Jay Wilson - Vice President-Investor Relations John Hess - Chief Executive Officer and Director Gregory Hill - Executive Vice President, Chief Operating Officer, President of Exploration and Production John Rielly - Senior Vice President, Chief Financial Officer

Doug Leggate - Bank of America Merrill Lynch Edward Westlake - Credit Suisse Securities Paul Cheng - Barclays Capital, Inc. Asit Sen - CLSA David Heikkinen - Heikkinen Energy Advisors Guy Baber - Simmons & Company International Evan Calio - Morgan Stanley Brian Singer - Goldman Sachs & Co. Roger Read - Wells Fargo Securities, LLC Jeffrey Campbell - Tuohy Brothers Pavel Molchanov - Raymond James & Associates, Inc. Phillips Johnston - Capital One Southcoast, Inc. John Herrlin - Societe Generale

Good day, ladies and gentlemen and welcome to the Fourth Quarter 2015 Hess Corporation Conference Call. My name is Candace and 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 of Investor Relations. Please proceed.

Thank you. 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 those 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 will now turn the call over to John Hess.

Thank you, Jay. Welcome to our fourth quarter conference call. I’ll provide an update on the steps we are taking in response to the low oil price environment and review highlights from 2015. Greg Hill will then discuss our operating performance and John Rielly will review our financial results. Three principles are guiding us through this lower-for-longer oil price environment. Preserve the strength of our balance sheet, preserve our operating capabilities and preserve our long-term growth options. By adhering to this disciplined approach, we finished the year with one of the strongest balance sheets and liquidity positions among our E&P peers, with $2.7 billion of cash, an undrawn $4 billion revolving credit facility that goes out to January 2020, and a net debt-to-capitalization ratio, excluding the Bakken Midstream joint venture of approximately 15%. Our top priority in this challenging environment is to continue to keep our balance sheet strong. Yesterday, we announced a 2016 capital and exploratory budget of $2.4 billion, 40% below our 2015 spend, and approximately 20% below the preliminary guidance we provided in late October of $2.9 billion to $3.1 billion. Our focus is on value not volume and we do not think it makes sense to accelerate production in the current price environment, particularly given the recent further deterioration in the oil markets. For this reason we will reduce activity levels across our producing portfolio in 2016, both onshore and offshore, and will continue to pursue further cost reductions to preserve the strength of our balance sheet. Our 2016 production forecast remains the same as our previous guidance of 330,000 to 350,000 barrels of oil equivalent per day, even with roughly $600 million of additional cuts in capital spend from our previous guidance and the recent sale of our assets in Algeria in December, which contributed net production of 10,000 barrels of oil equivalent per day in the fourth quarter of 2015. In terms of our year-end reserves as a result of significant price driven negative revision and a corresponding reduction in activity levels, our proved reserves decreased year-over-year to 1.086 billion barrels of oil equivalent at year-end 2015. It is important to note that all of the decrease was in proved undeveloped category and that our proved developed producing reserves increased by approximately 4% versus 2014. Now turning to our 2015 financial results, our adjusted net loss was $1.1 billion and cash flow from operations before changes in working capital was $1.9 billion. Compared to 2014, our results were positively impacted by higher crude oil and natural gas sales volumes, which were more than offset by lower crude oil and natural gas selling prices and higher DD&A expense. From an operational standpoint, 2015 was a year of outstanding performance with strong execution across the portfolio and we are very proud of the work our team has done in a difficult oil price environment. Actual production was 375,000 barrels of oil equivalent per day versus our October guidance of 370,000 to 375,000 barrels of oil equivalent per day. On a pro forma basis excluding Libya and asset sales, 2015 production increased by 18% compared to 2014 averaging 368,000 barrels of oil equivalent per day versus 311,000 barrels of oil equivalent per day the prior year on the same basis. Also during 2015, we delivered significant reductions in both capital expenditures and cash operating costs and achieved early success with our focused exploration program. Turning to the Bakken, Hess has an industry-leading acreage position that is competitive with the best shale oil plays in the United States. Through the application of lean manufacturing techniques, our Bakken team has continued to drill some of the lowest cost and most productive wells in the play. Our 2016 focus is on the core of the core, where Hess has significantly more drilling spacing units or DSUs than any other competitor. Maintaining a two rig program will help preserve our top quartile operating capabilities; so that we are positioned to efficiently increase activity when oil prices recover. Bakken production in 2015 averaged 112,000 barrels of oil equivalent per day, up approximately 35% from 2014. Despite dropping to two rigs, we continue to forecast Bakken production to average between 95,000 and 105,000 barrels of oil equivalent per day in 2016. On July 1, 2015 we closed on the Bakken Midstream joint venture, which resulted in total cash proceeds to Hess of $3 billion. Hess maintains operational control of these strategic assets giving us access to the best markets for our products through the flexibility that it offers. As previously announced, the joint venture plans to proceed with an initial public offering of Hess Midstream Partners LP common units when market conditions improve. In terms of developments, while we are significantly reducing investment across our base portfolio. We plan to continue to invest for future growth with two offshore developments. The first, North Malay Basin, is a long-life, low-risk natural gas resource with oil linked pricing. Hess is operator with a 50% interest. Full field development is on track for startup in 2017 after which the project is expected to add an incremental 20,000 barrels of oil equivalent per day of production and become a long-term cash generator. Our second offshore development Stampede is one of the largest undeveloped fields in the deepwater Gulf of Mexico, with estimated gross recoverable resources between 300 million and 350 million barrels of oil equivalent. Hess is the operator of Stampede and we have a 25% interest. Following startup in 2018, the project will add an incremental 15,000 barrels of oil equivalent per day of production and become a material cash generator. Turning to exploration, we are very pleased with the early results from our focused expiration program. Namely, the Exxon-operated Liza discovery, offshore Guyana, in which Hess has a 30% working interest. And the Chevron-operated Sicily discovery in the deepwater Gulf of Mexico in which Hess has a 25% working interest. In particular, we believe that the Stabroek Block in Guyana has the potential to be very material to Hess and create significant long-term value for our shareholders even in a lower price environment. About 90% of a 17,000 square kilometers 3D seismic acquisition program has been completed. In 2016, we plan to drill up the four wells to evaluate the Liza discovery, perform a drill stem test and explore additional prospects on the block. In summary we are well-positioned to navigate this lower-for-longer price environment and are taking a disciplined approach to preserve our financial strength competitively advantage capabilities and long-term growth options. I will now turn the call over to Greg for an operational update.

Thanks John. I would like to provide an operational update on our progress in 2015 and our plans for 2016. As John mentioned 2015 was a year of strong execution across our portfolio. Production averaged 375,000 barrels of oil equivalent per day at the top end of our October guidance of 370,000 to 375,000 barrels of oil equivalent per day. Furthermore, in the fourth quarter, production averaged 368,000 barrels of oil equivalent per day exceeding our October guidance of 360,000 barrels of oil equivalent per day for the same quarter. In 2015, we also reduce capital and exploratory expenditures by $400 million during the year and cash operating cost by more than $300 million. We continued to drive down our drilling and completion costs and successfully conducted tighter spacing and increased stage count pilots in the Bakken. We also achieve material exploration success in Guyana and the deepwater Gulf of Mexico were the Liza and Sicily wells were ranked as the two largest oil discoveries of 2015 by both Wood Mackenzie and IHS. Clearly 2015 was a challenging year in terms of oil prices and we believe it is prudent to manage the business assuming that prices remain lower for longer. On that basis we announced yesterday a 2016 capital and exploratory budget of $2.4 billion, which is 40% below 2015 levels and will result in significant reductions in activity levels across our unconventionals and offshore business. Year-end 2015 proved reserves were significantly impacted by the price environment with the addition of 84 million barrels of oil equivalent offset by price related downward revisions of 282 million barrels of oil equivalent. Year-end proved reserves accounting for the sale of our Algeria asset, were 1.086 billion barrels of oil equivalent of which 73% proved developed. Nonetheless, the notable early success of our exploration program and continued technical advances in our unconventionals business have allowed us to materially grow our total resource base. In 2016, we forecast companywide production to average between 330,000 and 350,000 barrels of oil equivalent per day. This forecast is unchanged from preliminary guidance provided on our last quarterly conference call despite the further 20% reduction in our capital and exploratory expenditures. In the first quarter of 2016, we forecast companywide production to average between 340,000 and 350,000 barrels of oil equivalent per day. Turning to operations, the Bakken continued to deliver outstanding performance as well as higher upside. We exceeded our production targets continued to substantially reduce our well cost through the continued application of lean manufacturing techniques, significantly improved our well IP rates through the successful testing of 50-stage sliding sleeve fracs, an industry first in the Bakken, and increased our well inventory and estimated ultimate recovery through infilling to tighter spacing, using a nine and eight configuration. Full year production in the Bakken averaged 112,000 barrels of oil equivalent per day, which was 35% above 2014 and above our guidance from the beginning of the year of 95,000 to 105,000 barrels of oil equivalent per day. In the fourth quarter as a result of lower drilling activity net production average 109,000 barrels of oil equivalent per day up 7% from the year ago quarter. Lean manufacturing practices enabled us to once again significantly drive down our Bakken drilling and completion costs with the fourth quarter averaging $5.1 million per well versus $7.1 million per well in the year ago quarter, a reduction of 28%. Looking forward, we expect drilling and completion costs in 2016 to remain near this level, even though we will increase stage counts by approximately 40% as we move from our standard 35-stage design to a 50-stage design. The 50-stage trials conducted in 2015 have been very successful delivering more than a 20% average increase in IP30, 60 and 90. Our tighter well spacing pilots in 2015 have also been successful. Results to date confirm that moving from 13 wells to 17 wells per DSU is value accretive in the core of the play enabling us to add 200 new drilling locations to our inventory. Additional pilots will be required in the future to fully understand applicability across all of our acreage which to some degree will be a function of price. The combination of our successful infill pilot and overall stronger type curve performance has allowed us to increase our estimated ultimate recovery from the Bakken to 1.6 billion barrels of oil equivalent from our previous estimate of 1.4 billion barrels of oil equivalent. Our industry-leading Bakken position continues to provide a forward well inventory that has one of the lowest breakevens in the play. However, in the current pricing environment, we believe it is prudent to reduce drilling until oil prices recover. With this in mind, in 2016, we intend to reduce our activity to two rigs at the end of February compared to an average of 8.5 rigs in 2015 and 17 rigs in 2014. Our 2016 capital budget for the Bakken is $425 million approximately a 70% reduction from 2015. We plan to drill approximately 50 wells and bring approximately 80 new wells online in 2016 compared to 219 new wells online in 2015. Despite this significant reduction in well activity, we forecast Bakken net production to average between 95,000 and 105,000 barrels of oil equivalent per day in 2016 and also in the first quarter of 2016. Moving to the Utica. In 2015 the joint venture drilled 24 wells and brought 32 new wells on production. In the fourth quarter, net production averaged 30,000 barrels of oil equivalent per day compared to 13,000 barrels of oil equivalent per day in the year ago quarter. Net production for the year in the Utica averaged 24,000 barrels of oil equivalent per day compared to 9,000 barrels of oil equivalent per day in 2014. In 2015 by applying the same lean manufacturing techniques that we use in the Bakken. We reduced drilling and completion costs by 30%, down to $9.6 million per well from $13.7 million per well in 2014. Despite the high quality of our acreage position and low 5% average royalty, the joint venture intends to lay down the one rig we have operating at the end of the first quarter of 2016 given low natural gas and NGL prices and wide basin differentials. In 2016, we plan to drill five wells and bring 14 new wells online. Production is forecast to average between 20,000 and 25,000 barrels of oil equivalent per day in 2016. Turning to our offshore operations, in the deepwater Gulf of Mexico, we commenced remediation work at our Tubular Bells field in which Hess holds a 57.1% working interest and is operator. This work includes acid jobs at two wells and opening a stuck subsurface safety valve at another well. The field produced approximately 20,000 net barrels of oil equivalent per day in 2015 and we forecast that the remediation work will allow production to increase to approximately 25,000 barrels of oil equivalent per day over 2016. In Norway, at the BP-operated Valhall Field, in which Hess has a 64% interest, production average 33,000 barrels of oil equivalent per day in 2015. In response to low prices, the operator plans a very minimal amount of activity in 2016. Full-year net production is expected to average approximately 30,000 barrels of oil equivalent per day in 2016. At the South Arne Field in Denmark, which Hess operates with a 61.5% interest we expect to complete the current phase of development drilling and release the rig at the end of the first quarter. Net production averaged 13,000 barrels of oil equivalent per day in 2015 and is expected to average approximately 15,000 barrels of oil equivalent per day in 2016. In Equatorial Guinea, where we are operator with an 85% interest we recently completed the acquisition of new 40 seismic. Processing of this seismic is underway and the early data indicates additional infill production and water injection well opportunities that can be pursued when oil prices recover. Net production averaged 43,000 barrels of oil equivalent per day in 2015. Looking forward production is expected to decline over 2016 reflecting a continuation of the drilling pause that has been in place since mid-2015. At the Malaysia Thailand joint development area and the Gulf of Thailand in which Hess has a 50% interest. Work continues on the booster compression project, which is expected to be completed in the third quarter. Further drilling activity will not be required to meet contracted volumes for the next couple of years as a result of the compression project. Net production average 43,000 barrels of oil equivalent per day in 2015 and is expected to be approximately 35,000 barrels of oil equivalent per day in 2016 reflecting planned downtime associated with the booster compression project and lower PFC entitlements due to lower capital expenditure. We continue to progress our North Malay Basin and Stampede developments, which remain on target to come on-stream in 2017 and 2018 respectively. Net North Malay Basin in the Gulf of Thailand, in which Hess holds a 50% interest and is operator. The first two wells of the development drilling campaign have reached total depth and are fully in line with pre-drill expectations. Net production averaged approximately 40 million cubic feet per day through the early production system in 2015 and is expected to stay at this level through 2016. Following completion of the full field development project in 2017 net production is planned increased to 165 million cubic feet per day. At the Stampede development in the Gulf of Mexico, in which Hess holds a 25% working interest and is operator we successfully completed installation of piles, started setting equipment on the top side and made good progress on the whole in 2015. Looking forward in 2016 we aim to complete the top sides main deck begin offshore installation of the whole block and install the subsea systems. Development drilling will commence in 2016 and first oil remains targeted for 2018. Moving to exploration. In the Gulf of Mexico following the success of the Sicily-1 discovery well, in which Hess holds a 25% interest. The operator Chevron has commenced drilling the Sicily-2 appraisal well to delineate a large four-way closure in the outboard Paleogene. The operator expects to reach target depth during the second quarter of 2016. Also in the Gulf of Mexico we are participating in a ConocoPhillips operated prospect called Melmar, in which Hess has a 35% interest. The lower price environment has enabled access to high-quality longer-term offshore prospects at attractive entry costs. Melmar is a good example of this and fits well with our strategy. It is one of the last large Paleogene four-way prospects in the prolific Perdido trend. Drilling operations began in December and the operator expects to reach total depth in the second quarter of 2016. In Guyana for the Liza-1 well accounted 295 feet of high-quality oil bearing reservoir. The operator Esso Exploration and Production Guyana Limited is planning to evaluate the Liza discovery and test the further potential of the Stabroek Block, in which Hess has a 30% interest. The next well, Liza-2 is planned to spud later in the first quarter. In closing, despite the challenging price environment 2015 was a year of excellent execution and delivery across our business which is a tribute to the outstanding people of Hess. Our strategy is to continue protecting our balance sheet, while maintaining our core capabilities and 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 2015 to the third quarter of 2015. Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $396 million in the fourth quarter of 2015, compared to $291 million in the third quarter of 2015. On a GAAP basis, the corporation incurred a net loss of $1.821 billion in the fourth quarter of 2015, compared with a net loss of $279 million in the previous quarter. The fourth quarter results contained non-cash charges of $1.359 billion resulting from the low commodity price environment including the write-off of our E&P segment goodwill of $1.98 billion. The non-taxable goodwill charge was allocated in our financial results to U.S. and international operations. In addition, fourth quarter exploration expenses include $178 million after-tax for the write-off of previously capitalized gas wells in Guyana, three previously capitalized wells in Australia that are not included in the most recent development concept and the impairment of certain leasehold costs in the Gulf of Mexico. In the United States we also recognized an impairment charge of $83 million after-tax associated with our legacy conventional North Dakota assets. In connection with the sale of Hovensa’s assets and completion of its bankruptcy has agreed to assume obligations under the Hovensa pension plan and relinquish our rights to receive any proceeds from financing provided to Hovensa during bankruptcy in exchange for the release of all claims from the Virgin Islands government that were asserted against us. Our fourth quarter results include charges of $41 million after-tax for the cost of the pension obligations amounts funded in the quarter and legal fees. Turning to E&P. On an adjusted basis, E&P incurred losses of $328 million in the fourth quarter of 2015, compared to a loss of $221 million in the third quarter of 2015. The changes in the after-tax components of adjusted results for E&P between the fourth quarter of 2015 and the third quarter of 2015 were as follows. Lower sales volumes reduced results by $46 million. Lower realized selling prices reduced results by $33 million. Higher exploration expenses reduced results by $21 million. All other items net to a reduction in results of $7 million for an overall reduction in fourth quarter adjusted results of $107 million. In the fourth quarter, our E&P operations were under-lifted compared with production by approximately 1 million 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 38% for the fourth quarter of 2015 compared with the benefit of 47% in the third quarter. On an unadjusted basis the fourth quarter effective tax rate reflects the fact the goodwill impairment charge did not have an associated tax benefit. Turning to Midstream. Fourth quarter net income of $11 million was down versus third quarter net income of $16 million, primarily due to lower volume throughput at the Tioga gas plant as a result of unplanned downtime and increase crude export via pipeline in response to market differentials. Bakken midstream EBITDA excluding the non-controlling interest amounted to $67 million in the fourth quarter of 2015 compared to $79 million in the previous quarter. Turning to corporate, after-tax corporate and interest expenses excluding items affecting comparability were $79 million in the fourth quarter of 2015, compared to $86 million in the third quarter of 2015. Turning to cash flow, net cash provided by operating activities in the fourth quarter including an increase of $401 million from changes in working capital was $623 million. Additions to property, plant and equipment were $935 million. Net borrowings were $93 million, common stock dividends paid were $72 million, other net amounted to a use of cash of $6 million resulting in a net decrease in and cash equivalents in the fourth quarter of $297 million. Excluding amounts held in our Bakken Midstream joint venture we had approximately $2.7 billion of cash and cash equivalents at December 31, 2015, compared to $3 billion at September 30, 2015. Total debt excluding Bakken Midstream was $5.9 billion at December 31, 2015 and our debt to capitalization ratio was 24.4%. In addition we have a committed $4 billion revolving credit facility that is undrawn. Turning to 2016 guidance, we project cash cost for E&P operations to be in a range of $15 to $16 per barrel of oil equivalent in the first quarter of 2016 and $14.50 to $15.50 per barrel for the full-year 2016 down from 2015 cash cost of $15.69 per barrel. The first quarter cash cost include well workover cost at the Tubular Bells Field. DD&A per barrel of oil equivalent for the first quarter of 2016 is forecast to be $29 to $30 per barrel and $28.50 to $29.50 per barrel for the full-year of 2016, up from 2015 DD&A of $28.14 per barrel. This results in projected total E&P unit operating costs of $44 to $46 per barrel in the first quarter of 2016 and $43 to $45 per barrel for the full-year of 2016 compared with 2015 E&P unit operating costs of $43.83 per barrel. The Bakken Midstream tariff expense is expected to be $3.55 to $3.65 per barrel of oil equivalent for the first quarter of 2016 and $3.55 to $3.95 per barrel of oil equivalent for the full-year of 2016, up from 2015 Midstream tariffs of $3.28 per barrel. Exploration expenses, excluding dry hole costs and items affecting comparability, are expected to be in the range of $65 million to $75 million in the first quarter of 2016 and $260 million to $280 million for the full-year 2016 down from $338 million in 2015. The E&P effective tax rate excluding Libya is expected to be a differed tax benefit in the range of 41% to 45% for the first quarter and full-year of 2016 versus a benefit of 45% in 2015. Turning to Midstream, in 2016 we anticipate net income attributable to Hess from the Bakken Midstream segment, which reflects our 50% ownership to be in the range of $10 million to $15 million in the first quarter and in the range of $40 million to $50 million for the full-year. Turning to Corporate and Interest, in 2016 we estimate corporate expenses net of taxes to be in the range of $25 million to $35 million in the first quarter and in the range of $110 million to $120 million for the full-year. We estimate interest expense to be in the range of $50 million to $55 million in the first quarter of 2016 and in the range of $205 million to $215 million for the full-year 2016. 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] And our first question comes from Doug Leggate of Bank of America. Your line is now open.

Hi, good morning everybody.

Good morning, Doug.

First, I've got a couple, if I may. First question is to John Rielly. John, the cash flow number you gave was net of working capital, but can you X the working capital gain, cash flow looked a bit light. Can you walk us through what has gone on with particularly deferred tax and any other unusual items that explained that number? And then I have got a couple of exploration follow-ups, please.

Sure. In the fourth quarter we did have some special charges in the fourth quarter and some of them do have a cash flow impact. So they are impacting what a normal run rate would be in the fourth quarter. So the first part of that in the E&P charges are for surplus materials and supplies just due to reduced drilling plans so that was approximately $25 million in the quarter that was reducing cash flow, that $221 million. And then also we had lower cost of market in the fourth quarter of approximately $40 million. So those two right there, from a special charges aspect, gets you about $65 million kind of a nonrecurring impact in the quarter. And then there's a couple of other things, one from the specials outside of E&P is for Hovensa. So part of the charge relates to the relinquishment of proceeds that we provided during bankruptcy plus we get legal fees in there. So that was approximately $20 million in the quarter again reducing cash flow from operations. And then on an operating standpoint, you probably saw you noticed our exploration costs were up in the quarter just from a run rate standpoint it was in line with our full-year guidance, but in the fourth quarter we had higher seismic approximately $20 million to $25 million in the quarter. So again from a recurring type standpoint it's just impacting at lower cash flow in the fourth quarter. And then the last thing you heard, I did mention there was a 1 million barrel under lift. So even though that had from a results standpoint not much of an impact, it does have a cash flow impact in the quarter. And so you are ranging that $10 million to $15 million for that under lift. So all told, it is about $125 million when you add those numbers up kind of reducing the cash flow from operations in the quarter.

That makes a ton of sense, makes - reconciles the number. Thanks, John. My follow-up, to the extent you can answer on two non-operated exploration wells, I mean clearly exploration is getting no quarter with the market right now. But these looked like to John comments, look like they could be pretty material. So Greg, first of all on Melmar, could you walk us through the genesis of how you got that in this market, spending additional capital on exploration might seem surprising to some. So what is the genesis of your entry there to the extent you can talk about the prospect? My understanding is this is a $2 billion to $4 billion oil-in-place target. I mean are those numbers right? And how would you risk it? I've got a follow-up on Liza, please.

Yes, so on Melmar. Let me just open Doug. Of course we are in a long-term business and we need to both think about today and tomorrow, so and one of the things we’re seeing is this low price environment has created a lot of opportunities to access very high-quality longer-term growth options at very competitive entry cost. So Melmar is a great example of that. Melmar, if you look at it it’s a very large four-way on the proven prolific Perdido trend. So we farmed into a 35% working interest position at all eight blocks covered by the structure. I think importantly, it’s one of the last undrilled large Paleogene four ways in the Perdido trend and therefore has a very high chance of geologic success. The second thing about it, it's got a water depth of about 5,200 feet now that's compared to 7,900 feet at Great White. And so that what that means is it has higher projected reservoir pressures compared to Great White. The development costs could be significantly lower, given the shallower depth, and importantly the rock properties across the impermeability and deliverability are also going to be likely be the best in the Perdido trend. So when you look at the prospect, it was one of these really quality prospects that you could get in at very low entry cost. So that's why we get it.

Okay. My final one, if I may, is also on exploration, Greg. And again, I realize Exxon is the operator. So the constraints that puts around you. But you did put $70 million in your budget for predevelopment. I'm just wondering what that means. Again, you hit rock quality with Melmar, but we’re hearing that the rock quality in Liza could be kind of off the charts. So if you could give some color there and maybe some idea as to what an early production system might look like, acknowledging that it is only one well and perhaps we are getting a little bit over our skis, but any color you can provide, it would be helpful. Thanks.

Yes, I think, so first of all the rock property is fantastic. Very good porosity, very good permeability for deepwater at this depth, it is truly almost an outlier in that respect. Regarding the early production system we have money in our budget to begin looking at the development options, obviously the development options will be depended upon what you figure out in the appraisal program. So other than that we can't really be specific because it depends on what we find in the appraisal program, so but very good, very exciting Guyana province here.

Are you prepared to give us a scale on the discovery yet, Greg?

I can’t yet, you’ll have to ask the operator about that.

I think that would be the answer. All right, thanks a lot.

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

Good morning gentlemen. Just the market obviously, with the low strip prices, is very focused on outspend. Obviously you’re spending 820 on the two developments and when they come on-stream, you will get the cash flow from that. That’s pretty obvious. But in terms of the next wave of spending around Guyana or the lower treasury. I am just trying to get a sense of are there any sort of lease terms which might force you into spending money, even if the oil price stays low? I am trying to get a sense of a way of asking 2017 exploration spend and development spend and maybe a trajectory into 2018.?

Sure, Ed. The way we look at it in and obviously as Greg said, Guyana is an exciting opportunity for us and you kind of laid it out with North Malay Basin coming on-stream in 2017 turning into a cash generator and then Stampede following in 2018. We don't really see any significant developments spend coming our way from Guyana in 2017 and 2018. We see further exploration spending coming in. So the bigger development spend will be coming in fitting nicely into our portfolio as North Malay Basin and Stampede come up. So I can’t really give you any specific guidance, but that's how we think about the spending going over the next couple of years.

Okay. And then just on the Bakken, obviously with two rigs, it feels like you’re going to be drawing down some undeveloped - sorry, drilled but uncompleted inventory. Maybe just an update as you roll - if you rolled a two-rig program out into 2017, what the impact would be on Bakken production.

Yes, I think Ed, with the two-rig program we feel pretty confident we can hold production in that range of 95,000 to 105,000 barrels a day through 2016. If you think about how that trajectories going to unfold those throughout 2016, it’s going to start the year at the high-end of the range and it’s going to be end the year at the lower end of the range. So if you fast-forward to 2017 and set I held two rigs through 2017 obviously you would see some decline year-on-year, you can't hold it flat for more than a year with two rigs.

Okay, thanks very much.

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

Thank you. Hey gentlemen, good morning.

Good morning.

Greg, just curious then I mean just three months ago when you were talking about the guidance of the budget was a four rig program for Bakken, we talking about 95,000 to 105,000 and now with the two-rigs. Over the last three months, then, what may have changed that to make you increase the confidence that only two-rig and you actually also drop the number of well going to be on-stream next year from 100 to 80, but you keep the guidance to be the same. You said just that three months ago the guidance, you actually feel like you could be able to reach the high end. And now it is more like in the middle or in the lower end. Just trying to understand.

Okay, thanks Paul. Really there is four factors. So first of all the two-rig program is really focused in the core of the core with the higher EURs and IP rate. I think the second factor is we’ve increased the stage count from 35 being our standard design to 50-stage fracs as our standard. And if you look at the impact of the 50 stage design we are seeing about a 20% increase in IP 30, 60 and 90. So obviously that's going to carry through. I think the third thing is we are going to have increased gas and NGL capture in the plant as the Hawkeye south of the river system comes on in the third quarter of the year. And then the last is just increased drilling efficiencies. So further reductions in the spud-to-spud base. So it’s really all four of those factors add up to you can still hold the range even with the two-rig program.

And Greg, looked like the $600 million cut from the previous guidance, $300 million appears to be from the major projects. Because I thought previously you are talking about $1.5 billion in the major projects and now it is about $1.2 billion. Are you including the exploration or appraisal during Guyana and northern? Where is that $300 million has been reduced from?

Paul, I can answer this even - I guess maybe just a little bit more broadly. But of that $600 million about half of it is due to cost-saving. So we are seeing further cost savings from the numbers that that we had provided in October. So we’re getting about $300 million there across and some of it is in the development project, some of it is in our existing assets. And then the other half, like reducing to the two rigs in the Bakken is due to deferral of activity.

I see. And then, John, since that you are here, Algeria that the offset sales, have you already closed before the end of the year? In other words, is the money already in your balance sheet or that we should expect that in the first quarter? And if it is, how much is that?

So the actual transaction did close right before year-end. However, we have not received the cash yet. That will be coming in the first quarter. The contract though is confidential I can't give you the number on that. But it is not a significant amount.

So when you say not a significant, you say it means less than 100?

You can estimate that Paul. Yes.

Okay, that's fine. And I just want to clarify. I have to apologize that when you speak, I - John, you can correct me maybe. You're saying that the cash at the end of the year, excluding the Bakken, John mentioned is $2.3 billion or did I get that number wrong?

Right. No, you did. It is $2.7 billion sorry Paul.

$2.7 billion.

Yes, $2.7 billion.

Perfect. Thank you.

Thank you.

Thank you. Our next question comes from Asit Sen of CLSA. Your line is now open.

Thanks, good morning. A couple of questions, if I may, on the cost structure. Historically, when looking at the Bakken, Greg, I think you have mentioned OpEx per barrel a split of 40% variable, 60% fixed, but the variable costs should benefit from the lower energy component. But there could be several moving parts in the fixed component, particularly as relates to lower field personnel costs. Could you update us on that? So that's number one. Number two: on DD&A per barrel, that number should also trend lower over the medium term. Could you discuss sort of the potential trajectory? And third, on the cost structure, Stampede first oil expected in 2018. I know the rigs have been contracted. What percent of the project cost is yet to be committed?

Okay I will try to answer all three of you. So the first one, you are focusing on the Bakken but it does apply across the portfolio that we do have high you know I mean there is a good amount of the costs that are fixed and so obviously we are trying to attack the fixed cost in this low-price environment as well as the variable costs and making sure we get all the variable costs out as we reduce activity. So we have been seen from let’s just pick the Bakken on our cash cost per barrel we’ve been seen significant reductions like if you go back from the first quarter of 2014 through the fourth quarter of 2015. We've been seen significant cost reductions on our cash cost per barrel. And you probably heard when I gave the 2016 guidance we are giving guidance that our cash cost per barrel are going down in 2016 and that’s with a reduction from 368,000 barrels a day pro forma production down to our 3.30 to 3.50. So we are trying to stay up with especially in this low oil price environment reducing fixed costs and variable costs and so we are attacking both of them. As far as DD&A from a trajectory standpoint, you heard from our guidance actually our DD&A was going up in 2016 and that it's directly related to the reserves. So you heard the reserves are going down from the price revisions so with those lower reserve amounts that's going to increase our DD&A up as prices recover, then those reserves will come right back on the book. And so in a normal environment what would be happening say in the Bakken as we continue to add reserves through our performance in additional drilling and now that we’ve got all the infrastructure spend kind of behind us our DD&A would be going down over time. As far as Stampede, and I’m going to hand it back to Greg for that.

Yes, so thanks for that. Stampede, if you look at it most of the costs have already been committed, but we have taken advantage of the lower price and service environment and actually got some savings from Stampede. As we put in our capital press release yesterday, we will spend about $325 million in 2016 in Stampede.

Great, that is very helpful. And then just a follow-up on Guyana, could you talk about well costs? I know Liza was probably less than $80 million, I think you mentioned. And could you remind us of the environment, water depth, et cetera if you could?

Yes, so you're right Liza was less than $80 million net to us. Regarding future well costs, you are going to have to refer to the operator. What I will say is obviously the appraisal wells will be higher cost, because we’re doing lots of testing and coring and the normal things that you would do in the appraisal part of the program.

Thank you.

Thank you. And our next question comes from David Heikkinen of Heikkinen Energy Advisors. Your line is now open.

Good morning guys. I have one high level question and one kind of lower level, what do you expect your year-end 2016 cash to be?

Okay, David that’s - let me go through, I’ll tell you how I think you should be looking at 2016. So we finished the year as you know with $2.7 billion of cash and obviously we’re going to have cash flow from operations in 2016. So as we just released yesterday, you saw our capital spend program is estimated to be $2.4 billion in 2016. In that $2.4 billion is approximately $200 million of exploration cash spend, like seismic and G&A that’s part of cash flow. So we have to fund capital expenditures of $2.2 billion and we have our dividend of approximately $285 million, let me just round that to $300 million. So our capital and our dividend is going to be $2.5 billion in 2016. We have a cash balance at the end of 2015 of $2.7 billion. So effectively we can fund our capital program and our dividend out of our cash balance and still have $200 million left over at the end of 2016 and obviously we still have the revolver undrawn. So then with that $200 million left from the cash account, David I am going to give you some work to do here. Because now you have to estimate what the cash flow from operations are going to be in 2016 and that depends on your commodity price assumption. So we’ve given you the production guidance, the cash cost guidance and whatever cash flow from operations that you then come to you can add to that $200 million and that’s where we will sit. So we are in a good liquidity position coming into this year and I think that's how you have to look at 2016.

Yes, you did not want to fill in the blank that I was looking for. That is fair enough. On the other side, Greg, the new stage count is pretty impressive. And then you are coming up. So just trying to get an idea of 2016 Bakken development. Do you have any idea of what 30, 60, and 90-day rates would be? Just round numbers would be helpful on a BOE basis.

I think we have given guidance before and we’ll be at the upper end of that range obviously because we are in the core of the core of the Bakken. So our previous guidance will be in the high-end of the range.

Yes, it just seemed like you are double dipping with the new wells and core of the core that it would have been even above that range, potentially.

It will be. Once you had the 50-stage fracs, so we need to update our guidance once we get over entirely.

Okay, perfect. Overall that through, too and then just net-net of everything, what is your Bakken net back expected to be in the first quarter?

So we never really try to forecast because it’s so difficult quarter-to-quarter, so in the fourth quarter we were - the Bakken was getting between $6 and $7 under TI and again the economics are right now favoring more to pipe then rail.

Yes, about 75% of our volume now is on pipe and the clear book differential that goes into that $6 number that John was just talking as a discount to WTI just maybe 250 refineries and turnarounds so that number was about 150 before. So there's a lot of dollar weakness now, but refineries come back on we expect that to recover.

Okay, thanks.

Thank you. And our next question comes from Guy Baber of Simmons & Company. Your line is now open.

Good morning everybody.

Good morning.

You all have consistently mentioned that preserving your operating capability is a key objective for the Company. And that is the strategic question for me, particularly in the Bakken. But can you talk about striking that balance between cutting CapEx and rigs to protect the balance sheet versus preserving your capability so that you can respond in a timely manner when you get the appropriate oil price signal. Is that a concern for you guys with two rigs running? And is it a concern for you all for the industry at large in the Bakken from what you can see?

Thanks for that question. It is striking the balance and I think with our budget and operating two-rigs in the Bakken, we think we've achieved the right balance. So we’re doing creative things with doubling up people and moving them over to special assignments and all at, making sure that they're ready for the inevitable ramp-up that will come in the Bakken.

Okay, thanks. And then my follow-up is on the committed CapEx going forward, thinking through 2017 and 2018, we know that major project spending, long lead time, obligations are falling off over the next few years. But can you give us any specific indications as to how much decline in 2017 - is the majority of the North Malay Basin CapEx in 2016, you're not going to have that spending commitment in 2017? Or is that more of a 2018 event? Just trying to get a better sense there as I think it would help us better appreciate and understand the evolution of the free cash flow profile in a flat oil price environment, which is an important consideration.

Sure, so from a commitment standpoint what we’d be looking at over the next couple of years is to complete North Malay Basin, to complete Stampede and obviously continue the exploration that we have going on in particular in Guyana. So in 2017, the North Malay Basin will be coming online so we have $375 million in the budget this year that is essentially reducing our free cash flow by that $375 million. Now, we don't have exactly what the budget will be for North Malay Basin next year as far as pure capital, but it will be considerably lower than the $375 million, but again no matter what that number is it will be generating free cash flow. So as you look to 2017 you will get an improvement of free cash flow just related to North Malay Basin of $375 million. And then again you follow-on that with Stampede so you have $325 million this year not generating free cash flow. Again we don't have the budget set for 2017. I don't expect it to be that different in 2017 as you move forward with Stampede and so it won't be until 2018 that you’ll turnaround that $325 million of free cash flow.

That’s helpful. Thank you guys.

Thank you. And our next question comes from Evan Calio of Morgan Stanley. Your line is now open.

Hey guys, good morning guys. Just to start off with a follow-up to a prior cash question. What do you guys consider the minimum operating cash limits on the balance sheet? And I realize on most of the math that you supplied before on the call, you can currently support the dividend, given your balance sheet strength. How do you consider the dividend strategy in the context of the constrained cash flow environment? And the amount or the breadth of longer-term investment opportunities that you have as you navigate 2016?

Sure Evan. So again, as we go through that, I mean we are just on a good position probably relative to our competition with this $2.7 billion of cash. We don't need any cash flow from operations to fund our capital program, as I mentioned of $2.2 billion, plus the dividend if I round up to $300 million. So we can fund that completely out of our cash account and have $200 million left over in there. And there will be, if you want to sit at a minimum level you are somewhere around that, say at the $200 million that you want to at least keep in our system between the U.S. and internationally. But again we don't even need any cash flow from operations just to repeat that to fund the capital or dividend. So anything again as your estimate for cash flow from operations will just get added to that cash balance. We won't be near this any minimum levels as it relates to cash.

Yes, that makes sense. And I have a couple smaller follow-up items. Can you give a cost or EUR uplift from the 50-stage Bakken completions versus the 35-stage design?

Yes, so if you look at 2015 particularly at the back half of year when we had a lot of 50-stages coming online. We were at the top end of our guidance range so the 550 to 650 we were at the very top end of that. We average 650 for the whole year in 2015. And as we drill on the core of the core you know next year and do the 50-stage fracs we expect to be in the high-600 to the mid-700 range. So you're seeing that uplift, also on the IP rates you could see a similar sort of effect I mean the range we've given on the IP rate is 800 to 950 and obviously with 50-stage fracs on the IP rate you're going to be up there. One another point I want to make about you know the well costs on the Bakken. The well costs for the fourth quarter averaged $5.1 million per well, which is about a 28% reduction from the year ago and 4% reduction from Q3 again that lean manufacturing machine just continuing to work. We said that we expect cost next year to be broadly flat at that $5 million to $5.1 million per well level. But of course that math, the significant amount of ongoing improvement because embedded in that number of the $5.1 million is the 40% increase in stage count. So we expect to fully offset that increased cost due to the higher stage count with continued lean manufacturing gain. So again, a 20% uplift in production for basically the same cost is what you have this year. So obviously that's going to be good for returns.

And then I guess a similar spud to spud - I think it was an 18 day, or is that what that number is? We should assume?

Yes, it will improve again next year I mean this year we averaged about 22 wells per rig during the year that's going to increase to say, 24 or so next year.

Great. And then lastly for me, a small one. If you can share what you booked on North Malay expansion 2016, just so I know how much of that project value is potentially reflected in your reserve numbers?

Oh no, that was not - there was no addition to our reserves in 2015 for the North Malay Basin expansion.

Can you give us a number of what that - what is in there - what is in your - what you've booked or what you have as PUDs there?

Okay, so what we have for North Malay Basin and this is kind of you get to this unique reserve accounting of rules because we don't - during 2015 we did not have a significant amount of wells in the ground that we could book proved reserves on and as Greg mentioned we started the drilling program more - now ticking it off in 2016 to drill up the reservoirs. We didn't have that significant of reserves say initially. And then when you run it through the reserve accounting requirements because those proved reserves are low compared to the gas sale contract we can't book the reserves here in 2015. So what will happen is as Greg’s team just drills out in 2016, we’ll actually begin booking the reserves at North Malay Basin.

Okay. That’s helpful. I will follow-up offline.

Thank you.

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

Thank you and good morning.

Good morning.

I wanted to follow up on some of the Guyana questions. You mentioned that the early production system depends on the appraisal program. Can you talk more specifically about what you expect to learn with the Liza-2? And then the same kind of question for how the next three wells that you are drilling and planning this year differ and what the learnings could be from those wells as well.

Yes, I think so let's talk about Liza appraisal first. I mean we want to get a dynamic test that will tell us about potential compartmentalization in Liza. We also want to find where the contact is so that will be the primary two objectives of the appraisal wells in Liza. The exploration wells are basically the objective there is to figure out what we are seeing on seismic, is that replicable in other areas of the block, because we have a lot of look-alikes on seismic. So we want to get a well or two in a couple of the other things and see what running room we have on the block. We think there's a lot, but obviously you'll need some more wells to figure that out.

Great, thanks. And then my follow-up is with regards to M&A. You mentioned really going back a year valuations never really looked attractive from a consolidation perspective. And I wondered, A, if you could kind of comment on how those look now. And then B, recognizing that preserving balance sheet is one of your key objectives, is the opportunity set that you now see at Guyana and at Sicily so meaningful that it reduces your interest level and even considering shale consolidation?

Look, a fair question on M&A. We always look at the outside to see if there are opportunities that will make our portfolios stronger, improve our economic opportunities for investment and also not sacrifice our balance sheet strength and while values have come down just to reiterate while our priority is first and foremost the strength of our balance sheet and obviously the companies really well positioned with our $2.7 billion of cash at the end of the year, one of the strongest balance sheets and liquidity positions among our peers. We further strengthen that balance sheet by the further reduction in our spending for 2016 to the $2.4 billion number. We’re talking about; it's about value not volume. So the whole focus is the balance sheet and yet at the same time it's very important that the company, we are in a long-term business. Everybody is thinking short-term that we invest for future growth on a disciplined and focused basis and we feel we’re extremely well positioned with the growth options that we have both in North Malay Basin and Stampede, but also obviously Guyana that the company is going to benefit quite a bit and our shareholders as well as oil prices recover ultimately with these growth options that we’ve already assembled. So we feel pretty good about what we’ve already captured and therefore M&A is very low on the priority list.

Great. Thank you.

Thank you. And our next question comes from Roger Read of Wells Fargo. Your line is now open.

Good morning.

Good morning.

I guess two questions, one on the Bakken in terms of the efficiencies. Do you continue to do testing in this environment or with the two-well program strictly we should think about it as development and maybe putting further efficiencies on a hold for now? Or it's a drive for further efficiencies?

No, I think part of lean manufacturing is every day you look for the next improvement. So in terms of piloting though I think we've done the infills nine and eight and very successful, 50-stage fracs been very successful. So those now will become our standard design obviously in the core of the core. But every day, we are looking for the next improvement right. So that that drive will continue, that will go on, and we are constantly trying to improve everything across our business there. And that’s all part of the lean manufacturing philosophy.

Okay, thanks. And then as you think about and you mentioned earlier in the beginning of the call, opportunities in the deepwater you have been able to get in; others are struggling on the cash flow side. As you look at some of those partners and you think about taking these projects forward, either on an appraisal well or ultimately full development, if it works out that way, what sort of I guess roadblocks may we run into, where partners simply don't want to fund those next steps? And how do we - it has been a long time since we've had a downturn like this. How should we think about the workout of that process over time?

Well, certainly if you think about what we are in currently so Sicily, clearly Chevron wants to move forward or aligned to that on the appraisal. ConocoPhillips obviously moved forward with Melmar, Guyana moving forward with Exxon; Nova Scotia BP moving forward. So we don't really see any partner risk of people not wanting to move forward. Regarding your question, in the opportunity space. There is a lot of opportunity out there, very good prospects, very low entry cost, but we are going to be extremely disciplined and it's going to have to be really good in order for us to even consider adding it to the mix. And Melmar was one example of something that was very good and we made the decision to get in, but we are going to be extremely disciplined and very selective on how we do that.

Okay, great. Thank you.

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

Thank you. The first question I wanted to ask was did I understand correctly that the reduced spending at North Malay and Stampede was largely on cost saving? And if so, can you indicate where, what sort of savings we are talking about? And also was I correct that the timelines to first oil are intact?

I’ll start with the timelines to first oil are intact. When I was talking about cost savings, it was across the portfolio, we had a mix of that $600 million worth kind of a half of it was cost savings and a half of it was deferment of activity. So there is a mix on North Malay Basin and Stampede, it's not like that was all cost savings.

Okay. And then thinking about - and staying on the theme of cost savings and the offshore, I was just wondering can you comment broadly about your current view of industry efforts to reduce offshore development costs? And specifically I am thinking of back when you said that Guyana looked great at $80 a barrel, but not as much at lower oil prices. Other than waiting for a higher future oil price, do you see developments unfolding that can make a play like Guyana better able to attract capital in a better, but still moderate oil price environment?

Yes, I think so I mean if you look at cost reductions if you look at the onshore I would say the progression of cost reductions in the onshore has been much more rapid than the offshore. For very practical reason the offshore fleet - there's still a lot of rigs on contract at relatively high prices. The yards are full, still full as you kind of look around the globe so we see that really opening up though as rigs come off contract in the offshore as the yards become not at capacity those costs are going to come down as well. It’s just taking longer than the offshore because they are very busy. So I think if you are developing something in that timeframe of 2017 or so I think you really get the full benefit of that. We are already seeing those benefits in Guyana with the rig rates that Exxon was able to get Guyana also the seismic boat rates that they were able to get Guyana. So you are starting to see some of that come through the value chain, but more they come on the offshore.

And if I could just follow up on that a little bit further. I was also wondering, because I'm sure you are watching, do you see anything with regard to trends, like trying to standardize subsidy approaches, things on the engineering side that might suggest that you can drive costs down on that basis as well?

Yes, I think so. I think there is nothing like a low price for companies to get innovative and I know a lot of my service company colleagues in the major oil companies are all getting together talking about how can we better standardizes an industry to lower the overall cost structure of the industry. We are doing that in our developments, for example we are using a lot of the same things that came out of Tubular Bells and Stampede making sure there's not as much bespoke equipment that really tends to drive your cost up.

Okay, that was very helpful. I appreciate it. Thank you.

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

Hey guys. You addressed the M&A question from the buy side. I guess maybe I’ll try it from the sell side. You have been a net seller of assets for more than three years now. Has that pretty much run its course with the Algeria deal? Or are you still looking to monetize additional assets other than of course the Bakken MLP?

A fair question. We will always look to optimize our portfolio you know in the normal course of business. So we will continue to take that approach.

Any particular geographies that come to mind?

No.

Okay, all right. I will leave it there. Thanks.

Thank you. And our next question comes from Phillips Johnston of Capital One. Your line is now open.

Hi, guys thanks. Just a follow-up on Ed's question earlier. On the declines on the Bakken, if we assume you continue to run two-rigs throughout this year and next. Can you give us an update on what sort of cushion you have on your MBCs if we just assume your operator production continues to decline and if we assume production from other operators also declines in the basin? You've got some incremental volumes I think coming in through the Hawkeye system, which should sort of help offset that. But can you just give us an update on your latest thinking there, and whether or not that is something that we should be concerned about?

First of all, no I guess is the answer on an overall basis, I just wanted to let you know in our supplement that is being posted we actually have the 2016 minimum volume commitments there, maybe I can just walk you through that from a processing standpoint this 2016 commitment is a 186 million scuffs a day. In the fourth quarter we’re right at that 186 and as I mentioned earlier we had unplanned downtime in the third quarter we’re up at 210 in the second quarter 202, don't see any issues with that with the two-rig program. From the pipeline standpoint we gathered 50,000 barrels of oil per day and the commitment is 45 in 2016 and gas gathering was 198 in the fourth quarter and the minimal vol is 189 do not see an issue there. So the one small thing that we may see and we think it’s under $10 million save to us, is going to be on our logistics on the rail. Because as we mentioned earlier the economics now are favoring more to the pipeline but obviously that can change. So just from in the fourth quarter our terminal throughput was 62,000 barrels of oil per day the minimum volume commitment is 73,000 back in the second quarter we had 82 going through that terminal. But as far as the rail terminal crude loading, we were at 42,000 barrels a day the minimum volume coming is 38 and for rail services is 43,000 barrels a day for the minimum volume commitment and the fourth quarter was at 43,000. So bottom line we do not expect any real issues from the minimum volume standpoint and the build-out for the Hawkeye south of the river will begin to add throughput back into the system for us.

And just on that Hawkeye system, have you quantified what sort of incremental volumes you are expecting from that?

Yes, if you hold on one second I can give you we had not quantified per se what are the additional volumes that absolutely will be coming through, but I can give you capacity from the south of the river infrastructures so we are adding approximately 75,000 barrels a day from the oil standpoint and 50 million cubic feet per day from the gas compression. Now the project itself is also going to add interconnection points for the capture of third-party oil volumes into the midstream system as well.

Okay, great. Thank you.

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

Yes, hi. Just some quick ones for me. With Melmar, did COP approach you or did you approach COP in terms of the farming?

It’s been a joint thing; we’ve been talking to each other for the last year and a half about Melmar.

Okay, that's fine. With your PUD reductions, was it all price, or just some of it reduced activity?

Actually, it was both so if you look at the reductions as we mentioned in our opening remarks there were 282 million barrels of price related revision, 50 million of that was related to the Bakken five-year rule, so that’s just purely reduced rig counts that push wells out of the five-year window so that was about 50 million barrels. The remaining 234 of that 282 is really across the portfolio, but it split about 60% Bakken and 40% offshore. So that kind of gives you a relative sense of where those movements were.

Okay, great. Last one for me regarding the Bakken, you are increasing the number of stages. Are you changing the sand loadings at all? For your fracs?

Not really, although it does vary depending on where you are in the field. Typical sand loadings are anywhere from 75,000 to 100,000 pounds per stage, and just depending on where you are in the field we modify that based on the data.

Okay. And what drove all decline rates? Still high 20s?

For the portfolio or what?

For the Bakken portfolio, yes.

Well, I mean if you think about the - we averaged 112,000 barrels a day this year, the range is 95 to 105 so if you pick the middle that gives you a sense of how much the Bakken is going to decline year-on-year, right.

Okay, all right. Thanks.

Okay. You bet.

Thank you. Ladies and gentlemen, this concludes today’s conference. Thank you for your participation. And you may now disconnect. Everyone have a great day.