Jay R. Wilson - Vice President of Investor Relations John B. Hess - Chief Executive Officer and Director Gregory P. Hill - President of Worldwide Exploration & Production and Executive Vice President John P. Rielly - Chief Financial Officer, Principal Accounting Officer and Senior Vice President

Evan Calio - Morgan Stanley, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Douglas Terreson - ISI Group Inc., Research Division Edward Westlake - Crédit Suisse AG, Research Division John T. Malone - Mizuho Securities USA Inc., Research Division Roger D. Read - Wells Fargo Securities, LLC, Research Division

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2013 Hess Corporation Conference Call. My name is Allison, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. And I'd now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed, sir. Jay R. Wilson: Thank you, Allison. Good morning, everyone, and thank you for participating in our fourth quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess's annual and quarterly reports filed with the SEC. Also on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. With me today are John Hess, Chief Executive Officer; Greg Hill, 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, and thank you to everyone for joining our fourth quarter conference call. Greg Hill and John Rielly are also here today. And after some prepared remarks, as usual, we will take your questions. Over the last several months, I have met with many of you in person to share our enthusiasm about the prospects for our company in 2014 and beyond. This coming year will be one in which the company and its shareholders will continue to benefit from execution around our focused portfolio of lower-risk, higher-growth assets. We are confident that our initiatives have successfully positioned the company to achieve 5% to 8% compound average annual production growth through 2017 from 2012 pro forma. Importantly, we have the financial flexibility to fund this long-term cash-generative growth, while also delivering strong, sustainable returns for our shareholders. Before I expand on 2014, let me recap some key headlines from our earnings release and summarize our major accomplishments from 2013. First, 2013 adjusted earnings were $1.9 billion and cash flow from operations before changes in working capital was $5.55 billion. Compared to 2012, our results were positively impacted by higher realized selling prices, which offset lower production that was largely as a result of asset sales and the shut-in of Libyan production. Second, in 2013, production averaged 336,000 barrels of oil equivalent per day or 270,000 barrels of oil equivalent per day on a pro forma basis, excluding divestitures and Libya. In 2014, we forecast production to average between 305,000 and 315,000 barrels of oil equivalent per day, excluding Libya. Third, in 2013, we replaced 118% of production at an FD&A cost of approximately $41.50 per barrel of oil equivalent. At year end, our proved reserves stood at 1.437 billion barrels of oil equivalent and our reserve life was 11.5 years. On a pro forma basis, our 2013 reserve replacement ratio would have been 148% and our FD&A cost would have been $36 per barrel of oil equivalent. Pro forma year end reserves were 1.362 billion barrels of oil equivalent and our reserve life was 12.8 years. Now let's turn to the Bakken. Last year was an especially important one for us, as we really began to capitalize on our position as one of the 2 largest oil and gas producers in the play. Net production averaged 67,000 barrels of oil equivalent per day, up 20% year-over-year. And as Greg will discuss in more detail, we increased production while simultaneously lowering drilling and completion costs to $7.6 million in the fourth quarter of 2013 compared to $9 million in the year-ago quarter. To put this in perspective, we achieved this production increase even though we transitioned to pad drilling and experienced required shut-ins as a result of the expansion of the Tioga Gas Plant. Since the start of 2012, 1/3 of the top 50 wells drilled in the Bakken in North Dakota, in terms of 90-day initial production rate, were operated by Hess. We have an outstanding team operating in the Bakken, and they're doing all the right things to capture the tremendous investment opportunity there as we continue to drive down well costs, increase production and maximize returns. Turning to our other accomplishments in 2013. As everyone knows, we announced in March a detailed plan to: one, complete our transformation into a pure-play E&P company with increased production visibility and lower risk; two, fully exit the downstream; three, strengthen financial flexibility to fund growth; and four, increase current returns to shareholders. By any measure, our progress has been remarkable. Specifically, with respect to our announced divestiture program, we generated $7.8 billion in total proceeds from asset sales completed and announced in 2013. Consistent with our March announcement, initial proceeds were used to pay down $2.4 billion of short-term debt, fund a cash flow deficit over $1 billion in 2013 and to add approximately $1 billion of cash to the balance sheet as a cushion against future commodity price volatility. Excess proceeds from our asset sales allowed us to begin a share repurchase program in August of up to $4 billion. To date, we have purchased $1.9 billion of our stock, reducing fully diluted outstanding shares by approximately 6.5%. This share repurchase program is ongoing. We also raised our annual dividend by 150% to $1 per share in September. With respect to those divestitures still in progress, in terms of Hess Retail, late last year, we received a favorable private letter ruling from the IRS permitting Hess Corporation to spin the Hess Retail tax free to its shareholders. On January 8, Hess filed a Form 10 with the SEC in anticipation of completing the spin in mid-2014. A parallel third-party sales process has also been initiated and is currently ongoing to determine which alternative maximizes value for shareholders. In addition, the sale of our Thailand assets is well advanced, and we expect to be able to make an announcement early this year. The divestment of our interest in our energy trading joint venture, Hetco, is also ongoing, and we anticipate the conclusion of this process later in 2014. Additionally, we are working aggressively to structure our Bakken midstream assets in a way that would allow monetization without the loss of operating control, most likely through an MLP vehicle. We expect this event to occur no later than 2015, and we'll give further updates as appropriate. Looking to 2014 and beyond, as I have already noted, we are well positioned to achieve these 2 goals: First, deliver compound average annual production growth of 5% to 8% from pro forma 2012 over a 5-year period; and second, be free cash flow positive post-2014 based on $100 Brent. Our high visibility production growth is underpinned in the near term by assets with relatively low execution risk, by the highest leverage to oil prices in our peer group and by industry-leading cash margins. These assets include the Bakken in North Dakota, Tubular Bells in the Deepwater Gulf of Mexico and Valhall in Norway. In the outer years, we will benefit from our exciting North Malay Basin project in Malaysia and the emerging Utica Shale play in Ohio. I have already talked a little bit about the Bakken, but it bears repeating. Hess is one of the 2 largest oil and gas producers with some of the best acreage in arguably the best shale oil play in the world. Our wells there are among the lowest cost and most productive in the region; and as a result, are generating some of the highest rates of return. In 2014, we plan to increase our rig count to 17 from 14 and expect net production from the Bakken to average between 80,000 and 90,000 barrels of oil equivalent per day. Based upon the strong production performance of our Bakken and Three Forks wells over the past year, we are increasing our production guidance to a peak of net 150,000 barrels of oil equivalent per day in 2018 from our prior guidance of net 120,000 barrels of oil equivalent per day in 2016. In addition, we are increasing the number of future well locations from 1,800 to 2,400 and also our estimate of recoverable resources from 1 billion to 1.2 billion barrels of oil equivalent. During 2014, we will also be running production tests using tighter spacing pilots. This will allow us to determine whether there is additional upside in our estimates for future production and resources. Greg will talk more about this later. Turning to the offshore. In the Deepwater Gulf of Mexico, we are advancing our Tubular Bells project with our partner, Chevron. Hess has a 57% interest in the project and is the operator. Production is planned to commence in the third quarter of 2014 at a net rate of 25,000 barrels of oil equivalent per day. Recent drilling results are encouraging and indicate potential upside in both production and reserves. Moving to Norway. The Valhall Field is a long life material resource that generates significant free cash flow, and we think it still has untapped potential in terms of unbooked resources and production growth. The redevelopment project that was completed early last year extended field life by 40 years, and the operator plans to bring 3 new wells online this year. For 2014, we forecast net production to average between 3 -- 30,000 and 35,000 barrels of oil equivalent per day, an increase from 23,000 barrels of oil equivalent per day in 2013, while we continue to work closely with the operator to maximize production. Greg and I were in Malaysia earlier this month, and we are very enthusiastic about the long-term potential of our position in the Gulf of Thailand. Our natural gas assets there are long life, low risk and low cost, with oil-linked pricing and exploratory upside and will be significant cash generators for the next 2 decades. Combining our expected North Malay Basin production with that already coming from the JDA, we anticipate that by 2017 our Gulf of Thailand assets will produce an average of approximately 70,000 barrels of oil equivalent per day for the next 2 decades compared to 46,000 barrels of oil equivalent per day in 2013. Coming back to U.S. onshore. There's also considerable promise in the emerging Utica Shale where we have concentrated our position in the sweet spot of the play and have a successful joint venture with CONSOL. We drilled 29 wells last year and expect to drill another 35 wells in 2014. We are encouraged by the potential of our holdings in the wet gas window and anticipate returns comparable to those that we see in the Bakken, in part due to our acreage having high net revenue interest. As you have likely seen, we announced about a half hour ago, the sale of approximately 74,000 acres of our Utica dry -- Utica Shale dry gas acreage to an undisclosed third party for $924 million. Total proceeds from the sale will be used for additional share repurchases as they are in excess of those associated with a divestiture program announced by the company on March 4 of last year. We will determine whether or not to seek an increase to our existing $4 billion share repurchase authorization, which was approved as part of our March 4 announcement after a final decision is made, either to spin or sell Hess Retail. John Rielly will provide more detail in a few minutes. This divestiture is a perfect example of a point I have made many times before. Portfolio reshaping is part of the ongoing nature of the oil and gas business and fundamental to our strategy for growing long-term shareholder value. In this case, while our wells in the dry gas portion of the Utica were highly productive, we concluded that the potential returns from such an investment at current and projected natural gas prices no longer justified retaining this acreage as a strategic part of our overall liquids based asset portfolio. In summary, we are doing what we set out to do and more, as we continue to transform Hess into a pure-play E&P company. I am immensely proud of each and every member of our team for their combined contributions to our tremendous progress. I also want to thank our Board of Directors for their engaged counsel and their unanimous support of our strategy. The bottom line: 2013 was an outstanding year for our company and our shareholders. We look forward to carrying this momentum in 2014 to drive growth, enhance returns and create long-term value for our shareholders. I will now turn the call over to Greg Hill. Gregory P. Hill: Thanks, John. I would like to provide an operational update on our progress in 2013 and the plan for 2014. Starting with production. In the fourth quarter, we averaged 307,000 barrels of oil equivalent per day. This included the shut-in of some 35,000 barrels of oil equivalent per day of Hess production in the Gulf of Mexico as a consequence of Shell's unplanned shutdown of its Auger pipeline for repair on December 18. Production was restored on January 10. Overall, in 2013, we achieved an average of 336,000 barrels of oil equivalent per day. Looking forward, in 2014, we forecast production to average between 305,000 and 315,000 barrels of oil equivalent per day, which, as John mentioned, assumes our Libya production which has net capacity of approximately 25,000 barrels of oil equivalent per day, remains shut in for the full year as a result of civil unrest. We forecast production in the first quarter of 2014 to average between 275,000 and 285,000 barrels of oil equivalent per day, reflecting both the previously mentioned unplanned downtime in the Gulf of Mexico and the planned downtime associated with the Tioga Gas Plant expansion in North Dakota. Beginning in the second quarter, production is expected to build throughout 2014 as a result of the Tioga Gas Plant expansion, steady production growth in the Bakken and the startup of the Tubular Bells field in the third quarter. Moving to the Bakken. Fourth quarter 2013 production averaged 68,000 barrels of oil equivalent per day. And as John mentioned, full year 2013 production averaged 67,000 barrels per day, well within our guidance range of 64,000 to 70,000 barrels of oil equivalent per day. In 2014, net production from the Bakken is expected to increase to between 80,000 and 90,000 barrels of oil equivalent per day. Net production is expected to average in the range of 65,000 to 70,000 barrels of oil equivalent per day in the first quarter of 2014, reflecting the previously announced downtime associated with the expansion of the Tioga Gas Plant. Once the plant is fully onstream, we expect production to be reestablished at more than 80,000 barrels of oil equivalent per day and thereafter, steadily ramp up throughout the balance of the year. Looking forward, we now see Bakken production increasing to 125,000 barrels of oil equivalent per day in 2016 and then to 150,000 barrels of oil equivalent per day in 2018. This increase is based on continued strong well performance in both the Middle Bakken and Three Forks, as well as the success of our development spacing based on 5 Middle Bakken wells and 4 Three Forks wells per 1,280 acre drilling spacing unit, or DSU. As we mentioned on our last quarterly call, we intend to construct 17 well pads that will test infilling down to 7 Middle Bakken wells and 6 Three Forks wells per DSU. In addition, we are also constructing 2 well pads that will test infill down to 9 wells in the Middle Bakken and 8 in the Three Forks per DSU. If this tighter spacing validates the results of our reservoir simulations, our longer-term guidance of 150,000 barrels per day, our number of economic drilling locations and our recoverable resource will likely increase. In summary, the Bakken has gotten bigger and better as we have continued to delineate our acreage and optimize our development. Our continued focus on applying lean manufacturing practices to our operations enabled us to drive our drilling and completion costs down by more than 15% over the course of last year from $9 million per well in the fourth quarter of 2012 to $7.6 million in the fourth quarter of 2013. Even though we plan to increase our number of frac stages from 30 to 35 in 2014, we believe we can still achieve further reductions in drilling and completion costs in 2014. Our 2014 capital budget for the Bakken is $2.2 billion, which is level with last year. As John mentioned, although spending is expected to be comparable to 2013, as a result of lower infrastructure spend and continued reduction in drilling and completion costs, our activity level in terms of rig count and wells will be much higher. We expect to operate a 17-rig program in 2014, up from 14 last year; and to bring 225 new wells online compared to 168 last year. Current plans are to increase the rig count to 20 for mid-2015 forward. However, the results of the tighter spacing drilling in 2014 may result in even higher long-term rig counts. Our 30-day initial production rates have averaged between 750 to 900 barrels of oil equivalent per day or approximately 15% to 20% above the industry average. Our estimate of the ultimate recovery per well remains between 550,000 and 650,000 barrels of oil equivalent, demonstrating further the high quality of our Bakken acreage. With regard to our Bakken infrastructure, unseasonably cold weather conditions caused the startup of our Tioga Gas Plant to slip by about 1 month. The plant is 100% mechanically complete, and we are now in the process of commissioning the plant and expect to commence gas sales late February and extraction and sale of natural gas liquids in March. Turning to the Utica. Our 2013 activities materially improved our understanding of the play. During 2013, we drilled a total of 29 wells, completed 24 and tested 17 across the corporation's 100% owned and JV acreage with CONSOL. We are very encouraged by well results to date, with rates in the wet gas window averaging over 2,200 barrels of oil equivalent per day with 47% liquids based on 24-hour tests. As we announced today, we sold 74,000 acres of dry gas window that did not meet our investment return thresholds. We are fully retaining our 42,000 acre net position in the wet gas window, and we'll focus our efforts there going forward. This acreage provides for strong returns on investment comparable to those of the Bakken, as a consequence of strong liquids-rich well rates and an average net revenue interest of 96%. Of our 2014 Utica budget of $550 million, some $320 million is dedicated to drilling and completing 32 wells in the wet gas window. A further $50 million is allocated to drill 4 wells in the dry gas window as per our agreement with a third party in order to hold acreage. The balance includes capital for acreage acquisition to build out our DSUs and preconstruction of well facilities and pads in preparation for 2015 drilling. Drilling and completion costs in the Utica are down some 35% in 2013 versus 2012, as we have begun to apply the same lean manufacturing approaches that we used in the Bakken. However, we are still very much in the appraisal phase in the Utica, and our current drilling and completion cost of approximately $12 million includes extensive logging and coring, which is providing the data required to optimize the ultimate development of our acreage. As we move into development mode, we expect drilling and completion costs will be substantially reduced. In the Deepwater Gulf of Mexico, we continue to advance our Tubular Bells project, which Hess has a 50% interest and is the operator. The hole is complete, and we expect sail away within the next several weeks as soon as the heavy lift vessel is available after completing work for another operator in the Gulf. The topsides are now 95% complete, and sail away is planned for late February. Based on the better-than-prognosed results from the first 3 producing wells, a fourth producer will be drilled and completed by early 2015. First production is on schedule for the third quarter of 2014 in a net rate of approximately 25,000 barrels of oil equivalent per day. Moving to the Valhall Field in Norway, in which Hess has a 64% interest. The field's redevelopment project was completed in the first quarter of last year. Net production averaged 37,000 barrels of oil equivalent per day in the fourth quarter and 23,000 barrels of oil equivalent per day for the full year 2013. In 2014, we expect Valhall net production to average between 30,000 and 35,000 barrels of oil equivalent per day and to reach 40,000 to 50,000 barrels of oil equivalent per day by 2017. The majority of the activities going forward at Valhall will focus on development drilling to fully utilize platform capacity and also implementation of a plan agreed with the operator, BP, to improve operating performance at the field. In the Gulf of Thailand, we commenced production in October 2013 at the North Malay Basin project, in which Hess has a 50% interest and is the operator. Deliverability from the 5 early production wells is fully on target, and we expect net production to average approximately 40 million cubic feet per day through 2016. Full field development is progressing according to an aggressive schedule for first gas in late 2016, resulting in net production increasing to 165 million cubic feet per day in 2017 and contributing material cash flow through to the end of the current production-sharing contract in 2033. Early evidence from new 3D seismic shot in 2013 indicates significant volumetric upside. We plan to start a 6-well exploration campaign in late 2014 to further assess this potential. Regarding exploration, in the Deepwater Tano Cape Three Points South Block in Ghana, where Hess has a 90% working interest and is the operator, we have received the necessary approvals to begin a 3-well appraisal drilling program in the second half of 2014. Partnering negotiations to reduce our financial exposure are well advanced. In Kurdistan, our first exploration well, Shakrok-1, has drilled through its Jurassic target and an extensive set of well logging runs and coring has been completed. It will now be drilled on through the Triassic to its target depth after which, we intend to conduct production testing. In addition, we plan to spud a well on the Dinarta block in March. Hess has an 80% paying interest, 64% working interest in these blocks and is the operator. In closing, 2013 was a year of exceptional execution and delivery on all fronts, which is a tribute to the outstanding people of Hess. 2014 promises to be an exciting year with significant new volume growth in the Bakken and Tubular Bells and delineating material resource potential in North Malay Basin, Ghana and Kurdistan. I will now hand the call over to John Rielly. John P. Rielly: Thanks, Greg. Hello, everyone. In my remarks today, I will compare results from the fourth quarter of 2013 to the third quarter of 2013. The corporation generated consolidated net income of $1,925,000,000 in the fourth quarter of 2013 compared with $420 million in the third quarter of 2013. Adjusted earnings, which exclude items affecting comparability of earnings between periods, were $319 million in the fourth quarter of 2013 and $405 million in the previous quarter. As Greg previously mentioned, subsequent to our interim update, a third-party operated pipeline in the Gulf of Mexico was shut down on December 18, which reduced our production and impacted fourth quarter net income by an estimated $20 million. Turning to Exploration and Production. E&P income in the fourth quarter of 2013 was $1,029,000,000 and $455 million in the third quarter. E&P adjusted earnings were $436 million in the fourth quarter and $458 million in the previous quarter. Adjusted fourth quarter earnings were impacted by unplanned maintenance in the Gulf of Mexico in October and December, the planned shutdown of the Tioga Gas Plant and lower realized U.S. crude oil prices. The changes in the after-tax components of adjusted earnings for E&P between the third and fourth quarter were as follows: Changes in realized selling prices decreased earnings by $34 million. Higher unit costs decreased earnings by $25 million. Higher sales volumes increased earnings by $25 million. All other items net to an increase in earnings of $12 million, for an overall decrease in fourth quarter adjusted earnings of $22 million. Our E&P operations were over-lifted compared with production by approximately 500,000 barrels of crude oil in the fourth quarter, resulting in increased after-tax income of approximately $8 million. The E&P effective income tax rate, excluding items affecting comparability of earnings, was 38% for the fourth quarter and 45% in the third quarter of 2013. The lower rate in the fourth quarter reflects the impact of shut-in Libyan production, which has a high effective tax rate. In December, Denmark enacted a new hydrocarbon tax law that has resulted in a combination of changes to tax rates, revisions to the amount of uplifts allowed on capital expenditures and special transition rules. These changes will result in a higher effective tax rate, but cash taxes for this hydrocarbon tax are deferred until 2018, due to the uplifts allowed on future capital expenditures and the existence of net operating loss carryforwards. As a consequence of the tax law change, the corporation recorded a deferred tax asset of $674 million. In addition, the Exploration and Production results for the fourth quarter included the following additional items affecting comparability of earnings: The sales of our Indonesian assets increased net income by $156 million. The write-off of previously capitalized exploration wells in Area 54 offshore Libya decreased net income by $163 million. The write-off of our leasehold acreage in the Marcellus decreased net income by $23 million. Employee severance and other exit costs, including an income tax charge relating to the repatriation of foreign earnings, reduced net income by $51 million. Turning to corporate and interest. Corporate and interest expenses after income taxes were $115 million in the fourth quarter of 2013 and $89 million in the third quarter. Adjusted corporate and interest expenses were $108 million in the fourth quarter and $84 million in the previous quarter. The increased costs in the fourth quarter were a result of higher professional fees, increased letter of credit and bank fees and lower capitalized interest. Turning to downstream. Earnings from the downstream businesses were $1,011,000,000 in the fourth quarter of 2013 compared with $54 million in the third quarter. Fourth quarter results included after-tax gains totaling $995 million related to the sales of our Energy Marketing and terminal network businesses. Fourth quarter results also included after-tax income of $134 million from the partial liquidation of LIFO inventories, partly offset by after-tax charges totaling $109 million for severance and other exit costs, including an income tax adjustment. We had an adjusted loss of $9 million in the fourth quarter compared to adjusted earnings of $31 million in the third quarter. The decrease in the fourth quarter earnings was primarily due to the wind down of operations associated with divesting our downstream businesses. You may have seen in our earnings release that we have reported retail marketing and our energy trading joint venture as part of continuing operations, which is due to the potential spin-off of retail marketing and the lengthy marketing processes. These businesses will be reclassified as discontinued operations when they are divested. As a reminder, we have included pro forma E&P results in our supplemental earnings presentation on our website to assist in your understanding of our results as a pure-play E&P company. Turning to cash flow. Net cash provided by operating activities in the fourth quarter, including an increase of $389 million from changes in working capital, was $1,550,000,000. Net proceeds from asset sales were $2,870,000,000. Capital expenditures were $1,421,000,000. Common stock acquired and retired amounted to $993 million. Net repayments of debt were $416 million. Common stock dividends paid were $81 million. All other items amounted to a decrease in cash of $16 million, resulting in a net increase in cash and cash equivalents in the fourth quarter of $1,493,000,000. During the fourth quarter, we purchased approximately 12.8 million shares of common stock, bringing total 2013 purchases to approximately 19.3 million shares of common stock at a cost of approximately $1.54 billion or $79.65 per share. We've continued to buy our common stock in 2014. And as of January 27, total program-to-date purchases were 23.5 million shares at a cost of $1.87 billion or $79.55 per share. We had $1.8 billion of cash and cash equivalents at December 31, 2013, which is up from $649 million at the end of last year. Total debt was $5.8 billion at December 31, 2013, down from $8.1 billion at December 31, 2012. The corporation's debt-to-capitalization ratio at December 31, 2013, was 19%, which was improved from 27.7% at the end of 2012. As John has mentioned, the corporation reached agreement today to sell approximately 74,000 acres of its dry gas position in the Utica Shale for $924 million. Approximately 2/3 of the proceeds are expected to be received at the end of the first quarter, with the balance to be received in the third quarter. The proceeds from this asset sale will be used for share repurchases. The corporation will determine whether to seek an increase to its existing authorized $4 billion share repurchase program after a final decision is made to either spin or sell retail marketing. If retail is spun off to shareholders, the Utica proceeds will be used towards the $4 billion repurchase program. If retail is sold, we expect to seek board approval to increase the authorized share repurchases. Turning to 2014 guidance. In addition to the production and capital expenditure guidance provided for E&P by John and Greg, I would like to provide estimates for certain 2014 metrics based on our expected production range of 305,000 to 315,000 barrels of oil equivalent per day, which assumes no contribution from Libya. For the full year 2014, E&P cash costs are expected to be in the range of $20.50 to $21.50 per barrel, which is down approximately $3 per barrel from 2013 pro forma cash cost, excluding Libya. This improvement is due to a combination of cost savings and increased production volumes, and the decrease will improve our portfolio's already strong cash margin per BOE. Depreciation, depletion and amortization expenses are expected to be in the range of $29 to $30 per BOE, reflecting greater contributions from Bakken and Valhall, which both have higher DD&A rates than the portfolio average. Total production unit cost for 2014 are estimated to be $49.50 to $51.50 per barrel, which compares to 2013 pro forma unit cost, excluding Libya, of approximately $50 per barrel. For the full year 2014, the E&P effective tax rate, excluding items affecting comparability, is expected to be in the range of 37% to 41%. The corporation has hedged 25,000 barrels per day of Brent crude oil production for the calendar year 2014 at an average price of $109.12 per barrel. Corporate expenses in 2014 are estimated to be in the range of $125 million to $135 million after taxes, down from adjusted expenses of $161 million in 2013. We expect our 2014 after-tax interest expense to be in the range of $225 million to $235 million, down from $255 million in 2013. As previously guided, our cash flow deficit will be reduced in 2014. Looking forward, we expect our continued production growth in the Bakken, Valhall and Tubular Bells to generate free cash flow post-2014 at $100 Brent prices. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

[Operator Instructions] And our first question comes from the line of Evan Calio with Morgan Stanley. Evan Calio - Morgan Stanley, Research Division: My first question is on the '14 production guidance. I know you provided it many ways with different time periods, which is helpful. Yet the clean number x asset sales, x Libya is up 40,000 barrels a day equivalent to 15% for 2014. Can you break that down, the buildup of that 40,000 barrel a day growth? I know you gave the Bakken number, but I didn't -- I don't know if I heard what the year-on-year for Valhall, North Malay and then what you're assuming the ramp in -- of -- in the Gulf of Mexico. Gregory P. Hill: Yes. I think -- yes, thanks, Evan. So I guess, the easiest way to start is with the clean kind of pro forma number for 2013, which is 270,000 barrels a day. And then you add back on to that about 50,000 barrels a day of growth. Obviously, the 2 big contributors there are the Bakken, which is a full year ramp and the T-Bells in the Gulf of Mexico. There are smaller effects due to Valhall and North Malay and also the Utica. So that gets you to 320,000 barrels a day. And then back off about 10,000 for natural field declines and contingency, and that gets you to the mid-point of 310,000. Evan Calio - Morgan Stanley, Research Division: Okay, I think I got that. And then the -- and for the first quarter guidance, at 275,000, is that x Thailand? Or if the one asset, that you're guiding it without Thailand or with Thailand? John P. Rielly: Yes. So we're guiding -- all our guidance is pro forma, so that's without Thailand. So if you look at our fourth quarter actually, so the 307,000 and you pulled out and did that on a pro forma basis, it would be 277,000 in the fourth quarter. Basically 15 from Indonesia and 15 from Thailand. Evan Calio - Morgan Stanley, Research Division: Got it. Let me -- again, last question and I'll pass it off, maybe a question from a little bit from left field. But given how wide Gulf Coast differentials were in the fourth quarter of 2013 and market debate on what that might look like on a go-forward basis, I mean, do you see any opportunity to potentially monetize your HOVENSA interests? I mean, I know it's Jones Act exempt and I know that you've got a big cat cracker there. I think you conceivably run that refinery profitability if light discounts were wide enough. I mean, any thoughts around that asset? John B. Hess: Yes. We and our partners, PDVSA, are in the market looking to see if we might be able to monetize the asset. So a sales process has begun in coordination with the Virgin Island government.

And your next question comes from Doug Leggate of Bank of America. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: So a couple of questions for me, please. On the buyback, John Rielly, I guess, you've been pretty clear about you're going to wait on -- to see what happens over the next couple of months with retail. But can you update us, please, on what cash have you received since the end of the year? And where are you on the work-down of the terminals working capital? And if I may just layer on another one same kind of question. What are your intentions if you do spin retail in terms of putting debt on there as a potential contributor to the buyback as well? And I've got a follow-up, please. John P. Rielly: Sure, I think I have them all, Doug. So since the end of 2013, what we've received as far as asset sales is the Pangkah deal. So the Pangkah deal has closed. So we have the $650 million from that asset sale we've received. As far as the liquidation of inventories from our downstream side of the business, we still have approximately $200 million worth of inventory to liquidate, which we see getting -- doing that kind of throughout the first quarter. So that is also coming. As far as the debt on any potential spin, it's premature for us to talk about it at this point. But, I mean, you could look at that from a capital structure, it won't be different, really, from any of the retail industry peers that you see out there. But at this point, it's a little premature for us to discuss. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: So would you plan on dividending that back to the parent, John? John P. Rielly: So at this point, Doug, we're still in the marketing process. And so we will ultimately get to the capital structure if we do spin retail. But we're going to leave that discussion till later. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Okay. My 2 quick follow-ups, please. John, can you confirm still that you are not paying cash taxes in the U.S.? And if you could confirm again your latest thinking on when you might be paying cash taxes in Norway, and I've got one final one, please. John P. Rielly: Yes. So, Doug, to your question, I mean, due to our really significant investment in previous years in the United States and in Norway, if I can add it that way, and our continuing significant investments in the U.S. and in Norway, we right now do not see us paying cash taxes in the U.S. or Norway basically through that 2017 guidance that we have given out. So right now, it's extending out beyond 2017. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Great. And my final one is again, I guess, it's a bit like Evan's. It's a bit of an outfield question. But there's been a lot of chatter about rail safety in the Bakken. You guys were early. You and your cars, obviously, it's been a big benefit to you in terms of getting coastal pricing. But can you talk about where your -- the quality of your rail assets as it relates to safety standards and any concerns we should have there about any potential disruption to your coastal pricing? And I'll leave it there. Gregory P. Hill: Yes. Okay, great. Thanks, Doug. Yes, well, first of all, safety is obviously important in everything we do at Hess. And our railcars meet the highest standards of the day for specs and maintenance. We built the cars nearly 2 years ago. We worked with the railroad companies and industry experts to design our state-of-the-art railcars to a new standard that's commonly referred to as the petition 1517, 77 design. Now these cars were precisely designed to safely transport Bakken crude grades. And as such, they're equipped with enhanced features and include thicker steel, double-hull bottom, half-head shields, top fittings protection and a reclosing pressure relief device. So they're truly state-of-the-art railcars. Our experience is that rail company operators are equally focused on safety, just as we are. So I think as rail increases in the country and accidents inevitably happen, it's real important to have a regular dialogue between our industry and the rail operators and the government to ensure the overall integrity of these systems. But again, our cars are of the new and of the highest standards available in the rail industry.

Your next question comes from Doug Terreson of ISI. Douglas Terreson - ISI Group Inc., Research Division: In Europe, your comments indicate that Valhall seemed to be moving in a better direction, and you spent a minute talking about the development drilling program. And so my question was while that seems to be the primary initiative for improved output and recovery, but is there other factors that could be at work that should -- or that could enhance performance in this area as well? Maybe if you could just kind of provide an update on the plan there? And then also, were the higher depreciation and tax rates on this field the primary driver behind the change in international E&P profitability between the first and the second half? And I know that there were a lot of moving parts, but would that be the first place to start? Gregory P. Hill: Yes. Let me start with Valhall. As we've said before, we're implementing a plan with BP to improve performance on Valhall. Our ultimate objective, as well as the operators, is to fill up that capacity at Valhall. There's a number of drilling locations. There's a lot of upside in reserves. It's really going to be key to get our well costs down. So a big effort is going to be on reducing the well costs. Obviously, that will increase the number of drillable locations as you go forward, then also the other factors just to improve the overall operability of the asset, keep your availability and reliability high. So those are the 2 major areas that we're focused on. John P. Rielly: And then, Doug, to the discussion regarding Valhall and its contribution to the higher DD&A and the higher tax rate, you are correct. So Valhall does have a higher DD&A rate. So as the production is ramped up, that has increased the DD&A rate. And all in, we are still have to record from a book standpoint. So deferred taxes are being recorded at the high statutory rate. They're statutory rate is 78%. So you have the high deferred taxes there. But as I mentioned earlier, so you have higher DD&A and you have that higher tax rate due to deferred taxes, Valhall's cash margin per BOE is significantly higher than our portfolio average on a cash margin basis. So Valhall is contributing very good cash flow to us; and over this period to 2017, significant free cash flow.

And your next question comes from the line of Ed Westlake of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Just on Tioga. When you're thinking about trying to -- so you went down the MLP process, how many quarters of sort of operations do you think you need before you can actually either sell or launch an MLP? John P. Rielly: Yes. I mean, it's a good point. It's one of the key drivers that we have kind of on the timing of the monetization. So we do believe we need -- I'm going to say at least several months' worth of operating performance on the Tioga Gas Plant. I mean, the other things just in general that we have going on is there's extensive financial, tax and legal preparation work that needs to be completed and is ongoing, the Tioga Gas Plant, as you mentioned. The other thing, which is important, though, the third kind of key driver is we need the results of the tighter down spacing pilots that Greg spoke about earlier. And we want that prior to a monetization event to ensure we maximize shareholder value. So with all those 3 things going on as, John has said earlier, we are aggressively working this monetization, and it will be done by 2015. Edward Westlake - Crédit Suisse AG, Research Division: Yes, that's helpful color on what the -- what you need to get through beforehand. And then on the retail spin, and I forget -- I apologize if you have said this before. But on a third-party sale, would there be tax, I mean, as opposed to the tax-free spin that you might be able to do with the private letter ruling? John P. Rielly: So, I mean, there will be -- it will be a taxable transaction. And so yes, there will be taxes associated with the sale. Now again, you do have a timing of the cash tax payments, but there is -- that would be a taxable sale. Edward Westlake - Crédit Suisse AG, Research Division: Right, and then a follow-up on rail. I mean, obviously, the new cars are much better than the old cars. I don't know, I mean, I was -- I've been kind of recently heard on the radio that maybe some of the new cars had also blown up at the tragedy at Mégantic. Have you sort of done any work on how safe these new cars are relative to some of the news flow that we're seeing on disruptions on rail? Gregory P. Hill: Yes, we have. And first of all, the cars that were involved in the explosion were the old design. We know that. Those were the 111 cars. So that's just a rumor. But we -- again, these cars, we worked for over a year with railroad companies and industry experts to really design the safest car we could to transport Bakken crude. So we feel like we are running the safest -- one of the safest fleets in the industry. Edward Westlake - Crédit Suisse AG, Research Division: Okay. I mean, some were worried that you'd have to strip out additional light ends or something before loading the rail. But you feel you don't have to with the quality that you're loading. Gregory P. Hill: No I don't think so.

Your next question comes from John Malone of Mizuho Securities. John T. Malone - Mizuho Securities USA Inc., Research Division: Yes. John, just wanted to clarify something. Your Bakken guidance increase and your resource upgrade, that is driven still in kind of 9 well per section plan? So you haven't really baked in the upside from a 7, 6 or a 9, 8 configuration into those numbers? Gregory P. Hill: No, John, we haven't. So you're exactly right. That's based on a 5 and 4 configuration. And as I said in my opening remarks and John mentioned, here, we're going to put in these close space pilots next year, 17 well pads on the 7 and 6, 2 well pads on a 9 and 8. And depending upon the results of that, that could lead to further upside potential in the Bakken. John T. Malone - Mizuho Securities USA Inc., Research Division: When do you think you'll crunch those numbers? You just mentioned the fact that the 2015 plan for monetization in midstream, you'd have to have those data included. Do you anticipate being able to say something on that within -- in calendar 2014? Gregory P. Hill: Yes, I think probably very late 2014 or early 2015 before we'd be comfortable with that. John T. Malone - Mizuho Securities USA Inc., Research Division: Okay. And 17 rigs planned for this year. How do you see those being layered in over time? Gregory P. Hill: We're operating 17 rigs today. John B. Hess: In the Bakken. John T. Malone - Mizuho Securities USA Inc., Research Division: Okay, all right. Last question just the $7.6 million well cost. You mentioned the fact that you may be able to squeeze more gains out of that. What's sort of the low hanging fruit there? What could still be done to bring those costs down? Gregory P. Hill: John, I think it really is -- I think most of the low hanging fruit is gone. This is now in the lean manufacturing mode of just continuous improvements day in, day out, month-on-month, right?

And our next question comes from Roger Read of Wells Fargo. Roger D. Read - Wells Fargo Securities, LLC, Research Division: Just to take another swing at the Bakken. If we were to see a real change in Department of Transportation regulations that truly impacted how we're hauling crude today, notwithstanding the quality of your railcar fleet, what are your options, pipe versus rail here? Can you give us an idea of your flexibility to switch between one and the other? John B. Hess: Yes. We also have pipeline access of 60,000 to 70,000 barrels a day right now. Some of which we're using, some of which we're not because there are better differentials to put it on rail. So we actually are well positioned should something happen. Having said that, there are probably about 30,000 crude railcars in the United States, and 10,000 of them are the new modern standards that we have that others have as well. So it's really the 20,000, I think, that the government and industry, both rail and oil, are going to be addressing. So having said that, we and the industry in oil are going to work with rail and the government to really try to be thoughtful but also responsive to the safety issues. Roger D. Read - Wells Fargo Securities, LLC, Research Division: Okay, appreciate that. The other question I had, free cash flow expectations in 2015 are based on $100 Brent. What sort of differential are you presuming for your Bakken production there? John P. Rielly: Obviously, differentials are moving around. So what we're generally assuming is a differential, let's just say of using TI, and you can go off of that. It's somewhere in the $5 to $10 range.

Thank you very much. Ladies and gentlemen, this concludes the conference for today. Thank you for your participation. You may now disconnect, and have a great day.