Hess (HES) Q4 2017 Earnings Conference Call Transcript

Hess (HES 0.45%)
Q4 2017 Earnings Conference Call
Feb. 5, 2018 10:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good day, ladies and gentlemen, and welcome to the Fourth-Quarter 2017 Hess Corporation Conference Call. My name is Ayela, 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.

If at any time you require operator assistance please press * followed by 0 and we'll be happy to assist you. 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 Wilson -- Vice President of Investor Relations

Thank you, Ayela. 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' 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, which will be provided, on our website during the Hess Midstream partners conference call, today at 4:30 p.m.

Now as usual, with me today are John Hess, chief executive officer; Greg Hill, chief operating officer; and John Rielly, chief financial officer. I'll now turn the call over to John Hess.

John Hess -- Chief Executive Officer

Thank you, Jay. Welcome to our fourth-quarter conference call. I will review our overall strategy and plans. Greg Hill will then discuss our operating performance and 2018 guidance, and John Rielly will review our financial results.

Our company is making significant progress in our strategy. To grow our resource base in a capital-disciplined manner, to move down the cost curve so that we are resilient in a low-oil-price environment, and to be cash-generative at a $50 per barrel Brent oil price post-2020. In 2017, consistent with our strategy, we moved aggressively to high-grade and focus our portfolio, by investing in our highest-return assets in Guyana and the Bakken and divesting higher-cost mature assets. This portfolio high-grading in turn is lowering our cash unit operating costs, bolstering our balance sheet, and enabling us to prefund our world-class Guyana oil developments, while also returning capital to shareholders and reducing debt.

Our portfolio is now focused on Guyana and the Bakken as our growth engines and Malaysia in the deepwater Gulf of Mexico as our cash engines. On a pro forma basis, we expect to generate capital-efficient compound annual production growth of approximately 10% per year through 2020. The combination of investing in lower-cost assets and divesting higher-cost assets, along with a meaningful $150 million annual cost-reduction program, is expected to drive our cash unit production cost down by approximately 30% to less than $10 per barrel of oil equivalent by 2020. As a result, we expect to generate cash flow growth of more than 20% per year at a $50-per-barrel Brent oil price and more than 30% per year at a $60-per-barrel Brent oil price through 2020.

In terms of our portfolio high-grading, our asset monetizations in 2017 resulted in total proceeds of $3.4 billion and the release of $1.3 billion of asset retirement obligations. In October, we announced the sale of our mature higher-cost assets in Norway for total proceeds of $2 billion and Equatorial Guinea for total proceeds of $650 million. Both transactions closed in the fourth quarter as planned. These sales followed the divestiture of our mature Permian enhanced oil-recovery assets in August for total proceeds of $600 million and the successful IPO of Hess Midstream Partners in April that resulted in net proceeds of $175 million.

In addition, we have commenced a sales process for our interest in Denmark, which we expect to complete in 2018. Proceeds from our asset sales will first and foremost be used to prefund our world-class investment opportunity in Guyana. In addition, we plan to increase from four rigs to six rigs in the Bakken in the second half of 2018, where we have a robust inventory of high-return drilling locations. Also, we intend to buy back up to $500 million in stock and reduce debt by $500 million.

As we get further clarity on the capital requirements for future phases of development in Guyana as well as the outlook for oil prices, we plan to evaluate additional returns of capital to shareholders. Key to our strategy is our position in Guyana, an extraordinary oil investment opportunity, that is uniquely advantaged by its scale, reservoir quality, cost, rapid cash paybacks, and superior financial returns. The Stabroek Block in Guyana, where Hess has a 30% interest, covers 6.6 million acres and contains a massive world-class resource that keeps getting bigger and better. We have discovered some of the highest-quality reservoirs in the world, with high porosity and permeability that are expected to very high recovery factors and production rates.

Also, ExxonMobil, as a world-class operator, brings extensive project management experience and a great track record with this type of development. In January, we announced a sixth oil discovery on the Stabroek Block with the Ranger-1 well, which encountered 230 feet of high-quality oil-bearing carbonate reservoir. This world-class discovery confirms the presence of a working petroleum system more than 60 miles northwest of the Liza development area, increasing the prospectivity of this part of the block, where we see a number of large exploration prospects. Excluding Ranger, estimated gross discovered recoverable resources on the block were recently increased to more than 3.2 billion barrels of oil equivalent, up from the prior range of 2.5 billion to 2.8 billion of oil equivalent.

In addition, we continue to see multibillion barrels of additional exploration potential across the block. The Liza Phase I development, which was sanctioned last June, will develop approximately 450 million barrels of oil through an FPSO vessel, that will have the gross capacity to produce up to 120,000 barrels of oil per day. Development drilling is planned to start later this year. First production from the Liza Phase 1 development is expected in March 2020.

An application for an environmental permit to develop the second phase at Liza has been submitted. The concept involves a larger FPSO and subsea systems that would have a production capacity of approximately 220,000 barrels of oil per day, with start-up expected by mid-2022. As you may have seen from ExxonMobil's announcement last Friday, planning is also under way for a third phase of development, with an FPSO at Payara, closely following Liza Phase 2. The size of this third ship will be a function of future appraisal drilling.

With $7 per barrel unit development cost for Liza Phase I and cash payback in approximately three years at a $50 per barrel Brent oil price, our investment opportunity in Guyana is one of the most attractive in the world today. Now turning to our 2017 financial results. Our adjusted net loss was $1.4 billion, compared to $1.5 billion in 2016, and cash flow from operations, before changes in working capital, was $1.7 billion, up from $842 million in the prior year. As you saw in our release, we took a noncash charge of $1.7 billion in the fourth quarter for an accounting writedown of our Tubular Bells and Stampede assets to fair value.

John Rielly will talk more about this, but the charge was required under the accounting rules given our lower long-term oil price outlook and has no impact on our portfolio's ability to generate free cash flow at a $50 per barrel Brent oil price post-2020. In terms of 2017 reserve replacement, we had an outstanding year. We replaced 351% of production, with proved reserve additions of 397 million barrels of oil equivalent, at F&D cost of just over $5 per barrel of oil equivalent. Proved reserves at year-end stood at 1.15 billion barrels of oil equivalent, higher than 2016, even with asset sales that reduced reserves by 239 million barrels and production of 113 million barrels of oil equivalent during 2017.

And our reserve life was 10.2 years. Full-year production for 2017 was 295,000 barrels of oil equivalent per day, excluding Libya. Pro forma for the sales of our interest in Norway, Equatorial Guinea, and Permian [Inaudible] recovery assets, our production 2017 was 242,000 barrels of oil equivalent per day, excluding Libya. In 2018, our production is forecast to average between 245,000 and 255,000 barrels of oil equivalent per day, excluding Libya.

This forecast reflects reduced production of 60,000 barrels of oil equivalent per day due to asset sales and 15,000 barrels of oil equivalent per day due to the unplanned shutdown of Shell's Enchilada platform in the Gulf of Mexico, which is expected to be partially offset by growth in the Bakken and higher volumes from North Malay Basin. From our 2017 pro forma base of 242,000 barrels of oil equivalent per day, we remained on track to deliver 10% compounded annual production growth through 2020. Now turning to the Bakken, our largest operated growth asset. We have an industry-leading position, with more than 500,000 net acres in the core of the play, and are on track to grow production to approximately 175,000 barrels of oil equivalent per day by 2021, compared to 105,000 barrels of oil equivalent per day in 2017.

Through the application of geo-steering, optimized spacing, higher stage counts, and proppant loading, we've increased our well productivity by approximately 50% over the last two years. These improvements, together with our low drilling and completion costs, have enabled us to generate returns that are competitive with any shale play in the United States. The increased activity from two additional rigs in 2018 is expected to generate capital-efficient production growth of 15% to 20% per year through 2020 and deliver average returns that are in the range of 40% to 50% at a $50 per barrel WTI price from 2018 wells online. Bakken production in 2017 averaged 105,000 barrels of oil equivalent per day and in 2018 is forecast to average between 115,000 and 120,000 barrels of oil equivalent per day.

In summary, we continued to execute on our strategy and our reshaped portfolio is positioned to deliver a decade-plus of capital-efficient growth, with increasing cash generation and returns to shareholders. The success of our asset sales program in 2017 further focuses our portfolio on higher-return assets and lowers our cash unit costs, while strengthening our balance sheet to fund our world-class oil investment opportunity in Guyana, which we believe will create significant value for our shareholders for many years to come. Now, Greg.

Greg Hill -- Chief Operating Officer

Thanks, John. 2017 was marked by strong execution, both strategically and operationally. First, in terms of our developments, we achieved first gas in July at the North Malay Basin full field development, where Hess holds a 50% interest and is operator, safely on time and under budget. During the fourth quarter, North Malay Basin reached its planned plateau rate of approximately 165 million cubic feet of net gas per day, establishing the asset as a significant long-term, low-cost cash generator for the company.

Throughout 2017, we also successfully advanced development of the Stampede Field, where Hess is operator and has a 25% interest. I'm pleased to announce that we have achieved first oil from the field in January. That Hess team, working effectively with our partner Chevron, Statoil, and Exxon, delivered a highly complex project in just over three years from sanction, safely ahead of schedule and under budget. We intend to gradually ramp up production over the next eight months.

Second, in the Bakken, we executed successful pilots of 60-stage completions with increased proppant loading, which confirms that we are getting a 10% to 15% uplift in IP 180 productivity in expected ultimate recovery, or EUR, from our previous standard. As a result, we have increased our EUR estimate from our Bakken acreage to 2 billion barrels of oil equivalent from our previous estimate of 1.7 billion barrels of oil equivalent. Wells brought online in 2018 are expected to deliver an average EUR of greater than 1 million barrels of oil equivalent and generate returns of 40% to 50% at a $50 per barrel WTI. In addition, we've increased by 25%, the number of wells that can deliver a 15% return or higher at $50 per barrel WTI to 1,780 wells, which represents more than 60% of our remaining well inventory.

Third, on the 6.6 million acres Stabroek Block in Guyana, where Hess has a 30% interest, the extraordinary exploration success continues. With discoveries in 2017 at Payara, Snoek, Liza Deep, and Turbot. In January, we announced a sixth oil discovery. The Ranger-1 well encountered approximately 230 feet of high-quality oil-bearing carbonate reservoir.

This is important in that it demonstrates a working petroleum system more than 60 miles northwest of Liza and opens up multiple further play types across the Stabroek Block. Excluding Ranger, discovered recoverable resources for the block were increased to 3.2 billion gross barrels of oil equivalent, more than triple the estimate from this time last year. In June 2017, we sanctioned the first phase of Liza development, which will develop on a gross basis approximately 450 million barrels of oil through an FPSO vessel with gross capacity of 120,000 barrels of oil per day. First production from the Liza Phase 1 development is expected in March 2020.

Fourth, we successfully executed $3.4 billion of monetizations in 2017, with values and timing that exceeded expectations. Fifth, we delivered proved reserve additions of 397 million net barrels of oil equivalent, representing an organic replacement rate of 351% and an F&D cost of just over $5 per barrel of oil equivalent. About 70% of the additions were in the Bakken, reflecting new proved undeveloped reserves, improved prices, and our enhanced completion designs. Other significant developments include North Malay Basin and Stampede as well as initial reserve bookings in Guyana.

Now turning to results and starting with production. In the fourth quarter, production averaged 282,000 net barrels of oil equivalent per day, excluding Libya. This result reflects unplanned downtime at the Shell-operated Enchilada platform in the Gulf of Mexico, which experienced a fire on November 8 and remains down. As a result, production is shut in at our Baldpate, Conger, and Penn State Fields, as well as the Shell-operated Llano Field, with a daily production impact of approximately 30,000 net barrels of oil equivalent per day.

The operator is working to safely restore production. Excluding Libya, full-year 2017 production averaged 295,000 net barrels of oil equivalent per day, which reflects an impact from the unplanned downtime at Enchilada of approximately of 4,000 net barrels of oil equivalent per day. In 2018, we forecast production to average between 245,000 and 255,000 net barrels of oil equivalent per day, excluding Libya. This forecast reflects the divestments completed in 2017, representing approximately 60,000 net barrels of oil equivalent per day and an estimated annual impact from Enchilada of 15,000 net barrels of oil equivalent per day over 2018.

Our forecast also reflects higher year-over-year production from the Bakken and North Malay Basin of 12,000 and 15,000 net barrels of oil equivalent per day, respectively as well as increasing production from Stampede. We forecast production in the first quarter of 2018 to average in the range of 220,000 to 225,000 net barrels of oil equivalent per day, increasing to between 265,000 and 275,000 net barrels of oil equivalent per day in the fourth quarter, as our impacted Gulf of Mexico production is reinstated and as Bakken and Stampede ramp up. On a pro forma basis, net production is forecast to grow by approximately 10% per year between 2017 and 2020. Now turning to the Bakken.

In the fourth quarter, production averaged 110,000 net barrels of oil equivalent per day, which represented an increase of more than 15% from the year-ago quarter. Oil production in the fourth quarter was 69,000 net barrels per day versus 63,000 net barrels per day for the third quarter of 2017. For the full year 2017, production averaged 105,000 net barrels of oil equivalent per day. In 2018, we plan to add a fifth rig in the Bakken during the third quarter and sixth rig during the fourth quarter.

The timing reflects permitting and the efficiency of doing road and pad construction during the fair-weather period between May and October. We expect to drill approximately 120 wells and bring approximately 95 new wells online over the year, compared to 85 wells drilled and 68 wells brought online in 2017. For the first quarter, we expect Bakken production to average approximately 105,000 net barrels of oil equivalent per day, reflecting a modest reduction in NGL volumes due to market factors. Oil volumes are expected to remain flat for the fourth quarter of 2017.

For the full year 2018, we forecast our Bakken production to average between 115,000 and 120,000 net barrels of oil equivalent per day, approximately 12% above 2017 levels. Longer term, we continue to forecast steady Bakken production growth, to approximately 175,000 net barrels of oil equivalent per day by 2021, with a maximum rig count of six. Moving offshore. In the deepwater Gulf of Mexico, production averaged 40,000 net barrels of oil equivalent per day in the fourth quarter and 54,000 net barrels of oil equivalent per day for the full year 2017, reflecting the unplanned downtime at the Shell-operated Enchilada platform discussed earlier.

As a consequence, we forecast 2018 production from our deepwater Gulf of Mexico assets to average approximately 50,000 net barrels of oil equivalent per day, which again assumes a full-year production impact of 15,000 net barrels of oil equivalent per day. In the fourth quarter, when all impacted fields are expected to be back online, we forecast Gulf of Mexico production to average approximately 65,000 net barrels of oil equivalent per day. At the Malaysia/Thailand joint development area in the Gulf of Thailand, in which Hess has a 50% interest, production averaged 35,000 net barrels of oil equivalent per day in the fourth quarter and 37,000 net barrels of oil equivalent per day for the full year 2017. Net production is forecast to average approximately 36,000 net barrels of oil equivalent per day in 2018.

At the North Malay Basin, also in the Gulf of Thailand, net production averaged 26,000 barrels of oil equivalent per day over the fourth quarter and is forecast to also average approximately 26,000 net barrels of oil equivalent per day in 2018. Turning to Guyana. Following completion of the Ranger-1 well, the Stena Carron drillship has now spud the Pacora prospect, which is located 4 miles west of the Payara discovery. Additional exploration drilling is planned on the Stabroek Block for 2018, including appraisal of the Liza, Turbot, and Ranger discoveries, as well as a wider exploration program that will target additional prospects and play types on the block, where we continue to see multibillion barrels of exploration upside.

Development activities are also continuing on the Stabroek Block. The Liza Phase 1 development is progressing and remains on track for first oil in March 2020. Conversion of the VLCC, very large crude carrier, to an FPSO is progressing and development is planned to start later this year. In addition, planning for the second phase of development at Liza's under way, that is expected to utilize an FPSO with a gross-production capacity of approximately 220,000 barrels of oil per day.

Startup for Liza Phase 2 is expected by mid-2022. A third phase of development will focus on the Payara area and is expected to closely follow Liza Phase 2. In Suriname, where Hess holds a 33% interest in the 1.3 million-acre Block 42, along with Chevron and the operator Kosmos, interpretation of 3D seismic continues and we are seeing a set of attractive prospected leads similar to those seen on Stabroek. A first explorational well on the block is planned for the second half of 2018.

At the 2.8 million-acre Block 59, where Hess also holds a 30% -- 33% interest together with Statoil and the operator ExxonMobil, plans are under way to acquire 2D seismic in 2018. In Canada, Hess has partnered with operator BP to explore four deepwater frontier licenses offshore Nova Scotia, which combined are equal in size to approximately 600 deepwater Gulf of Mexico OCS blocks. Hess has a 50% working interest. Based on 3D seismic data, the geology appears analogous to deepwater Gulf of Mexico.

A first playtest is planned to spud in the second quarter of 2018. In closing, in 2017, Hess once again demonstrated strong execution on all fronts. We've taken proactive steps to high-grade our portfolio, move down the cost curve, and build a business that will be cash flow-generative down to $50 per barrel Brent post-2020. Our leading position in the Bakken promises continuing growth and material future cash flow.

Exploration results to date underline the exceptional world-class potential of the Stabroek Block in Guyana, and we are excited by potential extension to the plays in the Block 42 and 59 in neighboring Suriname. I will now turn the call over to John Rielly.

John Rielly -- Chief Financial Officer

Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2017 to the third quarter of 2017 and provide guidance for 2018. We incurred a net loss of $2.677 billion in the fourth quarter of 2017, compared with a net loss of $624 million in the previous quarter. Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $304 million in the fourth quarter of 2017, compared with an adjusted net loss of $324 million in the previous quarter.

Fourth-quarter results include an after-tax gain of $486 million from the sale of our interest in Equatorial Guinea and an after-tax loss of $857 million from the sale of our interest in Norway, both in line with estimates provided in our third quarter Form 10-Q. The fourth quarter also includes charges related to the Tubular Bells and Stampede Fields in the Gulf of Mexico, totaling $1.7 billion primarily based on a fourth-quarter reduction to our long-term oil price outlook used in our impairment test. The charge related to Tubular Bells is $605 million, while the charge related to Stampede is $1.095 billion, where we incurred significant exploration and appraisal costs prior to unitizing into the Stampede project. In addition, we fully impaired our Deepwater Tano Cape Three Points project offshore Guyana, with an after-tax charge of $280 million based on management's decision to not pursue the development project.

We are currently evaluating options to monetize our Guyana asset. Turning to the new tax law. In December, the new Tax Cuts and Jobs Act was signed into law, providing broad changes to the taxation of both domestic and foreign operations. We do not expect any U.S.

federal cash tax on deemed repatriation of unremitted earnings of our foreign subsidiaries, and the impact of the change in alternative minimum tax rules was immaterial. Further, we still do not anticipate any U.S. federal cash taxes over at least the next five years. Our tax-loss carry-forwards and tax basis and fixed assets as of December 31, 2017, will continue to provide a significant cash tax shield, and under the new law, substantially all of our foreign earnings will qualify for exemption from U.S.

federal tax. The decrease in the corporate tax rate to 21% from 35% leads to an approximate $1.475 billion reduction to our U.S. net deferred-tax asset, which predominantly relates to the NOL carry-forward. A corresponding reduction in the previously established U.S.

valuation allowance offsets this adjustment. Consequently, the remeasurement of deferred taxes using the newly enacted tax rate has no net impact on the income statement or balance sheet. Turning to E&P. On an adjusted basis, E&P incurred a net loss of $219 million in the fourth quarter of 2017, compared with a net loss of $238 million in the third quarter of 2017.

The changes in the after-tax components of adjusted E&P results between the fourth quarter and third quarter of 2017 were as follows: higher realized selling prices improved results by $133 million; noncash option premium amortization on crude oil callers reduced results by $38 million; the change in mix of sales volumes reduced results by $33 million; higher exploration expenses, primarily seismic cost, reduced results by $32 million; higher cash costs reduced results by $17 million; lowered DD&A expense improved results by $18 million; all other items reduced results by $12 million, for an overall improvement in fourth-quarter results of $19 million. The E&P effective income tax rate, excluding specials and Libyan operations, was an expense of 21% for the fourth quarter of 2017, due primarily to the accounting for assets held for sale compared with a benefit of 18% in the third quarter. Turning to midstream. The Midstream segment had net income of $20 million in the fourth quarter, compared to adjusted net income of $22 million in the third quarter of 2017.

Midstream EBITDA, before the noncontrolling interest and excluding specials, amounted to $113 million in the fourth quarter, compared to $109 million in the third quarter of 2017. Turning to corporate and interest. After-tax corporate and interest expenses were $105 million in the fourth quarter, compared to a net adjusted expense of $108 million in the third quarter of 2017. Turning to fourth-quarter cash flow.

Cash provided by operating activities before changes in working capital was $492 million; changes in working capital reduced operating cash flows by $149 million; additions to property, plant, and equipment were $554 million; proceeds from the sale of assets were $2.513 billion; net borrowings increased cash by $280 million; common stock acquired and retired were $110 million; common and preferred stock dividends paid were $90 million; distributions to noncontrolling interest were $35 million; all other items were a net decrease in cash of $26 million, resulting in a net increase in cash and cash equivalents in the fourth quarter of $2.321 billion. We estimate the fourth-quarter impact from the Enchilada platform shutdown was a reduction to cash flow from operations of approximately $55 million. Turning to our financial position. Excluding midstream, cash and cash equivalents were $4.5 billion, total liquidity was $8.9 billion, including available committed credit facilities, and debt was $5.997 billion.

We remain focused on maintaining a strong balance sheet and providing current returns to shareholders. In January, we called for redemption of our 8.125% notes due February 2019, with a principal amount of $350 million, and we plan to repay an additional $150 million principal amount of debt in 2018, for a total of $500 million in debt reduction. We also continue to execute our previously announced plan to repurchase $500 million of our common stock. We purchased $120 million in the fourth quarter of 2017 and plan to purchase the remaining $380 million of stock during 2018.

Turning to our cost-reduction program. As part of our portfolio reshaping, we have begun implementation of an organizational restructuring and cost-reduction effort, targeting annual savings of $150 million. In addition to direct headcount reductions as part of our asset sales, we eliminated approximately 400 employee and contractor positions in January and expect to record employee severance of $40 million to $50 million in the first quarter. Since the end of 2014, total employee and contractor positions have been reduced by approximately 50%.

In addition to the workforce reduction, we have identified further cost reductions in logistics, information technology, property, professional fees, and other operating costs as a result of our portfolio reshaping. The benefit from this $150 million annualized cost reduction will begin to be realized over the second half of 2018. Now turning to first-quarter and full-year 2018 guidance. Before I give guidance for 2018, which excludes items affecting comparability of earnings, I will provide full-year 2017 pro forma financial metrics that remove the impact of assets sold during the year.

Pro forma cash costs were $13.09 per barrel of oil equivalent, as compared to actual results of $14.30 per barrel. And pro forma DD&A was $23.62 per barrel versus actual DD&A of $24.53 per barrel. Finally, our pro forma tax rate excluding specials and Libya was a pro forma benefit of 4%, as compared to a reported benefit of 7%. We project our cash cost per barrel in 2018 to decline significantly during the year, as production related to Enchilada fully resumes and our cost reductions begin to be realized in the second half of the year.

In the first quarter, due to the impact of the Enchilada fire, which is estimated to shut in approximately 25,000 barrels of oil equivalent per day of low-cost production, cash costs are projected to be $15 to $16 per barrel. We project the remaining quarters to be lower, with an average cost of $12.75 per barrel and our fourth-quarter cash cost to be below $12 per barrel, as compared to portfolio cash cost of $13.09 in 2017. DD&A per barrel of oil equivalent for the full-year and first-quarter 2018 is forecast to be in the range of $18 to $19 per barrel, down from 2017 pro forma DD&A of $23.62 per barrel. This results in projected total E&P unit operating costs of $31 to $33 per barrel for the full year of 2018, down from 2017 E&P pro forma unit cost of $36.71 per barrel.

Exploration expenses, excluding dry hole costs, are expected to be in the range of $190 million to $210 million for the full year of 2018 and $45 million to $55 million in the first quarter of 2018. The midstream tariff is projected to be in the range of $625 million to $650 million for the full year of 2018, which is up from 2017 midstream tariff of $543 million due to higher Hess operated and third party volumes. The midstream tariff is expected to be approximately $150 million for the first quarter of 2018. The E&P effective tax rate, excluding Libya, is expected to be a benefit in the range of 0% to 4% for the full year and first quarter of 2018 versus a pro forma benefit of 4% for the full year of 2017.

As highlighted earlier, we have crude oil contracts to hedge price risk for 2018 production. For 2018, we expect the noncash premium amortization from these contracts, which will be reflected in our realized selling prices, will reduce our results by approximately $30 million per quarter. In midstream, in 2018, we anticipate net income attributable to Hess from the midstream segment to be in the range of $105 million to $115 million for the full year and approximately $25 million in the first quarter. Now for corporate and interest.

We expect corporate expenses to be in the range of $105 million to $115 million for the full year of 2018, down from $134 million in 2017, and $25 million to $30 million for the first quarter. We estimate interest expense to be in the range of $345 million to $355 million for the full year of 2018, which is higher than last year as we will not be capitalizing interest for the Stampede project, which commenced production in January. First-quarter interest expense is expected to be $85 million to $90 million. This concludes my remarks.

We will be happy to answer any questions. I will now turn the call over to the operator.

Questions and Answers:

Operator

Ladies and gentlemen, if you have a question please press * followed by 1 on your phone. If your question has been answered or you would like to withdraw your question press #. Questions will be taken in the order received. Please press *1 to begin.

Your first question comes from a line of Roger Read. Your line is now open.

Roger Read -- Wells Fargo -- Analyst 

Hi, thanks. Good morning.

John Hess -- Chief Executive Officer

Good morning.

Roger Read -- Wells Fargo -- Analyst 

I guess, if we could talk maybe a little bit here, your performance in the Bakken, six rigs is going to deliver growth up to the 175 level by 2021. How much more improvement in well performance is factored in on that?

John Hess -- Chief Executive Officer

Yes. Thanks for the question, Roger. As we said in our opening remarks, our new completion design, which is a 60-stage, 140,000 pounds per stage, has resulted in a 10% to 15% uplift in EUR and also IP 180 rates. That 175 at six rigs reflects improvement from that move to that new completion design.

Roger Read -- Wells Fargo -- Analyst 

So solely that design, not something additional from here?

John Hess -- Chief Executive Officer

No, I think we continue to optimize. We continue to look at other completion techniques. For example, we're doing some plug and perf pilots this year. Reason being is, as the industry has continued to improve, the limited entry perforating in particular on plug and perf is allowing a very large number of entry points with very good fracture control.

And so we're looking at that and are going to pilot some of that this year. So potentially, there could be a move to that. But we need to get more experience under our belt. And certainly, we know that we're going to have to do plug and perf outside the core.

So that's why we want to really begin to experiment with that stuff.

Roger Read -- Wells Fargo -- Analyst 

OK. Thanks on that. And then as we look at, just broadly, the cash flow from operations here. You referenced the Gulf of Mexico and NMB as your cash cow, so to speak.

Can you frame at all, kind of expectations for cash from those operations as we think about 2018 and 2019, maybe kind of think about maybe a $60 oil price outlook there?

John Rielly -- Chief Financial Officer

Sure. So now with the NMB coming online, our Malaysia assets are going to be significant free cash flow generator. As you can see, the Asian gas price that we now have. What we have in JDA is actually going to be the lowest, I guess, of the gas price because it goes back to 2016 oil prices.

So we'll have that price through September 30 of 2018 and then it will increase going to 2017 prices. And then, obviously, so far in '18, with the prices getting higher, JDAs price will continue to increase. North Malay Basin basically only has a one-month lag on oil prices. So we are seeing a benefit of that reflected right into our gas prices in North Malay Basin.

So if you looked at the number in that fourth quarter, JDA is below that average and North Malay Basin basically, significantly above that average. So we're seeing significant free cash flow actually from the Malaysian assets in 2018. And that will continue as you move into 2019 and 2020 because we'll start slowly bringing down the capital to -- in North Malay Basin. As far as Bakken goes, so this year, we are actually reducing the cash flow from the Bakken a bit because we're moving to the six rigs.

And, as Greg said, the fifth and sixth rigs are coming in the third -- one in the third quarter one in the fourth quarter. So the wells that are drilled by the fifth and sixth rigs are really not impacting production or cash flow in 2018. So we get the uplift on production and cash flow in '19 from that. So while Bakken will be generating free cash flow, it will be more in '19.

And then, obviously, with this growth that you just heard that Greg talked about, that will begin to significantly increase cash flow from the Bakken. And then, obviously, the other piece of our business is Gulf of Mexico. It's always been a significant free cash flow generator for us. Now Stampede is coming online.

So the capital is being reduced from the prior year. We do have this deferred production, which, as I guided, was about $55 million effect to cash flow in the fourth quarter. It's reasonable for you to use about $1 million a day from that being shut in. So you've got 15,000 barrels a day.

So you're getting on a half-year base basis on that 30,000 barrels. It is affecting us like somewhere about $180 million and $200 million in 2018. But Gulf of Mexico is going to be a significant cash flow generator, as Stampede continues to ramp up and we continue now to be -- actually bringing capital down there. So that's kind of how the cash flow works in our portfolio.

Roger Read -- Wells Fargo -- Analyst 

OK, thank you.

Operator

Our next question is from a line of Doug Leggate with Bank of America Merrill Lynch. Your line is now open.

Doug Leggate -- Bank of America Merrill Lynch

Thank you. Good morning, everybody.

John Hess -- Chief Executive Officer

Morning.

Doug Leggate -- Bank of America Merrill Lynch

Gents, I wonder if you can give us any idea if your cadence you're assuming on -- I mean, it sounds like Enchilada is down for the first half of the year, that was kind of what you're assuming. What are you assuming for the cadence for Stampede and Bakken? And I wonder if you can give an exit rate for '18 for both of those plays?

Greg Hill -- Chief Operating Officer

Yes, Doug, let me talk about Stampede first. We will gradually bring that production on over the year. The first piece it will come on is Penn State and Baldpate, that will come on in the first quarter. The next thing that will come on is Llano, which is in the second quarter.

And then finally, Conger will come on toward the end of the third quarter. So that's sort of the cadence there. So we pick up all that production by, certainly, fourth quarter. All of that comes back on.

So it will gradually come up. And if you want kind of a quarterly impact of the Gulf of Mexico, it's about 26,000 barrels a day in the first quarter, it's about 17,000 in the second quarter, it's about 15,000 in the third quarter. So that's the cadence there. And in terms of Stampede, we're going to gradually ramp it up over the next 18 months, we've got three producers capable of producing now.

We'll continue to drill producers throughout the year and into 2018. So gradually bring those up. And then in the fourth quarter, Stampede will average about 10,000 barrels a day and then will continue its climb net, obviously. And then will continue its climb in 2018 as we bring additional producers that we drill this year on production.

And I think, just overall production, I think the important thing is that we mentioned in our opening remarks, that whole increase from the first quarter to the fourth quarter, as you mentioned our production's going to be very strong and exit the year very strong in the fourth quarter. So in the fourth quarter, we're going to exit the year 265 to 275, whereas the first quarter of 220 to 225. So that's a significant increase over the year.

Doug Leggate -- Bank of America Merrill Lynch

OK, just to be clear, Greg, on the Bakken, what are you assuming there in the Bakken exit rate? I'm just wondering if you have any weather issues to impact the first quarter given the depth you're seeing?

John Rielly -- Chief Financial Officer

No, in the first quarter, Doug, we didn't have any weather issues. Again, as Greg said, oil will be flat from the fourth quarter to the first quarter. It's above ground NGL volumes. And what it is, is we had some ethane rejection.

And by the way, none of this impact actually our financial results. But there was some ethane rejection that we had in the first quarter that we're having, as well as higher NGL prices. It just works the way we process our gas, that when you get volumes to -- up to the amount of the gas processing fees. So if the prices are higher, your NGL volumes go down.

So there's no impact at all really from weather. We did see some right at the beginning, there was some difficult weather, but it didn't really impact, as you saw, we came in at the high end of the guidance in the fourth quarter. And yes, there is some impact early on in January but it's really not impacting our overall volumes. And I think you asked with growing, we said that the Bakken will be 115 to 120 over the year, so obviously, you start at 105, by the time you get to the fourth quarter, it's going to be higher than that range that we have there.

So it's going to be right at the upper end of the range.

Doug Leggate -- Bank of America Merrill Lynch

[Inaudible] Yes, go on, I'm sorry.

Greg Hill -- Chief Operating Officer

Yes, 120 to 125, Doug, in the fourth quarter.

Doug Leggate -- Bank of America Merrill Lynch

Thank you. My follow-up, Greg, is on Guyana. I guess a couple of interrelated points, if I may. Greg, can you tell us what the implication is of the carbonate versus the strat plays you've got at Ranger.

Obviously, that is not yet in the 3.2 billion. So give us an idea of what you -- the implications could be there. And I guess my follow-up would be for Mr. Hess.

John, it seems that Exxon is laying out a line of sight now in development, the PSC is now public. So what else do you need to see to reset your buyback program? Because it looks like the spending allocation or the requirement is going to become pretty transparent here fairly soon. And I'll leave it there, thanks.

Greg Hill -- Chief Operating Officer

Yes, thanks, Doug. I'll go first on Ranger. So obviously, Ranger, very significant outcome for the block. Why? Two hundred thirty feet of very high-quality oil-bearing carbonate reservoir.

Secondly, it's located 60 miles northwest of Liza, which says that the play is working certainly in terms of charge. The play is working that far away from Liza there. I think the third thing is that we see a number of additional carbonate features on the block. So that says that the carbonate system is working now.

Obviously, we've got to get wells in those eventually. But it bodes very well for the block in Guyana and potentially even Suriname as well.

John Hess -- Chief Executive Officer

Happy to talk about your question, Doug. Look, obviously, we have an extraordinary investment opportunity in Guyana. It truly gets bigger and better. And we're delighted that ExxonMobil announced last Friday on their quarterly call, that the second FPSO would be a larger ship, 220,000 barrels a day and start production in 2022.

And that would make our net working interest production from Guyana over 100,000 barrels of oil per day by 2022. And also, they announced that engineering would start on a third FPSO and that would come on shortly thereafter, Liza-2. The size of that is going to be a function of further appraisal drilling starting with Payara that we are currently drilling now. So your point is, as we get more transparency, the transparency is the capital need is going up.

And so we need to get some more definition in those costs and oil price before we would consider adding to our share-repurchase program of the $500 million that's already under way. So some more work and visibility on that. But I think the most important thing is, this is a phenomenal, one of the world's best return investments in the oil industry. And we are extremely well-positioned to capitalize on it.

And to prefund it with the cash that we have, not just for FPSO 1 but FPSO 2. And those financial returns are going to distinguish our company for many years to come. We have to be in position to capitalize on it and that's our first, second and third priority. As the costs get a little bit more defined on FPSO 2 and the engineering for FPSO 3, serious consideration will be to add to the share-repurchase program that's under way already.

Greg Hill -- Chief Operating Officer

Doug, just one other comment on Guyana. if you think about Turbot, which is 30 miles southeast of Liza, and then you have Ranger, which is 60 miles northwest of Liza, given that petroleum system is working over that entire aerial expand, it also opens up other play types as being highly prospective in addition to the carbonate. So there's further play types on the block as well.

Doug Leggate -- Bank of America Merrill Lynch

Thanks, guys.

Operator

Our next question is from Brian Singer with Goldman Sachs. Your line is now open.

Brian Singer -- Goldman Sachs -- Analyst

Thank you, good morning.

John Hess -- Chief Executive Officer

Morning.

Brian Singer -- Goldman Sachs -- Analyst

Wanted to follow up on a couple of the questions there earlier. First, on Guyana. When you and the operator and other partner have conversations and you see the resource that's been discovered, what if anything, would it take to accelerate the development to have two FPSOs moving for development at the same time or for the same schedule, i.e. not necessarily in every 18 to 24 months-type schedule? Is there anything that could happen there? Or do you see this as more definitively every discovery that you make will be very much staged in an order or down the line?

Greg Hill -- Chief Operating Officer

Couple of comments there, Brian. I think, first of all, we did mention that Phase 3 some further appraisal drilling is required to really define how big that's going to be. So that's the first step. I think the second step relates to how do you, very efficiently, develop this massive resource in Guyana.

And certainly, the view of ExxonMobil and us and Nexen is that the right way to do it is a phased approach, where you use the same project team and the construction resources, etc., etc. And really just continue to phase this development in such a way that it becomes very capital-efficient to do that versus, say, three things going in parallel, right?

John Hess -- Chief Executive Officer

And you know, as Exxon said in their call, that they're progressing concept selection for Payara and the start-up there is planned for 2023 or 2024, which actually could mean 12 to 18 months from Liza Phase 2 as opposed to 24 months. So Exxon is definitely getting more efficient in this assembly line process. And the definition of that, Brian, obviously, we need the appraisal drilling to be able to finalize what the size of that ship is going to be.

Brian Singer -- Goldman Sachs -- Analyst

That's great. And then my follow-up is with regard to the Gulf of Mexico. I'm trying to piece together some of the moving pieces of the Stampede and then the Enchilada platform. But also get your sense of whether there's been any changes in the underlying decline rate in the Gulf and what that is.

And I think in response to an earlier question, you threw out some numbers of 26,000, 17,000, and 15,000 maybe in the first quarter, second quarter, third quarter. Wondered if -- is that total production that's falling in Q2 and Q3 versus Q1 or just maybe I missed those numbers?

Greg Hill -- Chief Operating Officer

No, thanks for the clarification question, Brian. What that was, was the impact of the Enchilada fire on Hess Gulf of Mexico production quarter by quarter. So, again, it's 26,000 barrels a day off production on average in Q1. It's 17,000 barrels a day on average in Q2, and then 15,000 barrels a day on average in Q3.

And that reflects the cadence that I talked about where Baldpate and Penn State come on in the first quarter, Llano comes on in the second quarter, and then finally, Conger, the last piece, comes on in the third quarter. So that's what that reflects. And then the other piece of the equation in the Gulf of Mexico is Stampede. As I said, that's going to gradually ramp up over 18 months.

We just started first oil in January, we're going to ramp those wells up very slowly. That's been a big learning for industry that you need to bring these on very slowly. And we will average in the fourth quarter, some 10,000 barrels a day. So that kind of gives you how the trajectory of the Gulf of Mexico will go.

The rest declines very shallow. So declines not a big factor in the Gulf of Mexico this year.

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you.

Operator

Our next question is from Michael Hall with Heikkinen Energy Advisors. Your line is now open.

Michael Hall -- Heikkinen Energy Advisors --  Analyst

Thanks. Actually, prior question hit on the No. 1. But just final -- I guess one more final follow-up on Stampede.

Can you just remind me, what do you think the kind of peak production profile of Stampede would look like and when you reach that?

Greg Hill -- Chief Operating Officer

Yes, Michael, so -- it's early days and what we'd like to do is get some dynamic data on these wells before we be as specific as what we think the peak rate will be. As I said, we will wrap this up over the next 18 months. So as we get that dynamic data, see what the wells are going to do -- we just started this thing in January, then we'll be able to give some more definitive guidance on peak rates.

Michael Hall -- Heikkinen Energy Advisors --  Analyst

Fair enough. That's all I'll have in the moment. Thanks

Operator

Our next question is from Ryan Todd with Deutsche Bank. Your line is now open.

Ryan Todd -- Deutsche Bank -- Analyst

Maybe a couple for me. As you -- you talked about the monetization process for the assets in Denmark. As you look across the rest of the portfolio, are you happy with the current state of the portfolio? Would you consider selling any of the Asian assets? Or are you in a position where you could consider farming down Guyana at all? Or is this still too much undiscovered resource at this point?

John Hess -- Chief Executive Officer

Obviously, we've been pretty active optimizing our portfolio. We have an open mind. We're always there to maximize value. We have a long-term strategy and portfolio that we and the board worked on to have the cash generators along with the growth engines in Guyana and the Bakken.

So we will always have an open mind to maximize value as we've shown in the past. Having said that, the major focus of the company is to capitalize on the amazing investment opportunity we have in the Guyana and the Bakken and to do that, we've got to have a strong balance sheet and cash. We don't have a funding deficit, we prefund it. And as Guyana gets bigger and better, with FPSO 2 now being defined and FPSO 3 and, by the way, a pretty active exploration and appraisal program, we got to make sure we have the cash for that.

So our focus is much more on Guyana and then funding the world-class investment opportunity and high financial returns there. To sell part of that would not be the right thing for our shareholders because that is probably the best investment return, certainly in Hess' portfolio and one of the best in the industry. And if we could get more of it, we would. But selling it would be the wrong thing to do.

Ryan Todd -- Deutsche Bank -- Analyst

Thanks. That's very helpful. And maybe one follow-up on the Bakken. I mean, clearly very strong well results.

Can you clarify -- I think -- did you say that the drilling program in 2018 would have an average EUR per well of over 1 million barrels? And do you have an estimate of what the average per well EUR would be across the 1,780 high-rate-of-return inventory that you talked about?

Greg Hill -- Chief Operating Officer

So let me start with the 2018 program. Yes, you're correct. So the average EUR this year would be north of 1 million. Average IP 180, so this is cumulative now, is north of 100,000 barrels of oil.

And then also if you -- what in our portfolio do we think can generate over 1 million barrels a day or 1 million barrels of EUR, there's about 500 or so wells in our portfolio that can do that with our current completion design of 60-stage 140,000 pounds. That's substantially up from where it was last year as a result of moving to that better completion design.

Ryan Todd -- Deutsche Bank -- Analyst

Great. Thank you.

Operator

Our next question is from Paul Cheng with Barclays. Your line is now open.

Paul Cheng -- Barclays -- Analyst

Good morning. Greg, when you gave the production guidance, is that built in some time line, the -- them -- [Inaudible] said when it's going to be done? Or that -- the high [Inaudible] production is in there?

John Rielly -- Chief Financial Officer

What we have -- so in the -- Paul, in the pro forma numbers that we gave for 2017, of the 242,000 barrels a day that we only took out the assets sold, so Denmark is in there and we have Denmark in our production guidance next year. So if you wanted to take 10,000 barrels out of the 242,000, drop it to 232,000, and if you could take 10,000 barrels out of our '18 production, if you were doing a comparison. So I just want to make sure when everybody looks at that our pro forma of 242,000, our midpoint right now is between the 245,000 and 255,000 is 250,000. If you add the Enchilada effect to 265,000, we're getting to that 10% pro forma growth that Greg had talked about that will continue in through 2020.

Paul Cheng -- Barclays -- Analyst

And John, when you take the way down on Stampede and Tubular Bell, you say is based on the lower commodity prices? Can you share with us at what price that you're using? I mean, is it really significantly down? I mean, so what kind of carrying costs you still have endorsed to?

John Rielly -- Chief Financial Officer

So we -- I'm not going to be specific, exactly, on our -- on the crude oil price outlook that we have and went through with the board. But let's just start with what we are doing from a management standpoint of the business. So from the management standpoint of the business, as we said, we are managing to $50 and being able to generate free cash flow at $50 post the Guyana start-up. And we are well on our way on track for that.

So, again, with this pro forma production growth, 10% per year, plus our cash cost, as I said, by the fourth quarter, going under $12. So by 2020, we'll have our cash cost down to $10. And again, now generating that free cash flow. So as it relates to, just in general, where we're going with our cost reductions, we'll start getting that in the second half of the year.

We're going to even get then the full annualized effect in 2019 and then that will drop our cash cost per barrel even lower, as we move into '19.

Paul Cheng -- Barclays -- Analyst

John, the $150 million of cost reduction, where are they going to show up the most? Is it in the corporate items or just in the upstream operating costs? Or what line item that you're going to see the benefit?

John Rielly -- Chief Financial Officer

We saw -- if you noted in my guidance for corporate, so what you see actually in '18 already is about $24 million reduction in our corporate expenses, if you just take the midpoint of our corporate guidance. So we're beginning to get that impact right now in corporate. We're going to have severance charges, there will be pension charges, so with things like that going through. But what I would tell you in general by the time we get to the end of this, about two-thirds of the savings, just I'm using round numbers, Paul, is going to be labor-based and then the one-third is going to be the other operating cost that I talked about.

So that labor base will go between corporate, E&P, and also within operating cost in production and even within exploration G&A too as well as. So it's going to be spread throughout kind of the line items that we have in our financial statements.

Paul Cheng -- Barclays -- Analyst

OK. Can you tell us that what is the Stampede and Tubular Bell -- the cash operating cost may look like this year and also by year 2020?

John Rielly -- Chief Financial Officer

So for Stampede, as Greg said, there will be this slow ramp, right? So cash cost per barrel will not be, obviously, at its regular operating level at the beginning. So cash cost will be a little bit higher. But just like all Gulf of Mexico fields, these are going to -- Stampede itself is going to be below $10 as that is -- as Greg said, when you get to the fourth quarter and you get that up to the 10,000 barrels a day. So, again, Gulf of Mexico is always a good low-cost operating environment.

Tubular Bells is just a little bit higher and we said because we've leased that facility. So that's the one unique asset you have in the Gulf of Mexico. So Tubular Bells is above $10 for that. But that will hold steady at that rate.

Paul Cheng -- Barclays -- Analyst

And two final one for me. One on the hedging. You haven't extended any additional hedging into 2019, right? In 2018, are we still talking about 150,000 barrel per day or that have also been changed? I was wondering if you can comment on Ghana that what have changed leading to say make the decision not to develop?

John Hess -- Chief Executive Officer

Sure. So from the hedging standpoint, just confirming your point that in 2019 -- we have not added any hedges in 2019, with the backwardation basically in the curve. So for 2018, it is unchanged. It is in the back of the release, it's 115,000 barrels per day, correct, that we have the callers on in 2018.

John Rielly -- Chief Financial Officer

Yes, and Paul, in terms of Ghana, it's a good asset, there's oil there. But our strategy is to invest in the highest-return projects, be capital-disciplined and committed to being cash flow-generative at a $50 Brent price post-2020 as Liza Phase I comes on. And quite frankly, that project, while a good project, just can't compete for capital relative to the other investment opportunities we have. So as a consequence, we're currently looking at options to monetize our Ghana asset.

Paul Cheng -- Barclays -- Analyst

Thank you.

Operator

Our next question is from Arun Jayaram with JP Morgan. Your line is now open

Arun Jayaram -- JP Morgan -- Analyst

Yes. Quick question. I was just wondering if you could just help us bridge the production forecast for the other segments. You talked about 105,000 in the first quarter for the Gulf -- pardon me, for the Bakken.

I'm assuming that your guidance implies about 30,000 for the Gulf of Mexico? And I'm just wondering if you could help us think about the Utica U.S. -- other onshore as well as Asia for Q1?

John Rielly -- Chief Financial Officer

I guess, the way -- if you're trying to bridge, say, the fourth-quarter number to our first-quarter number, the biggest change is, obviously, asset sales. So that 282,000 barrels a day, if you take 41,000 barrels a day approximately as it relates to the asset sales, you have to take that off. Then, as Greg mentioned, we've got 26,000 barrels a day off on Enchilada versus the 17,000 that we have. So you have to take another 9,000 barrels a day off.

You've picked up the Bakken, right? So that's 5,000 barrels down. Utica will have a decline. So we have Utica declining approximately 3,000 barrels a day in the first quarter from the fourth quarter. As you probably saw it in our capital release, we will be drilling -- or sorry, completing some ducts that we have.

And that won't come in until really the end of the year. You won't see that in the Utica until fourth-quarter production. So with that, you basically bridge the difference between the fourth quarter and first quarter.

Arun Jayaram -- JP Morgan -- Analyst

That's helpful. And John, just a follow-up on the NGL commentary you made on the Bakken. Could you just maybe help us understand that a little bit better? Is that just going to affect 1Q? Or is there any effect as we think about the full year in terms of the Bakken?

John Rielly -- Chief Financial Officer

OK. So first thing I have to say, there's no effect on our bottom line for these two items. So the first one is, our buyer who takes our ethane, can execute and can reject ethane based on whatever pricing that they're getting and what benefits from their standpoint. However, they do have to pay us the economic amount of that ethane that we would have produced.

So again, just from a pure volume standpoint, we just have less ethane volumes flowing through our NGLs in the first quarter. So that's one -- and basically that's going to go away and come right back on. The second one is the increase in NGL pricing. So just think about it as, you've got a set gas-processing fee -- and it only works on some of the contracts that we have, and you probably heard POP contracts or percentage-of-proceed contracts -- so what we get is actual NGL volumes to satisfy that gas-processing fee.

So as NGL prices go up, you just get less volumes, you get the same amount from your gas-processing fee, but you just get less volumes to satisfy it. So as prices have come up from the fourth quarter, that's affecting that number. If prices stay the same or go down, you will get some fluctuations above ground. It shouldn't be big, it's not going to be a big effect.

And, again, as we said, Bakken, the real key is we'll be adding wells a little bit more toward the latter part of the first quarter and then just driving through the year and increasing Bakken quarter on quarter.

Arun Jayaram -- JP Morgan -- Analyst

OK. That's very helpful. Thanks a lot.

Operator

Our next question is from Pavel Molchanov from Raymond James. Your line is now open.

Pavel Molchanov -- Raymond James -- Analyst

Thanks for taking the question, guys. Few weeks ago, the fiscal terms of the Guyana production sharing agreement were published. And I spoke, for those investors who might look at that and say how can a deepwater project have a break-even oil price below $40 a barrel. What are the key attributes of those fiscal terms that are contributing to that low break-even?

John Hess -- Chief Executive Officer

OK. So it's really all the attributes. And you have to not even just the fiscal terms, it's -- so let me just start with Guyana overall. So our Liza find that we have, the geology, the reservoirs are just fantastic.

The permeability is fantastic. The size, obviously, you've seen the scale. So that plays into getting that low break-even. The next thing is, you compare, let's just say the other basins around the world, the depths that you drill to in Guyana are much shallower.

And the other thing is, there's no salt. So from an imaging standpoint that helps. And then there's less casing string. So the exploration wells and the development wells, obviously, just cost less.

I mean, clearly as you would compare, let's say, to like a Gulf of Mexico-type aspect. We're also in the low point in the cycle from offshore. So, again, yards are looking for work, rigs are looking for work. So all the costs that Exxon is getting for our developments are, you're just hitting this, obviously, at the right point in the cycle.

And then it's just a blend of the fiscal terms. So you have a production-sharing contract. So what makes -- just start with any production-sharing contract, it gives you downside protection. That's what it's set up for, to encourage investment from oil companies.

So as oil prices go lower, you get more barrels because you get the cost recover from that standpoint. So, again, as prices go down and giving you that break-even, you get that production-sharing cost impact. And then terms are out there. They're on the government website for people to see and that, along with just the unique attributes of the Guyana's basin, in general, allow you to get this really low break-even cost.

Pavel Molchanov -- Raymond James -- Analyst

OK. Let me ask a quick follow-up about the dividend. One of your well-known shareholders has called for a dividend cut or elimination and the proceeds deployed toward more share buyback. Should I take it as a given you are ruling out that scenario?

John Hess -- Chief Executive Officer

No. I mean what you should take as a feedback is that we talk to all of our shareholders and a number of our shareholders put a high degree of importance on that dividend as a show of confidence in our future and our ability to generate cash. So we talk to all our shareholders. We have ongoing communications with all of our shareholders.

And there are other views about the dividend than that one shareholder you were referring to.

Pavel Molchanov -- Raymond James -- Analyst

Appreciate it.

Operator

Our next question is from John Herrlin with Societe Generale. Your line is now open.

John Herrlin -- Societe Generale -- Analyst

Yes, hi. Just two quick ones on Guyana. When we were out in December, John, you had mentioned or Greg had mentioned that possibly you would buy the FPSO for Liza 2, is that still the case? And then the other question is on Ranger. It took longer to reach TD in a carbonate well.

Obviously, it was a cautious drill, but how much faster do you think the drilling would be for carbonate play?

Greg Hill -- Chief Operating Officer

Let me answer the Ranger question first. Yes, it was a very cautious drill. John, as you know, carbonates can be very tricky. But we didn't discover any of the downsides in the drilling of this well that potentially could've been there.

So I think, certainly, on the next appraisal well of Ranger, we anticipate the drilling time will improve and the cost will be lower, obviously. Regarding the boat on Phase 2, that decision has not been made. But certainly, from a financial standpoint, it's better to purchase these things, ultimately, just so you don't have to pay the uplift on the lease cost, right? So I think we're aligned with the operator, that ultimately, you'd want to purchase these things, but that decision has not been made.

John Herrlin -- Societe Generale -- Analyst

OK. Great. With Guyana, are you opening a data room?

John Hess -- Chief Executive Officer

Yes, the Guyana process is ongoing and I wouldn't want to comment further on that.

John Herrlin -- Societe Generale -- Analyst

Thanks, John.

Operator

Thank you very much. This concludes today's conference. Thank you for your participation. You may all disconnect.

Everyone, have a great day.

Duration: 83 minutes

Call Participants:

Jay Wilson -- Vice President of Investor Relations

John Hess -- Chief Executive Officer

Greg Hill -- Chief Operating Officer

John Rielly -- Chief Financial Officer

Roger Read -- Wells Fargo -- Analyst

Doug Leggate -- Bank of America Merrill Lynch

Brian Singer -- Goldman Sachs -- Analyst

Michael Hall -- Heikkinen Energy Advisors --  Analyst

Ryan Todd -- Deutsche Bank -- Analyst

Paul Cheng -- Barclays -- Analyst

Arun Jayaram -- JP Morgan -- Analyst

Pavel Molchanov -- Raymond James -- Analyst

John Herrlin -- Societe Generale -- Analyst

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