it a reservoir issue or is it contract issue, demand issue, can you just - in other words, I mean, what confident that we have once the full production that you really indeed will be able to [indiscernible] in 165?

Yeah, so, Paul, the early production system, the reason the production is down slightly this year is because of well. So, we lost the well and that early production system is going to go, remember that, that goes away. So, it doesn't make any sense to re-drill a well for a very short lifespan. So, I have all the confidence in the world that the 165 is a good number. We've got a great well stock. We've drilled 13 wells already. All of those wells have come in at or better than pre-drill expectations. So, the wells are healthy. We've got a great wealth stock. We've got a large number of wells in North Malay Basin or will have, so I have a lot of confidence in the 165 number.

Greg, the 165 is based on how many well producing at the same time and what is the average well production?

I can give you more color on that as we get closer to actually bringing it on, Paul.

Okay.

If you ask me that in mid-year and I can give you some more color.

Okay. For the Stampede we've been talking for some time, the 2018 start up and that we're now getting closer. Is there any maybe an EBIT more granularity in terms of is it going to be first quarter, second quarter, mid-year, second half, any kind of addition of data?

No, we'll give you guidance on that later in the year as we get closer. So, we still have - remember what we're trying to do this year, we're going to float out the TLP and topsides, get those landed on location. We got to get all the subsea umbilicals and flow lines done and then we'll also continue drilling. So, 2018 is a big year of installation. So, we'll give you more color as those activities progress throughout the year.

And in Valhall under the new operator, how many wells that they are going to drill this year?

Yeah, there will be three wells that actually get drilled. Only one will come on this year. So, the other two will come on next year.

So, we should not expect that Valhall production will be up until fourth quarter?

Yeah, I think that's a good - I think that's a good estimate, so kind of flattish. In the meantime, we do have a shutdown in Valhall associated with that Ekofisk in the third quarter, but that's fairly minor in the big scheme of things. So, again, we guided 25 to 30 for Valhall this year, which is relatively flat where it was last year.

Oh, I see. All right. Thank you.

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

Hi, good morning everyone. Just a high level question, John, you started out with the [indiscernible]. Greg, you talked about more efficiency. I was wondering, what was the balance between the decisions to accelerate the Bakken in terms of an expectation of higher oil prices or whether it's all about the fact that you can do more for less? Thanks.

It's actually both at the end of the day. We said as prices approach 60 and really have a firm five in the price and we feel pretty good about that. We would be comfortable starting to accelerate our Bakken program and obviously with a great work that Greg and his team have done about lowering costs, increasing stage counts, increasing productivity. When you add it all up, it's about allocating capital the highest returns and we saw some very good returns there.

Yeah I think that you’ve led into the second thoughts on which was, I think previously you talked about free cash flow generation of 60 in the Bakken if I'm not wrong and that being the number at which you would accelerate, are you effectively saying that that number is now lower?

Well, actually, so our plans, our capital plans - fair question. Our capital plans for the Bakken anticipate that asset generating free cash and growing as well and obviously that free cash is going to be a function of what the oil prices, but our plans aren't just to invest all the cash to grow production. It's also to make sure that we start getting some cash back from that asset and that's an integral part of how we thought about allocating the capital.

Okay. Thank you. And then one to add to the Guyana question, just wondering you said Payara very similar to Liza, but one can thus note explicitly net pay seems a lot less. Is there anything to say about that? Thank you.

I think the key thing there is we just have more appraisal to do, but we think it will be a significant resource in and of itself, how big it is, more appraisals necessary.

I guess the question was I think you had 95 feet of net pay at Payara, which is less than half of the Liza?

Absolutely, but more appraisals necessary to find out what the resource size is going to be and so, let's wait for that appraisal before we can be more definitive about what the number is, but we do think Payara itself will be significant.

Thank you, John.

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

Yeah, thanks. Maybe as we just look over the medium term in terms of managing and kind of cash inflows and outflows, you have a large cash balance on hand right now. As you look towards - but a decent sized outspend likely in 2017 as well, so as you look forward over the next few years, how do you anticipate drawing down that cash balance versus the preference towards kind of achieving cash flow neutrality?

Sure. So, again the key is, as we've been talking about, we've been spending this capital on these development projects, North Malay Basin and Stampede and we're getting obviously closer to getting them both online and generating free cash. So, if you are looking from like a general guidance of where we are this year, if you were excluding basically North Malay Basin and Stampede’s capital, our operating cash flow would cover CapEx and dividends in 2017 kind of at the current strip prices that we have. So, it's - and then going forward, it's like John just said, I mean obviously prices are going to play an important role in this, but we're trying to balance our investment in growth and this generation in free cash flow and we've always said 2018 will be the big transition year for us. Now we're generating free cash flow from this North Malay Basin in Stampede and we can use that cash flow now to begin to generate into our development projects, say, in Liza and other growth projects like in Bakken. So, we will balance that continually going forward.

Okay. And any consideration I know it was asked earlier about your appetite for just additional acquisitions. I mean as you look about at the extent of your global portfolio on the flip side, do you look at - how do you - how is the appetite for additional monetization of resource across the portfolio either from some of your global assets or even a farm-down of Guyana in terms of either allowing you to fund future developments or accelerate capital deployment in places like the Bakken?

Yeah, now fair enough portfolio optimization, as I said before, is something we look at every day and is in the normal course of business. So we're always looking to optimize that and go where the value is and go where the returns are. Having said that, outright acquisitions are low on the priority list because what we have captured in our portfolio both short cycle and long cycle already offers very attractive returns to our shareholders. And in terms of Guyana, it offers such attractive returns that that is not looking at something that we would sell down. But as I said in our overall portfolio we're always looking to optimize and as opportunities present themselves we’ll consider them.

Great and maybe one quick follow-up on the Bakken, fourth quarter, as you mentioned in your comments and as we see in the data, in the fourth quarter you saw significant increase in well productivity at least in terms of 30-day IPs versus prior quarters. Can you talk a little bit about what the mix shift was in terms of 50-stage fracs 3Q versus 4Q? And is that a number what we saw in 4Q that we should view as kind of a more representative number of the drilling program going forward in terms of well productivity?

Yeah, I think in the fourth quarter, you're right. All the wells that we drilled are 50-stage and that was truly in the core of the core. So, the best wells that we've drilled in the Bakken that 1091 barrels of oil, kind of IP30, those were the wells we were drilling in the fourth quarter. We will stay in the core in 2017 that will be the bulk of where our drilling is. Certainly, on average because of the 50-stage fracs, the IP90s and the IP30 rates will be higher in 2017 than they were in 2016. So, the whole inventory is not going to be the 1091 kind of IP30s. That was truly some extraordinary wells. So, it'll still be - the average is going to be higher this year than it was last year. So, good upside there.

Great, thanks.

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

Good morning guys and congratulations on the ramp going into fourth quarter. One thing with all the moving parts of Valhall and Malay that is gas but oil linked, can you just give a BO expectation, just barrels of oil for the fourth quarter in that split for the overall corporate guidance?

David, make sure I understand your question.

You gave BOEs, what’s just the barrels of oil in the fourth quarter?

Barrels of oil for the fourth quarter of 2016?

Yeah, in that 330 to 340 guidance, what would be the split?

Oh, now I understand, now I understand in the fourth quarter number. So, we would be moving up considerably here. I'd say it's going to go up approximately almost close to 14%, I'd say, between the first quarter and the fourth quarter on the oil. So, you're going to see that jump clearly above in the range of 210,000 barrels a day plus in the fourth quarter for the oil in that number.

That's very helpful. Thanks, guys.

Thank you. Our next question comes from the line of Jeffrey Campbell of Touhy Brothers. Your line is now open.

Good morning. I was just wondering if you can share any early impressions of [indiscernible] that takes over the operation at Valhall, I mean I don’t think it’s rude to say that sometimes we felt like the prior operators left something to be desired, so I’m just wondering how you’re feeling about them in your early impressions?

Yeah, thanks for the question. I think John and I have met with their senior management twice over the course of the year as recently as a month ago and we’re encouraged by their approach and we really look forward to working together with them to maximize value from the Valhall asset. Hess did a lot with BP and I’ll credit BP with their progress that they’ve made in the last couple of years using many of the techniques that we develop on South Arne, applying those to Valhall both lean manufacturing and some shaft drilling and well [indiscernible] techniques that we developed in the North Sea. Acre, BP is carrying on with that and we’re excited that they can even drive more improvement beyond what BP was able to achieve with our help in the last couple of years.

Okay, great. I think we’ll look forward to that. I just wanted to ask one quick question with regard to Guyana. It sounds like the Liza-1, the Liza-3 and Payara, all tested different formations. I was just wondering with the next well that’s coming and the visible explorations that you see, are you going to be just essentially testing one of those once again in a different location or are you going to be testing an entirely new formation?

Now, these are all upper cretaceous, so every one of these wells has been upper cretaceous. So all of the well test, everything that we’re doing is all confined to the upper cretaceous. Even the Liza deep is upper cretaceous accumulation.

Okay, thank you, I appreciate.

Do you mind, I just want to clarify something for the group that I gave because that was - you were specifically asking before oil. I had some liquids numbers in there, so again from an oil and liquid standpoint there will be a significant increase as you go into fourth quarter. Oil again will have a significant increase, but oil will be about 190,000 barrels a day plus in the fourth quarter and then liquids will be above that. Thank you.

Thank you and I’m showing no further questions at this time. Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.