Jay R. Wilson - VP, Investor Relations John B. Hess - CEO John P. Rielly - SVP and CFO Gregory P. Hill - President and COO

Doug Leggate - Bank of America Merrill Lynch Guy Baber - Simmons Brian Singer - Goldman Sachs Ryan Todd - Deutsche Bank Evan Calio - Morgan Stanley Ed Westlake - Credit Suisse Paul Cheng - Barclays Capital David Heikkinen - Heikkinen Energy Advisors Phillips Johnston - Capital One South Coast Jeffrey Campbell - Tuohy Brothers Investment Research Roger Read - Wells Fargo Pavel Molchanov - Raymond James

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2014 Hess Corporation Conference Call. My name is Lisa 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. Jay R. Wilson: Thank you, Lisa. 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 Web-site, 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' 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 Web-site. With me today are John Hess, Chief Executive Officer; Greg Hill, President and Chief Operating Officer; and John Rielly, Senior Vice President and Chief Financial Officer. I'll now turn the call over to John Hess. John B. Hess: Thank you, Jay. Welcome to our fourth quarter conference call. I will provide some key highlights from 2014 and guidance for 2015. Greg Hill will then discuss our operating performance and John Rielly will review our financial results. Before covering the quarter and the year, I would like to provide some thoughts on the dramatic change in the oil market with the price of Brent dropping from $115 per barrel in June to approximately $49 per barrel today. While this price drop poses serious challenges for the entire industry, Hess continues to maintain a strong financial position with $2.4 billion of cash on our balance sheet at year-end and a debt-to-capitalization ratio of 21%. The current market weakness is driven by strong supply growth from U.S. unconventionals and weaker than expected global demand. In the past, during periods of oversupply, Saudi Arabia and a few other OPEC members would have reduced production to stabilize prices. This time, they decided to leave it to the market to rebalance, and consequently oil prices have plummeted. The near-term impact is that many companies including ours are announcing significant reductions to their global investment programs which will begin to decrease unconventional and conventional production growth in the latter half of 2015 and even more so in 2016. All of the steps we have taken in the last several years have positioned us well to manage in this environment. In addition to our strong balance sheet and liquidity position, our transformation to an E&P company has created a resilient portfolio of world-class assets that is balanced between unconventionals which offer lower-risk growth in a high price environment with the flexibility to moderate investment in a lower price environment, and our offshore assets which generate significant cash flows and also provide future growth opportunities. Our financial strategy which we reviewed during our Investor Day last November is, first, to invest for returns; second, to manage our business to be cash generative over the long-term; third, to use our balance sheet in a given year like 2015 to fund the shortfall in operating cash flow; and finally, to maintain our investment-grade credit rating. In keeping with this strategy, we are taking a disciplined approach to protect our financial strength in the current environment while preserving our long-term growth options. As announced on Monday, we will reduce our 2015 capital and exploratory expenditure budget to $4.7 billion, approximately 16% lower than our 2014 actual spend. We are reducing our 2015 annual spend in the Bakken to $1.8 billion compared to $2.2 billion in 2014 and plan to decrease our rig count to eight rigs by the second quarter compared to 17 rigs in 2014. In addition, we are actively pursuing cost reductions with service providers across our supply chain. As for our share repurchase program, we are significantly moderating the pace of share repurchases in 2015 to preserve liquidity in the current oil price environment. Since commencement of the program in August of 2013, we have repurchased 62.8 million shares for $5.3 billion. Now I would like to comment on some of the key highlights of our earnings release as well as our major accomplishments from 2014, which overall was a year of outstanding operating performance. First, 2014 adjusted net income was $1.3 billion and cash flow from operations before changes in working capital was $5.2 billion. Compared to 2013, our results were positively impacted by lower cash operating costs and exploration expenses which were more than offset by lower realized selling prices and higher depreciation expenses. Second, in 2014, production averaged 329,000 barrels of oil equivalent per day or 318,000 barrels of oil equivalent per day on a pro forma basis excluding divestitures in Libya. In 2015, we forecast production to average between 350,000 and 360,000 barrels of oil equivalent per day excluding Libya. Third, in 2014, we replaced 158% of production at an FD&A cost of approximately $28.75 per barrel of oil equivalent. At year-end, our proved reserves stood at 1.4 billion barrels of oil equivalent and our reserve life was 11.7 years. Now I will review some of the accomplishments from 2014 starting with the Bakken where Hess continues its industry leadership. In late March, the expanded Tioga gas processing plant came online, which is key to our commitment to sustainable growth in North Dakota and is enabling us to significantly reduce flaring. The expansion increased the plant's gross inlet capacity to 250 million cubic feet per day and more than doubled its natural gas liquids processing capacity. Throughout 2014, our Bakken team has continued to drive down drilling and completion costs and the productivity of our wells is among the highest in the industry. In the fourth quarter, we achieved the important milestone of net production exceeding 100,000 barrels of oil equivalent per day. Hess has a strong acreage position in the Bakken with more DSUs in the core of the play than any other competitor. For 2015, our net production from the Bakken is expected to average between 95,000 and 105,000 barrels of oil equivalent per day compared to 83,000 barrels of oil equivalent per day in 2014. We are still working to monetize our Bakken midstream assets through a master limited partnership. We expect the IPO to occur in 2015 subject to market conditions and we will continue to provide you with further updates as appropriate. Turning to offshore, we continue to employ our top quartile drilling and project delivery capabilities. A major accomplishment in 2014 was the startup of the Tubular Bells Field in the deepwater Gulf of Mexico in which Hess has a 57.1% interest in the project and is the operator. The field achieved first production approximately three years after project sanctioned. Net production is expected to average between 30,000 and 35,000 barrels of oil equivalent per day in 2015. The Stampede project in the deepwater Gulf of Mexico in which Hess has a 25% working interest and is operator received full partner sanction for development in October 2014. Chevron, Statoil and Nexen, each have a 25% working interest. Total recoverable resources for Stampede are estimated in the range of 300 million to 350 million barrels of oil equivalent and first production is expected in 2018. In Malaysia, full field development of the North Malay Basin project continue to progress, which should result in net production increasing to 165 million cubic feet per day in 2017. Hess is the operator with a 50% interest. In terms of exploration, our strategy is to deliver long-term value by focusing on proven and emerging oil prone plays in basins we understand well and that leverage our capabilities. As we announced at our Investor Day, we secured farming opportunities in three deepwater blocks, Sicily in the Gulf of Mexico with Chevron as operator; the Stabroek block in Guyana with Esso E&P Guyana Limited as operator, and in Nova Scotia with BP as operator. In summary, 2014 was a year of outstanding execution and strong operating results with industry-leading performance in our unconventionals and offshore business. Our Company is well-positioned to manage through the current price environment with a strong balance sheet and resilient portfolio. Our 2015 budget reflects a disciplined approach to maintaining our financial strength and flexibility while preserving our long-term growth options. Just as important, we have top quartile operating capabilities and some of the best people in the industry to execute our plans and maximize shareholder value. I will now turn the call over to Greg Hill. Gregory P. Hill: Thanks, John. I'd like to provide an operational update on our progress in 2014 and our plans for 2015. In 2014, we demonstrated strong delivery of our plan across our unconventionals and offshore businesses and began rebuilding a top-quality exploration organization and portfolio. We exceeded the top end of our production guidance range while achieving a material reduction of approximately $200 million in our capital and exploratory spend against budget in response to the lower price environment. In our unconventionals business, we delivered on our Bakken commitments while continuing our cost reductions and successfully progressing our infill pilots, leading to a significant increase in well inventory. In the Utica, results continued to encourage our transition from appraisal to early development. Offshore, we delivered first production from Tubular Bells, achieved full partner sanction on Stampede and made steady progress at Valhall and at North Malay Basin. We drilled some excellent wells at South Arne and Equatorial Guinea, successfully conducted our appraisal of Ghana and advanced our Equus project in Australia. Starting then with production, in the fourth quarter net production averaged 352,000 barrels of oil equivalent per day on a pro forma basis excluding divestures in Libya. On that same basis, for the full year 2014 we achieved net production of 318,000 barrels of oil equivalent per day which exceeded our beginning of the year guidance of 305,000 to 315,000 barrels of oil equivalent per day. Looking forward, in 2015 we forecast net production to average between 350,000 and 360,000 barrels of oil equivalent per day excluding Libya, an increase of between 10% and 13% respectively over a pro forma production in 2014. On the same basis, we forecast net production in the first quarter of 2015 to average between 330,000 and 340,000 barrels of oil equivalent per day which takes into account planned maintenance in the deepwater Gulf of Mexico and the North Sea. Turning to the Bakken, in 2014 we continued to demonstrate excellent performance. We brought 238 new operated wells online and full-year net production averaged 83,000 barrels of oil equivalent per day, an increase of 24% versus 2013 and well within our guidance of 80,000 to 90,000 barrels of oil equivalent net per day. In the fourth quarter, net production averaged 102,000 barrels of oil equivalent per day, a 19% increase from the previous quarter and a 50% increase from the fourth quarter of 2013. In 2014, our 30 day initial production rates have average between 800 and 950 barrels of oil equivalent per day, well above the industry average. Our continued focus on applying lean manufacturing practices to our operations enabled us to continue to drive down our Bakken drilling and completion costs with the fourth quarter averaging $7.1 million per well versus $7.6 million per well in the year ago quarter. We expect to further reduce costs both through ongoing efficiencies and by proactively addressing our cost structure in collaboration with our suppliers. Based on our top quartile drilling and completion costs and the productivity of our wells, we continued to deliver some of the highest return wells in the play. As we mentioned on our last call and at our Investor Day last November, we have now moved to 13 wells per DSU as our standard basis of development. Also our two existing 17 well per DSU pilots are performing in line with expectations. So we plan to increase the total number of these to five in 2015. The quality of our Bakken position provides a robust forward well inventory that's substantially all held by production. Given the current pricing environment, it makes sense to diverse some drilling until oil prices have moved higher. With this in mind, in 2015 we intend to reduce our activity from 14 rigs in the first quarter to eight in the second quarter, giving an average of 9.5 rigs for the year compared to 17 rigs in 2014 and we will remain flexible to respond to prices as appropriate. Our 2015 capital budget for the Bakken is $1.8 billion, a reduction of some 18% from last year. With our reduced rig program, we nevertheless expect to drill and complete approximately 180 wells in 2015 and bring approximately 210 new wells online in total, compared to 238 new wells online in 2014. Bakken net production is expected to average between 95,000 and 105,000 barrels of oil equivalent per day over the full year, an increase of 14% to 27% respectively on an annualized basis versus 2014. Looking further ahead, the quality of our acreage and our well inventory on a 13 well per DSU development plan continues to support our longer-term net production target of 175,000 barrels of oil equivalent a day for the Bakken. However, the timing of when this can be reached will be a function of oil price. Moving to the Utica, the appraisal and early development of our 45,000 core net acres in the Hess-CONSOL joint venture continues to be encouraging. In 2014, the joint venture drilled 38 wells, completed 36 wells and brought 39 wells on production. Our drilling and completion costs on a dollars per foot and dollars per stage basis moved steadily lower by 28% and 17% respectively in 2014 as we began to apply the same lean manufacturing techniques that we used in the Bakken. As we move into development mode and continue to work with our suppliers in the lower oil price environment, we expect drilling and completion costs will be further reduced. Net production for the year in the Utica averaged 9,000 barrels of oil equivalent per day. In the fourth quarter, net production averaged 13,000 barrels of oil equivalent per day compared to 2,000 barrels of oil equivalent per day in the year ago quarter. The joint venture intends to execute a two rig program in the core of the wet gas window during 2015. Our budget of $290 million for 2015 is dedicated to drilling 20 to 25 joint venture wells and we expect to bring 25 to 30 new wells online. In terms of net production, we expect to average between 15,000 and 20,000 barrels of oil equivalent per day in 2015. Turning to our offshore business, in the deepwater Gulf of Mexico we commenced production at our Tubular Bells Field in which Hess holds a 57.1% working interest and is operator. Sanctioned in October 2011 and fast-tracked to first oil in approximately three years, the project underlines Hess' ability to successfully execute complex deepwater development projects. The first three producers are now online and production continues to build. A fourth producer reached target depth and encountered 290 feet of net pay. Current net production from the field is approximately 26,000 barrels of oil equivalent per day and we plan to bring on one additional producer and continue to increase production over the course of 2015. We forecast net production to average between 30,000 and 35,000 barrels of oil equivalent per day over 2015. Also in the Gulf of Mexico, on October the Stampede development project in which Hess holds a 25% working interest and is operator was sanctioned by all four partners. Drilling is expected to commence utilizing two rigs in late 2015 with first oil targeted for 2018. In North Malay Basin in the Gulf of Thailand in which Hess holds a 50% working interest and is operator, progress continues on the first phase of field development. Engineering, procurement and construction activities are underway and commencement of development drilling is planned by Q4 of 2015. Full year net production averaged 40 million cubic feet per day through the early production system in 2014 and is expected to stay at this level through 2016. Upon completion of the full field development project in 2017, net production is planned to increase to 165 million cubic feet per day. In Norway, at the BP operated Valhall Field in which Hess has a 64% interest, fourth quarter net production averaged 30,000 barrels of oil equivalent per day compared to 37,000 barrels of oil equivalent per day in the year ago quarter, due in part to scheduled maintenance downtime in the fourth quarter of 2014. Full year 2014 net production averaged 31,000 barrels of oil equivalent per day, an increase of 8,000 barrels of oil equivalent per day over the previous year. In 2015, we expect Valhall net production to average between 30,000 and 35,000 barrels of oil equivalent per day. In Ghana, Hess and its partners are continuing to incorporate the data from the appraisal drilling in new 3D seismic into our models with a view to a sanction decision during 2016. Offshore Australia, we signed a letter of intent with the North West Shelf joint venture to process gas through LNG facilities at Karratha. Next steps will be to finalize commercial terms, complete FEED for the project and engage with LNG buyers in 2015 aiming for a sanction decision in 2017. Moving to exploration, in Kurdistan where Hess has a 64% interest, we have suspended drilling of the Shireen-1 well on the Dinarta block due to drilling difficulties and are assessing options to complete the program. In the Gulf of Mexico, Chevron has begun drilling operations on the Sicily well where Hess has a 25% interest, which is targeting a four-way closure in the outward Paleocene. The operator expects to reach target depth in the third quarter of 2015. In Guyana, we expect the operator, Esso Exploration and Production Guyana Limited, to spud the offshore Liza-1 well in the Stabroek License in which Hess holds a 30% interest in March 2015. Liza is a large amplitude-supported Upper Cretaceous fan play. Turning to offshore Nova Scotia where we hold a 40% license interest in blocks where BP is operator, Hess has been approved as a partner by the regulatory authorities and drilling is expected to commence in 2017. In closing, 2014 was a year of exceptional execution and delivery on all fronts which is a tribute to the outstanding people of Hess. Although 2015 promises to be a challenging year for the industry, I believe Hess' portfolio and prospects have never been stronger. I will now turn the call over to John Rielly. John P. Rielly: Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2014 to the third quarter of 2014. Adjusted net income, which excludes items affecting comparability of earnings between periods, was $53 million in the fourth quarter of 2014 and $377 million in the previous quarter. We estimate the fourth quarter decline in selling prices lowered net income by approximately $300 million net of hedging gains compared to the third quarter. On an unadjusted basis, the Corporation incurred a net loss of $8 million in the fourth quarter of 2014 compared with net income of $1,008 million in the third quarter. Turning to exploration and production, E&P net income in the fourth quarter of 2014 was $92 million and $441 million in the third quarter. E&P adjusted earnings were $147 million in the fourth quarter and $412 million in the previous quarter. The changes in the after-tax components of adjusted net income for E&P between the third and fourth quarter were as follows. Lower realized selling prices decreased earnings by $303 million. Higher sales volumes increased earnings by $132 million. Higher exploration expenses decreased earnings by $56 million. Higher DD&A expense decreased earnings by $22 million. All other items net to a decrease in earnings of $16 million, for an overall decrease in fourth quarter adjusted earnings of $265 million. Our E&P operations were over-lifted compared with production by approximately 1 million barrels in the fourth quarter, resulting in an increased after-tax income of approximately $9 million. The E&P effective income tax rate excluding items affecting comparability of earnings was 58% for the fourth quarter and 41% in the third quarter of 2014. The increase in the effective tax rate reflects the impact of higher Libyan production. When the Libyan operations are also excluded, the effective tax rate was 41%. Turning to corporate and interest, corporate and interest expenses after income taxes were $97 million in the fourth quarter of 2014 and $82 million in the third quarter. The increased costs in the fourth quarter were a result of lower capitalized interest and higher professional fees and other administrative expenses. Turning to cash flow, net cash provided by operating activities in the fourth quarter including an increase of $80 million from changes in working capital was $1,057 million. Capital expenditures were $1,566 million. Common stock acquired and retired was $1,077 million. Net repayments of debt were $37 million. Common stock dividends paid were $71 million. All other items amounted to an increase in cash of $18 million, resulting in a net decrease in cash and cash equivalents in the fourth quarter of $1,676 million. Turning to our stock repurchase program, during the fourth quarter we purchased approximately 13.3 million shares of common stock bringing total 2014 purchases to approximately 43.4 million shares at a cost of approximately $3.7 billion. As of January 27, total program to date purchases were 62.8 million shares at a cost of $5.27 billion or $83.91 per share. Turning to our financial position, we had $2.4 billion of cash and cash equivalents at December 31, 2014, up from $1.8 billion at the end of last year. Total debt was $6 billion at December 31, 2014 and $5.8 billion at December 31, 2013. The Corporation's debt-to-capitalization ratio was 21.2% at December 31, 2014 and 19% at the end of 2013. Going forward, we expect to utilize our strong cash position and balance sheet to manage through this low commodity price cycle. Turning to 2015 guidance and starting with exploration and production, in addition to the production and capital expenditure guidance provided by John and Greg, I would like to provide estimates for certain 2015 metrics based on our expected production range of 350,000 to 360,000 barrels of oil equivalent per day which assumes no contribution from Libya. For the full year 2015, E&P cash costs are expected to be in the range of $19.50 to $20.50 per barrel, which is down approximately 5% before any realization of our cost saving initiatives. Depreciation, depletion and amortization expenses are expected to be in the range of $28.50 to $29.50 per barrel reflecting greater contributions from Bakken and Tubular Bells which both have higher DD&A rates than the portfolio average. Total production unit costs for 2015 are estimated to be in the range of $48 to $50 per barrel. Full year 2015 exploration expenses excluding dry hole costs are expected to be in the range of $400 million to $420 million. For the first quarter of 2015, excluding Libyan operations, cash costs are expected to be in the range of $20.50 to $21.50 per barrel due to maintenance downtime in the Gulf of Mexico and North Sea, and DD&A rates are expected to be in the range of $28.50 to $29.50 per barrel, for total production unit costs of $49 to $51 per barrel. Exploration expenses in the first quarter excluding dry hole costs are expected to be in the range of $90 million to $100 million. Based on current Strip oil prices, we are forecasting a pre-tax loss for 2015 and as a result the E&P effective tax rate excluding items affecting comparability is expected to be a benefit in the range of 38% to 42% excluding Libyan operations. On the same basis as the full-year guidance, the effective tax rate for the first quarter of 2015 is expected to be a benefit in the range of 40% to 44%. Turning to corporate and interest, for the full year of 2015 corporate expenses are estimated to be in the range of $120 million to $130 million net of taxes, and interest expenses are estimated to be in the range of $205 million to $215 million net of taxes. For the first quarter of 2015, corporate expenses are estimated to be in the range of $30 million to $35 million net of taxes and interest expenses are estimated to be in the range of $50 million to $55 million net of taxes. Before I conclude my remarks, I would like to inform you the quarterly earnings supplement posted on our Web-site has been augmented this quarter to include more detailed information regarding our Utica shale operations. I will now turn the call over to the operator for questions.

[Operator Instructions] Your first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Please proceed.

John and Greg, I guess I haven't spoken to you guys yet, so Happy New Year. I wondered if I could take two questions please. The first one is really on the prospective cash burn for the current year. I understand the balance sheet is in terrific shape given all the moves from last year, but what are you guys assuming in terms of the commodity environment, because obviously if oil prices don't recover, this level of spending pretty much burns through your cash flow pretty quickly, so can you give some framework as to how the CapEx may change if oil prices don't recover, and I have a follow-up please? John P. Rielly: Sure, Doug. I appreciate the question and the difficulty with the environment but we're not going to speculate right now on where oil prices are going to end up through 2015. So now having said that, we are well-positioned going into this low priced commodity cycle. So first, proactively we have been reducing our CapEx, we did reduce that as you saw in 2014 and we've made further reductions in 2015. And as was mentioned by both John and Greg, we have the ability to reduce it further if needed. We are reducing our stock repurchase program, we're significantly moderating that, and then as you mentioned with our strong cash position, we have $2.4 billion of cash, and our strong balance sheet position, we can utilize this cash and the balance sheet to get through this low priced commodity cycle. So we think we're in great position from that standpoint and we're just going to see where oil prices end up throughout the year.

Great. Thanks, John. My follow-up is for Greg. Greg, we've got something like last time I looked about a $20 contango and the oil price for the next three years which approximates I guess to about two-thirds, 70% of production from our Bakken well, can you help us understand the decision to go ahead and retain the completion rate at such a high level, and talk to what does the new type curve look like for the 2015 program, and I guess finally, what are your expectations for drilling and completion cost reductions as you move forward over in this cost environment, a low price environment? I'll leave it there, thank you. Gregory P. Hill: Thanks, Doug, that's really three questions, so let me try and answer all. First of all, at current prices, what you were talking about was really, what are your returns in the Bakken, why should you go forward? So just some context, as we mentioned at our Investor Day in November, recall that we have 60% more DSUs in the core of the Bakken than any other operator, and our 2015 drilling program is focused in the best areas of this core. Secondly, as you know our well costs are some of the lowest in the industry, our well IPs are well above the industry average. So that means we're delivering some of the highest returns in the industry. So given all these advantages, our current prices were delivering incremental returns that meet or exceed our hurdle rate. And finally given our large position in the core, we see a multiyear inventory of drilling at these current activity levels and pricing. I think the final thing I would say is, we really want to maintain capability. We have a world-class lean manufacturing team and capability and we have a strong desire to maintain that as much as possible. As far as service cost, we're starting to see some response and we're in very active discussions with all of our suppliers. So it's premature to kind of speculate on where those are going to go, they're going to go down but I can't tell you how much or how fast at this point in time. I think the third thing relating to type curves, we're going to be in that 800 to 950 kind of an initial IP rate in this core of the core. So we'll be probably towards the upper end of that but that's probably still a good range for us.

Good, thanks very much. When you said you've got several years of drilling, you mean not type of well curve, you have a multiyear inventory that you can continue to focus on? Gregory P. Hill: Yes, at current activity levels and current pricing we have a multiyear inventory to go forward.

With a positive return? Gregory P. Hill: Yes, sir.

Okay, great. I'll leave it at that. Thanks very much for answering the questions.

Your next question comes from the line of Guy Baber with Simmons & Company. Please proceed.

John, you made a comment in the prepared remarks about the impact that lower spending could have on production for the industry overall, especially as we move into 2016. So I was hoping you could elaborate on those comments and maybe what you might expect for the Hess portfolio specifically in 2016, and then in the Bakken especially. I'm assuming spending remains relatively constrained relative to the plans presented at the November Analyst Day, if you could just give maybe some thoughts around kind of the 2016 production trajectory? John B. Hess: Yes, in terms of the industry, a lot of the announcements of companies' plans including ours have been announced for 2015 where their significant reductions and their unconventional programs and as you all know many unconventional wells on the oil side have about a 70% decline in the first year, and as these programs through the year get feathered in with reduced rigs running, the growth year on year of unconventionals being up 1 million barrels a day or so year versus year in the U.S. because of unconventional, we see that attenuating quite a bit to where it flattens out probably the beginning of next year. So a lot of the unconventional growth both for the industry and ourselves at the rig counts being anticipated should flatten out, and our Company itself also will have that but it's great pointing out we're going to still be able even in these oil prices to drill very attractive returns in the core of the core and we're very fortunate to be in a position to do that for several years. So our whole focus here is to maintain our financial strength and flexibility while still preserving our long-term growth options, but we do believe with the decrease in investment programs for the industry and the consequent levelling out of production growth, oil prices will recover starting next year.

That's very helpful. And then one follow-up for me in the Bakken also, I was hoping you could talk a little bit about the relationship between well count which was down 12% year-over-year and the rig count which was obviously down much more substantially, but could you just talk a little bit about the backlog of drilled but uncompleted wells the over what timeframe you might bring those online through 2015 and what impact that could have to production? And then also, if you could just comment on the implicit efficiency gains for rigs that you're assuming kind of in 2015, because it seems as if you guys were already expecting some efficiency gains that you talked about at the November Analyst Day, but your numbers seem to imply even greater efficiency gains, and just trying to get a sense of how conservative you might feel those are and what type of opportunities did you see with some of the tailwinds from a lower commodity price environment? Gregory P. Hill: Let me hit the rig question first. I think really the question you're asking is that rig count is going down about 45%, yet the capital is only going down by about 18%, so why is that. And that's all because of the continuing efficiency gains from our lean manufacturing. So we expect to drill approximately 20% more wells per rig in 2015. So that's 18 plus wells per rig in 2015 versus 15 per rig in 2014. So what that means is we expect to bring online 210 new wells in 2015 versus 238 in 2014. So you're exactly right, there is quite a bit of efficiency gains expected in our plans. And I think that broadly answers the question that you were trying to ask.

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

Sorry for the delay there. Two questions. First, can you talk to the service and development cost reduction that you are seeing versus expecting and how offshore compares to onshore? Gregory P. Hill: First of all, again as I said in my remarks on the last question, here it's early days, right. I mean the discussions are ongoing as we speak with suppliers. So it's premature to speculate how low will it go, how quickly will you see those cost reductions throughout the value chains. In respect to offshore, recall we contracted two rigs even before the price environment to next generation deepwater drilling rigs. We contracted those for 400,000 a day. That was a major reduction over what those rigs would have contracted for say even 18 months ago, alright. Now, if you think about the offshore though, this is probably the best time to be in the development phase of an offshore project because we know and we are seeing already some significant cost reductions in all those offshore services. So as you develop and then those developments come online, in Stampede's case in 2018, it's probably the best time in the cycle to be in development mode for those projects.

Great, thanks. And my follow-up is, going back to your November Analyst Meeting, you indicated that Hess was interested in acquisitions, but I may be paraphrasing here, but the valuations at the time were not attractive despite the drop from June highs. That valuations in oil prices have obviously changed since then, and wondered if you could give us your latest thoughts on M&A and what may or may not make sense for Hess? John B. Hess: Appreciate that. Obviously as opportunities arise, we'll be in a position to evaluate them with the strong financial position we have. It would have to still make sense both strategically and financially. So we're definitely on the lookout and we'll be in a position to move forward if something made sense, but at the same time our priority still will be to maintain our financial strength and flexibility and preserve our long-term growth options.

Your next question comes from the line of Ryan Todd with Deutsche Bank. Please proceed.

Maybe a follow-up on one of the earlier questions on CapEx, I realize that the near-term volatility in commodity makes it very hard, as you talked about, in 2015, but maybe if we think about the medium term view, say the next two to three years, I mean how should we think about your willingness to outspend in terms of [indiscernible] suggest on a multiyear basis there was an effort to be cash positive, is that still the view and how does that inform kind of the two or three year view from here? John P. Rielly: So it is clearly our focus that over the long-term that we want to generate free cash flow. So obviously with the significant decline, it's come on fast, and we are in a good position with our cash levels of $2.4 billion in our balance sheet to spend, to utilize some of that cash and balance sheet strength to get through this cycle. So with the current uncertainties, in the mid-term and long term, we naturally have a range of price scenarios under which we're evaluating our forward activity and production outlook. So again, the pace of spend and the growth will depend on that oil price and that's what's going to impact our longer-term growth rate as well as our free cash flow over the period. But we will continue to focus over the long-term to generate free cash flow.

So I guess should we think like on a two years out, three years out, there's still a target to be cash flow positive at that point and depending on commodity you'll adjust accordingly for 2015? John P. Rielly: Yes.

Okay. And then maybe a follow-up, I know we've talked to a decent amount about drilling and completion cost in the Bakken, can you say what was the implied drilling and completion cost per well in the 2015 budget, did you make any assumption, I know you made assumptions for efficiency gain, did you make any assumption for cost deflation, and if not, is that a source of potential downward pressure on the budget from here? \ John P. Rielly: Yes, I think so, all-in – so I'm going to talk DC&F, all in cost assumptions in 2015 was 8.3 and that gives you a D&C cost of around 6.8. So that's the assumption in our current plan.

Okay, and that's apples-to-apples versus the 7.1 number that you saw in 4Q? John P. Rielly: Yes, it is, and that 7.1 is D&C.

Okay, great. Thanks. I'll leave it there.

Your next question comes from the line of Evan Calio with Morgan Stanley. Please proceed.

This is maybe a follow-up question on the Bakken and the well inventory drawdown, it looks like you added something 30 wells to the uncompleted Bakken inventory in the quarter, but can you give us the number of what the current total inventory of uncompleted and completed yet not tied in wells are and as the inventory drawdown for 2015 agnostic to the commodity price or should we kind of expect that to grow into recovery, so I understand how that works? Gregory P. Hill: So we carried about 50 wells into 2015 from 2014 that were uncompleted. Obviously we're going to work that inventory down because we plan to drill about 180 wells yet bring 210 wells online. So you'll see we'll draw that inventory down. I think the carryout at the end of the year is anticipated to be around 20 wells or so, so a net gain of 30.

And was that something that would have occurred regardless of the commodity price, I'm just trying to understand if that's a more kind of normal number going forward? Gregory P. Hill: No, because those wells were all drilled in the core, we were already drilling in the core on those wells.

That makes sense. And then another question on maybe kind of a follow-up on the cost side for Stampede, I mean how much of that cost structure is locked in or is available to potentially rebid given an accelerating downturn likely in the offshore spending market? John P. Rielly: So first of all about 50% had been contracted through the end of 2014. Now we're looking at opportunities to reduce the costs in those contracts and we also expect lower contracts in the ones yet to be awarded. They are lower costs and those are yet to be awarded. And recall, production doesn't commence until 2018. So we've got three years of spend here that we can really work the cost hard on before it comes online in 2018.

Great. And then maybe one last one if I could, not to beat a dead horse, but I mean just trying to understand commodity price, not trying to make a forecast, what commodity price you're using to set the budget, and maybe it's something that is more fluid, do we need changes to the marketplace and do you expect to be I guess assessing that on maybe a more frequent time period? John B. Hess: Obviously we're dealing with the reality of current prices, and while we can't predict them and certainly believe they will recover, we're also going to be in a position to adapt further should they be deeper and longer. So they are very unpredictable right now and we think the prudent thing is to focus on financial strength and preserving our liquidity to ride this storm out and we think we're going to come out of this in a very strong manner and I want to make sure we take the steps to do that. So if we have to moderate CapEx more should the price decline continue for a longer period, we'll be in a position to do that. We think we've got the prudent balance now to stay financially strong yet still preserve our long-term growth options and our capability, as Greg said earlier.

Your next question comes from the line of Edward Westlake with Credit Suisse. Please proceed.

Good morning and thank you, lots of helpful color. I just want to run through some math on the rig program in the Bakken. I guess if you get down to eight rigs and you're drilling say over 18 rigs per well, next year you'd probably be closer to 150 wells. Obviously you've spoken about some of the drilled but non-completed this year, 210, and obviously this year the exit rate of production is 102 and next year you're 95 to 105, so I guess does that eight rig program implies some decline in 2016, which makes sense because it's all HBP, but I'm just trying to get the math right? Gregory P. Hill: First of all, as you know we don't really give specific guidance beyond the first year on 2016. But however broadly speaking, Ed, production in the Bakken would remain flat broadly with an eight rig program. So that will give you theory in some direction, but in any case we're going to remain flexible and we'll be prepared to respond accordingly as prices improve, right.

Right. And then just a clarification on the costs in the offshore, you obviously highlighted the rigs, are you seeing decline in all service cost related to rigs as well as to the cost of building fabrication topsides? Gregory P. Hill: Yes, we are. Again, this cycle is just starting. So again, how low will it go and how fast will it come, it's just too premature to talk about that, but we're certainly seeing the signs of across the board price reductions coming at us.

Okay. And then final area, the $1.2 billion of production CapEx this year, and it's very detailed, helpfully detailed in the press release, $300 million in the North Sea for some wells of South Arne and Valhall, $250 million for Tubular Bells, $200 million-ish for EG and then some for Shenzi, another Gulf of Mexico work and then JDA, so you gave us all the data, how much of those wells are I guess linked to reservoir management and how much in say 2016 as you look further out could you just allow the fields to decline or do less activity? I'm trying to get a sense of how much of that $1.2 billion of production CapEx is kind of discretionary and therefore could be influenced by prices. John P. Rielly: I mean I think it's always discretionary, but I think that the important thing is we're focused on returns. So I mean these wells even at current prices generate great returns. So that's why we're continuing forward, and as long as that's the case we will continue to execute those programs.

I presume in 2016, maybe EG and some of the North Sea spend, is there an inventory of those wells to continue that level of activity? John P. Rielly: Yes, there is, and in EG in particular we just started some new 4D seismic. So we're going to take a drilling pause in 2015 but we know that that new 4D is going to indicate further inventory on a go forward basis for EG.

And North Sea, I mean Valhall, yes, obviously the South Arne? John P. Rielly: Yes, South Arne and Valhall, both have multiyear inventories of drilling.

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

Maybe this is for either Greg or John Rielly, if we are looking at your surface cost, any rough idea that how much of as a percentage that is under-contracted as longer than two years? John P. Rielly: Surface cost, is that relative to the Bakken?

No, I'm talking about overall for the organization. So in other words, I mean that how much is your cost is subject to all that have the opportunity to get reset within the next two years, what is your cost base? John P. Rielly: Yes, I mean I can't give you a percentage, Paul, but broadly obviously your offshore fleet tends to be contracted for longer periods of time, right. But what I will say is that doesn't mean that there is no opportunity for cost reduction there. We're going to engage with all of our suppliers, are engaging as we speak expecting cost reductions across the board from everyone. So even though it's contracted, that doesn't necessarily mean that we're locked into those rates.

And maybe I missed in your earlier prepared remarks, did you provide the first quarter production estimate for Bakken, Utica and Waha, I know that you gave the 2015, but how about the first quarter 2015? Gregory P. Hill: Sure. So what we're doing for production in the first quarter will be 330,000 barrels a day to 340,000 barrels a day, that's excluding Libya, for the overall portfolio. Bakken is also still – for the year it was 95 to 105, the first quarter is 95,000 to 105,000 barrels a day.

How about Utica and Waha? John P. Rielly: So for Valhall we gave for the full year, it's 30,000 to 35,000 and it will be the same for the first quarter. Utica will be 15,000 to 20,000 for the full year and it will be a little bit less. So you heard, as Greg said, it's 13,000 barrels in the fourth quarter. So you'll be ramping to that 15,000 to 20,000 throughout the year.

Okay. And John, since that you expect to have a tax benefit because you're going to have a few tax laws, should we assume that 100% of that is actually cash or that is more of a book benefit but the cash you still have to pay? John P. Rielly: No, you should model that essentially as a deferred tax benefit, Paul. I mean we'll have some small cash taxes in several jurisdictions offset by refunds particularly in the UKs where we have our dismantlement, but overall just model that as a deferred tax benefit.

Greg, do you have a number that you can share what is the Bakken current cash operating cost and unit DD&A? John P. Rielly: Paul, as usual, we typically do not provide individual unit cost information. So just overall, Bakken is on the cash cost side, is slightly below our portfolio average, it has been getting better as the production continues to increase there and Greg drives efficiencies in the operations. The DD&A still is higher than the portfolio average, but again, as we book additional reserves with performance as we move through in the Bakken, that DD&A rate has also been coming down and will continue.

Your next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please proceed.

As you think about the price scenarios that you're currently running, when would you update your 2013 to 2018 outlook again? John B. Hess: I'd say as we have a little more visibility on where oil prices stabilize. They are in free fall now, we don't think they are sustainable here, but once the investment programs of not only companies but countries take effect, we think that's going to affect both unconventional and conventional production, that should start to strengthen the market and wherever those prices stably lies remains to be seen, but making a forecast on that now would be foolhardy and predicting when that time we could give new updates also would be foolhardy. We do think during the year as production growth starts to attenuate, prices will start to recover and once we have a little more visibility and confidence in the stability, that's when we would make those updates.

Okay. And then just on our own sensitivity and scenarios, we have here over $1 billion of outspend that sustains, is that a reasonable number given your internal scenarios? John P. Rielly: Again, David, we're just not going to speculate on where oil prices are because as we've been saying, we are going to watch it and be flexible and see where commodity prices are moving and that will affect the pace of investment going forward. So at this point we're just not going to speculate on that number.

Okay, worth a shot. And then I guess as you go through the year on drilling and completion cost, we've thought about cost being lower in the back half. Will you just update those quarterly as you actually have the effect of the cost savings that you're negotiating now or when do you think you'll be able to give us some more clarity on how those negotiations are going? Gregory P. Hill: I think we can update as we go throughout the year. I do want to clarify one thing. Those well costs that I gave in the Bakken, so the D&C of around 6.8, that excludes any significant supply chain reduction. So that was just current cost assuming some efficiencies from lean manufacturing. So there's the opportunity for those costs to go even lower than that in the Bakken in particular.

Very good. And then, so the outspend then is really covered by the MLP and you're in a pretty strong position still to move that forward given the sustained production in the Williston, so no changes to that outlook as far as the MLP? John P. Rielly: No, we are progressing our S-1 filings with the SEC and our preparations remain on track for the transaction in 2015, obviously subject to market conditions, but everything is on track for it.

Very good. Thank you, guys.

Your next question comes from the line of Phillips Johnston with Capital One. Please proceed.

Sort of similar to Ed's question but more on a Company-wide basis, if you look at your overall production guidance for this year ex Libya, it implies that volume should be relatively flat versus the fourth quarter average. Two questions there. First, should we assume the $3.9 billion of CapEx that you plan to spend this year excluding exploration and infrastructure is roughly the level of spending that's required to keep production flat over the next couple of years or is it not that simple? John P. Rielly: No, it's not that simple, and as you said, as you can see, the overall production is about flat with the fourth quarter, what we do have is, as I mentioned earlier with our production in the first quarter, we have some downtime here coming in the first quarter, right, so that's going to affect the overall average. And then the production numbers, just if you're doing the math, is going to be higher than the fourth quarter numbers as you move through the year. But yes, that kind of math is just difficult to do.

Okay, sure. And then just I guess on that note, looking out into Q4, would you expect Q4 to be similar to Q4 last year or higher or slightly lower? John P. Rielly: I just hesitate, I mean I'd rather stay with our full-year guidance, because again we just don't want to speculate on what's happening with oil prices on that. If it goes up, it could be a different story and if it goes down there can obviously be a different story as well. So I think we just want to stay with that overall guidance.

Okay. And just to follow-up on the economics in the Bakken, assuming the high-graded wells this year have EURs of 800,000 to 950,000 as you mentioned, what sort of NYMEX breakeven price would you expect those wells to have? Gregory P. Hill: I think what I can guide you on is that current prices, they exceed our hurdle rate.

Okay, fair enough. Thank you.

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

In 2014, you were expanding nine and eight well pilots to determine if Middle Bakken and Three Forks zones could support 500 foot lateral spacing. Does this expanded testing continue in 2015 or does it dial back until oil prices rise? Gregory P. Hill: No, it doesn't dial back, and in fact the results we've seen from the two existing 17 well per DSU pilots are performing in line with expectations. So therefore we're going to expand the number of pilots. We're going to add three more pilots in 2015 aiming for having enough data to make a decision on that development plan by year-end 2015.

Okay, great. Thank you. You've identified drilling the perfect well offshore Ghana and the players to grow the vehicle after 2020, is this timeline agnostic to oil prices or could FID accelerate if oil prices improve? John P. Rielly: I think first of all we're obligated to submit a development plan to the Ghanaian government in 2016. So, so far that timeline hasn't changed. Obviously this project like every project is going to be a function of oil price. So I think that deadline could be flexible if oil prices stay low.

And as the last question, could you just add a little bit of color on the 2015 exploration effort offshore Guyana, when might you expect the result from the first exploration well and when will the acquisition of additional 3D be completed? Gregory P. Hill: A lot of the 3D has been shot and it's currently being processed as we speak. As I mentioned in my opening remarks, the operator, ExxonMobil affiliate, plans to spud that well in early 2017. Obviously we would have the results during 2017 of that well, and it's cretaceous fan play. Sorry 2015, sorry, not 2017. I was thinking Nova Scotia, I apologize. Guyana is 2015.

Right. Okay, great. Thanks very much.

Your next question comes from the line of Roger Read with Wells Fargo. Please proceed.

I guess lots of dust has been hit pretty well here, but as we look at the adjustments you're making in your Bakken drilling plan, the number of rigs, and then flexibility to either cut that more if prices go down or ramp it up if prices do recover, can you kind of walk us through what is obviously a greater availability of service capacity but kind of what your flexibility is to go from say eight to six or eight to 10 rigs as we hit the latter part of the year? John P. Rielly: I think we're trying to maintain flexibility for the reasons you just described given the volatility of oil prices and certainly where it's going. So we can dial up and we can dial back and we're spending a small amount of capital to give us the flexibility to dial up if commodity prices improve, so that means getting permits and pads ready and things like that, but it's a small amount of the budget next year, but that's why we're doing it because we want that ability to dial up as well as dial down, much easier to dial down than it is to dial up, right.

Sure. And then when do you think the M&A market would start to look more active? I mean I know we've had the downturn but everybody is sort of adjusting their plans at this point. Kind of looking back at prior downturns and not asking you to pick a particular property or even region, what's kind of the normal process we should watch here, is the key to acceleration in M&A, is it a latter part of this year, only if oil prices stay down, just kind of how you think about that? Gregory P. Hill: I wouldn't even want to fathom I guess on your question, but certainly the environment we're in, one would assume that there will be more consolidation and it's yet to unfold.

Alright, good enough for now. Thank you.

And your last question comes from the line of Pavel Molchanov with Raymond James. Please proceed.

Apologize for my voice. You said, going back to a year ago, that spending would be down in 2015 and of course that was at a time when oil was in the triple digits, so off the 16% reduction in your 2015 budget, how much is specifically driven by commodity prices as opposed to what had already been telegraphed a year ago? John P. Rielly: It's the significant majority of it. So first remember we were planning on $5.8 billion in this year. We already started making reductions, brought that down to $5.6 billion. So we were going to take a reduction of the $5.8 billion, but the big move down to $4.7 billion is in reaction to the oil price.

Okay. And then are there any FIDs that you have been planning for 2015 that are likely to be delayed or postponed because of the commodity environment? John P. Rielly: No, there's not. We just didn't have any is the point in 2015.

No FIDs at all on deck for this year? John P. Rielly: No.

Okay, clear enough. Appreciate it, guys.

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