赫斯 (HES) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2016 Hess Corporation conference call. My name is Nicole and I will be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to Jay Wilson, Vice President Investor Relations. Please proceed.

Thank you, Nicole. Good morning, everyone. Thank you for participating in our fourth-quarter earnings 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 on our website.

With me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer.

I will now turn the call over to John Hess.

Thank you, Jay. Welcome to our fourth-quarter conference call. I will review highlights from 2016 and plans for 2017. Greg Hill will then discuss our operating performance, and John Rielly will review our financial results.

First, I would like to share our view of the oil market, particularly in light of the recent OPEC agreement. We are entering a new chapter in oil prices. After two years of a lower-for-longer price environment, global investment in exploration and production has been severely curtailed, nearly in half from approximately $700 billion in 2014 to $380 billion last year.

While 2017 should see modestly higher investment than 2016, we believe this level of spend will not be enough to bring forward the necessary production over the next several years to meet future oil demand growth and offset production declines globally. We see continued strong demand coupled with the anticipated reduced supply resulting from OPEC and non-OPEC supply cuts and natural field declines more than offsetting increased US shale oil production, leading to higher oil prices this year and into 2018.

Our Company is extremely well positioned for this improving price environment. We have a decade or more of visible reserve and production growth, and our continued focus on operational excellence and financial discipline is driving improving returns and lower costs across our portfolio.

Our visible growth trajectory is underpinned by four key areas: the Bakken, where we have a leadership position and will go from two rigs to six rigs over the course of 2017; two offshore developments, North Malay Basin and Stampede, which are expected to contribute significant production and cash flow when they come online in 2017 and 2018, respectively; and the world-class Liza and recent Iara oil discoveries in Guyana, with sanction of the first phase of the Liza development expected midyear and continuing appraisal and development activities underway.

In 2017, we will continue to be disciplined in investing in our growth projects while maintaining a strong balance sheet and liquidity position. On January 12, we announced a 2017 capital and exploratory budget of $2.25 billion.

About 70% of our 2017 budget is allocated to our four major growth areas. With activity increasing in 2017, our focus will be on execution in terms of safety, cost control, project delivery and working with our partners to advance our discoveries in Guyana to development.

Now turning to our 2016 financial results, our adjusted net loss was $1.5 billion, and cash flow from operations before changes in working capital was $840 million. Compared to 2015, our financial results were negatively impacted by lower crude oil and natural gas sales volumes and selling prices, which more than offset the positive impacts of lower operating costs and DD&A expense.

From an operational standpoint, while we reduced activity across our producing portfolio in 2016, our team has much to be proud of. Driving operational efficiencies across our portfolio, delivering reductions in capital expenditures and cash operating costs, progressing our offshore developments, and achieving major success with our focused exploration program.

In 2016, full-year net production was 321,000 barrels of oil equivalent per day, excluding Libya. In 2017, our production is forecast to average between 300,000 and 310,000 barrels of oil equivalent per day, excluding Libya.

It is important to note that fourth-quarter 2017 production is expected to increase in excess of 10% from first-quarter levels, driven by the startup of North Malay Basin in the third quarter, increased activity levels in the Bakken and the restart of drilling at the Valhall Field in Norway. All of which builds momentum and positions the Company for strong production growth in 2018.

At year-end 2016, our proved reserves stood at 1.1 billion barrels of oil equivalent and our reserve life was 9.2 years. We replaced 119% of production in 2016 at an FD&A cost of approximately $13 per barrel of oil equivalent.

Now turning to the Bakken, Hess has one of the highest-quality acreage positions in the play with more future drilling locations in the core than any other operator and an advantaged infrastructure position. Through our application of lean manufacturing techniques, our Bakken team has achieved among the lowest drilling and completion costs and most productive wells in the basin, offering very attractive financial returns.

Bakken production in 2016 averaged 105,000 barrels of oil equivalent per day, reflecting our reduced drilling program. Bakken production in 2017 is forecast to average between 95,000 and 105,000 barrels of oil equivalent per day. With increased activity in the Bakken and the improvement in the MLP market, Hess Infrastructure Partners is preparing for an initial public offering of LP common units in 2017.

Turning to our offshore developments, full-field development of North Malay Basin in the Gulf of Thailand is on track to achieve first production in the third quarter of 2017. The Stampede development in the deepwater Gulf of Mexico is progressing and remains on schedule for first oil in 2018. Together, they are expected to add a combined 35,000 barrels of oil equivalent per day and transition from being sizable cash users to significant long-term cash generators for the Company.

With regard to Guyana, we are excited about the significant resource potential on the 6.6-million-acre Stabroek Block. The Liza-3 well results last October confirmed Liza as one of the industry's largest oil discoveries in the last 10 years, with estimated recoverable resources of more than 1 billion barrels of oil equivalent. We expect to be in a position to sanction the first phase of development in 2017 with production expected in 2020.

This month, the Payara-1 well confirmed a second significant oil discovery with the same high-quality reservoir. Payara and an additional deeper reservoir identified directly below the Liza Field are accretive to the estimated recoverable resources already confirmed at Liza and further demonstrate the prospectivity of the Stabroek Block. The Stabroek Block offers very attractive economics and will be very material for our Company.

The Liza and Payara oil discoveries underpin a large discovered resource on the block that has significant upside in terms of appraisal and future exploration potential. The reservoir quality is world-class with high porosity and permeability. The wells can be drilled in a third to a half of the time and cost of those in the deepwater Gulf of Mexico, and we are entering the development phase at what will likely be the bottom of the offshore cost cycle.

In summary, we are well positioned to deliver visible and sustainable growth and value to our shareholders. We are increasing activity in the Bakken, which will bring growth back into our onshore portfolio and support a potential IPO of the midstream business to unlock additional value.

Offshore, our developments in the Gulf of Thailand and the deepwater Gulf of Mexico are poised to add significant volumes and become long-term cash generators. And in Guyana, the Liza field is one of the industry's largest oil discoveries of the last 10 years, which we and our partners will continue to appraise and progress toward development. Overall, we see 2017 as the start of an exciting new chapter of value-driven growth and increasing production momentum for our Company and our shareholders.

I will now turn the call over to Greg for an operational update.

Thanks, John. I'd like to provide an operational update for 2016 and to review our plans for 2017. Clearly, the past year was challenging in terms of oil prices, and we responded by reducing our capital spend and operating costs.

Last year was also marked by strong execution on many fronts, including the continued advancement of our North Malay Basin and Stampede developments and exceptional exploration results in Guyana, firmly establishing a new world-class oil province.

With regard to production, in 2016, we averaged 321,000 barrels of oil equivalent per day, excluding Libya. In the fourth quarter, production averaged 307,000 barrels of oil equivalent per day, excluding Libya, which was above our guidance of 305,000 barrels of oil equivalent per day.

During the quarter, production from Libya resumed and on a net basis, averaged 4,000 barrels per day in the fourth quarter. Production from Libya remains highly uncertain. Therefore, we will continue to exclude it from our guidance.

As John mentioned, in 2016, we achieved a reserve replacement ratio of 119% and an FD&A cost of $13 per barrel of oil equivalent. Net proved reserve additions totaled 143 million barrels of oil equivalent. About half of the additions were in the Bakken, reflecting higher EURs associated with our shift to 50-stage completions and lower costs. Other areas with additions include North Malay Basin, South Arne, and the Utica.

In 2017, we forecast Company-wide production to average between 300,000 and 310,000 barrels of oil equivalent per day. Our production has been decreasing over the last several quarters as a result of reducing our capital expenditures to manage in the lower price environment. Our production will continue to decline in the first half of 2017 as a result of this reduced spend and a high level of planned maintenance at four of our offshore assets in the second quarter.

We forecast production to average between 290,000 and 300,000 barrels of oil equivalent per day in the first quarter and between 270,000 and 280,000 barrels per day in the second quarter. Production is forecast to increase in the third quarter with the startup of North Malay Basin to between 305,000 and 315,000 barrels of oil equivalent per day.

Production will continue to grow in the fourth quarter as Bakken production increases as a result of rig ramp-up and the first new Valhall well comes online. Fourth-quarter production is forecast to average between 330,000 and 340,000 barrels of oil equivalent per day, resulting in production growth in excess of 10% or some 40,000 barrels per day from the first to the fourth quarter of 2017.

Turning to operations, the Bakken continues to deliver outstanding results. We continued to improve our drilling and completion performance, with fourth-quarter D&C costs dropping 10% versus the year-ago quarter to $4.6 million.

We now have enough production history to conclude that we will get an average 13% uplift in EUR per well from our 50-stage completions compared to our previous estimate of 7%. As a result, we have increased our estimate of ultimate recovery from our Bakken acreage to 1.7 billion barrels of oil equivalent from our previous estimate of 1.6 billion barrels of oil equivalent.

In the fourth quarter, initial production rates for wells that reached IP 30 during the quarter averaged a record 1,091 barrels of oil per day versus 843 barrels of oil per day in the third quarter. This result reflects all wells during the quarter being 50-stage completions and in the core of the core of our acreage.

Going forward, we will shift our guidance to IP 90 rates, which we feel are more reflective of a well's actual performance. In 2017, we forecast our IP 90s to average between 700 and 750 barrels of oil per day compared to 620 barrels of oil per day in 2016.

Net production from the Bakken averaged 105,000 barrels of oil equivalent per day in 2016, which was at the top end of our beginning-of-the-year guidance range of 95,000 to 105,000 barrels of oil equivalent per day. In the fourth quarter, net production averaged 95,000 barrels of oil equivalent per day, which was below guidance due to extreme winter weather, which resulted in road closures and an unusually high number of shut-in facilities and wells. The net negative impact of weather in the fourth quarter on the Bakken was about 7,000 barrels of oil per day.

With the recovery in oil prices to the mid-$50s, we plan to increase our rig count from the 2 rigs we currently have operating to 6 regs by the end of this year and expect our rig count to average approximately 3.5 for the year. In 2017, we plan to drill approximately 80 wells and bring approximately 75 new wells online over the year.

We will continue to focus our drilling in the core of our Bakken acreage where our sliding sleeve completions, tight spacing, and higher stage counts deliver optimal value. Of the 75 wells we plan to bring online this year, approximately 50 wells will be our new standard 50-stage design, and we expect the B&C costs for these wells to be in line with the $4.8 million that we averaged in 2016.

We will also be conducting two new completion design pilots this year in our drive to continually optimize the value of our industry-leading acreage position. The first pilot will be increasing the stage count to 60 from the standard 50-stage design. We plan to test this in 10 wells to ensure the reliability of the system and are forecasting well costs in these 10 wells to range between $5 million and $5.5 million.

The second pilot will involve higher proppant loading. The 60-stage sliding sleeve may be approaching the technical limit of mechanical design. Therefore, we now want to test the technical limit on proppant loading in a sliding sleeve well.

We plan to increase proppant loading in 15 50-stage wells and forecast these wells to cost in the range of $5.5 million to $6 million. For both of these trials, reservoir simulation indicates a potential IP 180 uplift of 10% to 15%. If successful, our future development plans and production outlook for the Bakken will be modified accordingly in 2018.

The extreme winter weather conditions have persisted throughout the month of January. And as a result, we forecast production in the first quarter of 2017 to average between 90,000 and 95,000 barrels of oil equivalent per day.

For the full year 2017, we forecast our Bakken production to average between 95,000 and 105,000 barrels of oil equivalent per day. With the building rig count, we expect our Bakken production to average between 105,000 and 110,000 barrels of oil equivalent per day during the fourth quarter of 2017, which would represent a growth rate of approximately 15% from the first quarter to the fourth quarter of 2017.

Moving to the Utica, in 2016, net production averaged 29,000 barrels of oil equivalent per day compared to 24,000 barrels of oil equivalent per day in 2015. In the fourth quarter, net production averaged 26,000 barrels of oil equivalent per day. As a result of continued wide basin differentials, we intend to maintain our drilling pause in the Utica.

In 2017, production is forecast to average between 15,000 and 20,000 barrels of oil equivalent per day. However, given the high quality of our Utica acreage position, our high average net revenue interest of 95%, as well as the first-quartile well performance that we delivered in 2016, the asset will be an excellent resource to develop as natural gas and NGL price realizations improve.

Now turning to the offshore, in the deepwater Gulf of Mexico, net production averaged 61,000 barrels of oil equivalent per day in both the fourth quarter and for the full year 2016. We forecast Gulf of Mexico production to average approximately 65,000 barrels of oil equivalent per day in 2017 and to reach approximately 75,000 barrels of oil equivalent per day in the fourth quarter of 2017.

This production growth reflects the addition of a new well and the restart of an existing well following a workover at the Tubular Bells Field in the first quarter, a restart of a well at the Conger Field, also following a workover, and a planned new well at the Penn State Field, which will come online in the second half of this year.

In Norway, at the Aker BP-operated Valhall Field, in which Hess has a 64% interest, production averaged 28,000 barrels of oil equivalent per day in 2016 and 32,000 barrels of oil equivalent per day in the fourth quarter. The transition from BP to Aker BP operatorship was completed in the fourth quarter, and we are looking forward to working together with the new operator to maximize the value of the Valhall asset.

Drilling from the existing platform rig is planned to resume in March. In 2017, net production is expected to average between 25,000 and 30,000 barrels of oil equivalent per day.

At the South Arne Field in Denmark, which Hess operates with a 61.5% interest, net production averaged 13,000 barrels of oil equivalent per day in 2016 and 14,000 barrels of oil equivalent per day in the fourth quarter. The field is expected to average approximately 12,000 barrels of oil equivalent per day in 2017.

In the fourth quarter, the Danish government awarded an extension of the South Arne license through to 2047. This secures the long-term future of this asset and provides for future phases of development.

In Equatorial Guinea, where Hess is an operator with an 85% interest, net production averaged 32,000 barrels of oil equivalent per day in 2016, reflecting the drilling pause in place since mid-2015. Net production in 2017 is forecast to average approximately 25,000 barrels of oil equivalent per day.

Interpretation of the latest 4D survey has been completed and has identified multiple new targets. However, the production outlook for 2017 reflects continuation of the drilling pause over the year.

At the Malaysia-Thailand Joint Development Area in the Gulf of Thailand, in which Hess has a 50% interest, net production averaged 35,000 barrels of oil equivalent per day in the fourth quarter. Net production averaged 34,000 barrels of oil equivalent per day in 2016 and is expected to average approximately 35,000 barrels of oil equivalent per day in 2017. No further drilling activity will be required to meet contracted volumes for the year as a result of the booster compression project that was completed in the third quarter of 2016.

Moving now to our development projects, at North Malay Basin in the Gulf of Thailand, in which Hess holds a 50% interest and is operator, three remote wellhead platforms were hooked up and commissioned in the fourth quarter. The drilling campaign is on schedule, with two wells being drilled in the fourth quarter, bringing the total number of wells drilled so far to 13.

All wells have either met or exceeded pre-drill expectations. The last heavy lift for the central processing platform topsides is completed and sail away is scheduled for the first quarter of 2017.

Net production through the early production system averaged approximately 26 million cubic feet per day over 2016. Once full-field development is completed in third quarter of this year, we forecast net production to increase to approximately 165 million cubic feet per day and to remain at this rate for many years, becoming a significant cash generator for the Company.

At the Stampede development in the Gulf of Mexico, in which Hess has a 25% working interest and is operator, we successfully completed installation of subsea equipment at both drill centers and completed all topsides heavy lift onto the hull. Looking forward, in 2017, we will install the TOP and topsides on location, complete the subsea installation, and continue our drilling program. First oil remains on target for 2018.

Turning to Guyana, exploration and appraisal drilling activity continues at the 6.6-million-acre Stabroek Block, in which Hess holds a 30% interest. As announced earlier this month, the Payara-1 well, located approximately 10 miles northwest of the Liza discovery, was drilled by the operator Esso Exploration and Production Guyana Ltd. to a depth of 18,080 feet and encountered more than 95 feet of high-quality multi-Darcy permeability oil-bearing sandstone reservoirs.

Two sidetracks were subsequently drilled to take core and further evaluate the reservoir. Both sidetracks found high-quality oil-bearing sands. The original well and the two sidetracks were drilled, logged, and cored in 56 days. A production test is now planned to further evaluate the reservoir.

Appraisal drilling is planned for later this year to help define the full resource potential of the Payara discovery. After completing the well test on Payara-1, the rig will move to drill the SNOOK exploration prospect, which is located approximately 6 miles south of the Liza-1 discovery well. The next well in queue is a Liza-4 appraisal well, which will test the eastern part of the Liza Field. This will be followed by a Payara-2 appraisal well.

Earlier this month, we announced that the Liza-3 appraisal well, which reached target depth in the fourth quarter, identified an additional high-quality, deeper reservoir directly below the Liza Field, which is estimated to contain recoverable reserves between 100 million and 150 million barrels of oil equivalent.

This additional resource is expected to be developed in conjunction with the Liza discovery. The operator plans to continue to appraise the Liza and Payara discoveries, while in parallel continuing to evaluate the wider resource potential of the Stabroek Block for additional exploration, drilling, and seismic analysis over 2017.

In closing, in 2016, we once again demonstrated strong execution performance and took proactive steps to manage through the weak oil price environment by significantly reducing our capital spend and operating costs while continuing to progress our future growth options.

I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2016 to the third quarter of 2016. The Corporation incurred a net loss of $4.892 billion in the fourth quarter of 2016 compared with a net loss of $339 million in the third quarter.

The largest driver for the loss in the fourth quarter was the non-cash accounting charge of $3.75 billion on net deferred tax assets in the US, Denmark, and Malaysia. This non-cash adjustment is required under accounting standards following a three-year cumulative loss. The deferred tax charge has no cash flow or economic impact. The Company's underlying tax position remains unchanged.

Beginning in 2017, our financial results will not recognize a deferred tax benefit or expense in these three countries until the deferred tax assets are reestablished. Our guidance for 2017 includes the anticipated impact of this charge, which will result in a lower effective tax rate going forward.

Fourth-quarter results also included an after-tax charge of $693 million to fully impair the carrying value of our Equus natural gas project offshore the North West Shelf of Australia as a result of our decision to defer further development so we can allocate capital to other projects that generate higher returns, including the Bakken and Guyana. Other after-tax charges totaling $145 million were recognized for exit costs for an offshore drilling rig, loss on debt extinguishment, impairment of older specification railcars, severance, and surplus materials and supplies inventory. Excluding items affecting the comparability of earnings between periods, our adjusted net loss was $305 million in the fourth quarter of 2016 compared with an adjusted net loss of $340 million in the third quarter.

Turning to E&P, on an adjusted basis, E&P incurred a net loss of $257 million in the fourth quarter of 2016 compared to a net loss of $285 million in the third quarter of 2016. The changes in the after-tax components of adjusted results for E&P between the fourth quarter and the third quarter of 2016 were as follows: higher realized selling prices improved results by $37 million; lower sales volumes reduced results by $23 million; lower DD&A expense improved results by $29 million; all other items reduced results by $15 million for an overall decrease in fourth-quarter net loss of $28 million.

In the fourth quarter, our E&P operations were overlifted compared with production by approximately 300,000 barrels, which did not have a material impact on fourth-quarter results. The E&P effective income tax rate, excluding items affecting comparability, was a benefit of 43% in the fourth quarter of 2016 compared with a benefit of 41% in the third quarter.

Turning to midstream, the Bakken midstream segment had net income of $3 million in the fourth quarter compared to $13 million in the third quarter. Higher revenues in the fourth quarter reflect a recognition of deferred minimum volume deficiency payments that were partly offset by lower throughput volumes caused by severe weather in North Dakota. Fourth-quarter results also include a pre-tax charge of $67 million or $21 million after taxes and the 50% noncontrolling interest to impair older specification railcars.

EBITDA for the Bakken midstream before the noncontrolling interest amounted to $99 million in the fourth quarter of 2016 compared to $73 million in the third quarter. Starting January 1, 2017, our midstream segment now includes the Company's interest in the Permian gas plant in West Texas and related CO2 assets and our North Dakota water handling assets, which principally consists of gathering infrastructure. These assets are wholly owned by the Company and are not included in our Hess Infrastructure Partners joint venture.

Turning to corporate, after-tax corporate and interest expenses, excluding items affecting comparability, were $72 million in the fourth quarter of 2016 compared to $68 million in the third quarter. Turning to cash flow for the fourth quarter, net cash provided by operating activities before changes in working capital was $128 million. The net increase in cash resulting from changes in working capital was $198 million.

Additions to property, plant, and equipment were $487 million. Net repayments of debt were $592 million. Common and preferred stock dividends paid were $90 million. All other items resulted in an increase in cash of $46 million, resulting in a net decrease in cash and cash equivalents in the fourth quarter of $797 million.

Fourth-quarter cash flow from operations before changes in working capital of $128 million reflects a reduction of approximately $200 million associated with the charges for rig exit costs, severance and surplus inventory, and higher well workover costs in the quarter.

Turning to cash and liquidity, excluding the Bakken midstream, we ended 2016 with cash and cash equivalents of $2.7 billion, total liquidity of $7.3 billion, including available committed credit facilities, and total debt of $6.073 billion.

Turning to guidance, first with E&P, we project cash costs for E&P operations to be in the range of $16 to $17 per barrel of oil equivalent in the first quarter of 2017 and $15 to $16 per barrel for the full year of 2017 as compared to 2016 cash costs of $15.87 per barrel. Full-year cash costs per barrel are lower than the first quarter, reflecting the startup of the North Malay Basin project in the third quarter and increasing production from the Bakken in the second half of 2017.

DD&A per barrel of oil equivalent for the first quarter of 2017 is forecast to be $25.50 to $26.50 and $24 to $25 for the full year 2017, down from 2016 DD&A of $26.57 per barrel. This results in projected total E&P unit operating costs of $41.50 to $43.50 per barrel in the first quarter of 2017 and $39 to $41 per barrel for the full year of 2017, down from 2016 E&P unit operating costs of $42.44 per barrel.

Exploration expenses, excluding dry holes, are expected to be in the range of $65 million to $75 million in the first quarter of 2017 and $250 million to $270 million for the full year of 2017, similar to 2016 exploration expenses of $261 million, excluding dry hole expense. The midstream tariff, which now includes tariffs associated with our Permian gas plant and related CO2 assets and additional North Dakota water handling assets, is expected to be in the range of $115 million to $125 million for the first quarter of 2017 and $520 million to $550 million for the full year of 2017.

The E&P effective tax rate, excluding Libya, is expected to be a benefit in the range of 11% to 15% for the first quarter and 17% to 21% for the full year of 2017 versus a benefit of 42% in 2016. As mentioned, we will not be recognizing deferred taxes in the US, Denmark, and Malaysia, which causes the lower effective tax rate. This lower effective tax rate will have no effect on cash flow.

Turning to midstream, in 2017, we anticipate net income attributable to Hess from the midstream segment to be in the range of $15 million to $25 million in the first quarter and in the range of $70 million to $90 million for the full year.

Turning to corporate, in 2017, our corporate and interest expenses will not receive deferred tax benefits as discussed and therefore our guidance reflects pre-tax numbers due to the absence of a tax provision. In 2017, we estimate corporate expenses to be in the range of $35 million to $40 million in the first quarter and in the range of $140 million to $150 million for the full year. We estimate interest expense to be in the range of $75 million to $80 million in the first quarter of 2017 and in the range of $295 million to $305 million for the full year of 2017.

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

(Operator Instructions) Arun Jayaram, JPMorgan.

First question just relates to better understanding the CapEx and the completion activity in the Bakken and just trying to think about 2018. I know you spent $429 million in the Bakken and did 100 gross wells. And I know you had some DUCs that helped you a little bit.

In 2017, you are guiding to $700 million in CapEx, yet the completion count is going down by 25. So just wondering if you can maybe help me reconcile that, and could reflect some higher infrastructure spending. But just thinking about the completion versus the CapEx in 2017 and thoughts around completion activities as we think about 2018.

Yes, so let me just kind of break down the -- there's a total of about $660 million being spent in the Bakken next year. About $50 million of that is for non-operated participation in some wells that we are expecting this year. So that leaves about $610 million for I'll call it Bakken-operated.

And if you look at that $610 million and break it down, the bulk is drilling and completion. So about $465 million is for drilling and completions and all the related facilities associated with that. There's about $95 million also in that category, but that's money spent in 2017 for future years. So that's the DUCs that get carried into 2018 and then also the pads that we will construct in 2017 for early 2018.

And then there's about $50 million left for major maintenance and some field upgrades, more statistical, that we put in the budget. Hopefully that's helpful.

That's very helpful. And just my follow-up question is you could just maybe better help us understand some of the first-half 2017 maintenance-related shut-ins that you forecast. I think you highlighted four projects that will experience some downtime. If you gave us some more color on that, be much appreciated.

Yes, you bet. Almost all that downtime is in the second quarter. And about 13,000 barrels a day down first quarter versus second quarter -- or second quarter versus first quarter associated with those major shutdowns offshore. About 5,000 barrels of that is at Llano in the Gulf, about 6,000 is at Equatorial Guinea, and a couple thousand barrels a day at Conger, also in the Gulf of Mexico. So that's the majority of it.

Okay, thanks a lot. Appreciate it.

Doug Leggate, Bank of America.

Greg, the update in the Gulf of Mexico -- I'm just wondering if we could dig a little bit into some of the moving parts this year. You mentioned Penn State. But what is the current status and expectations for Tubular Bells trajectory and full year?

It's too early to say on Tubular Bells. And that's because we are basically increasing the chokes on not only the well that was worked over and that came on in December 31, but also the new well that came on in late December as well.

So we're just in the early stages of ramping Tubular Bells back up. I want to get it stable. We also are getting water injection stable. So I really want to see the well results from that before I'd be specific on that. So potentially in midyear we could provide an update once we get stable.

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

We are not going to give that yet. And again, Doug, I'm not trying to be evasive. I just really want to see these wells ramp-up and see what they are at. So I want to be certain about that.

Okay. My second one, hopefully a quick one, is -- and I've got one more on Guyana, if I may. Just assuming oil prices come in, trajectory through the year gets a little higher, what's the first call on cash for Hess in 2017?

So if oil prices come in higher, you know what we are doing with the rig ramp in Bakken. We've always said that that first call on cash will be the Bakken. So we will continue to look, then: do you accelerate how we are bringing the rigs in? So that's what we would be thinking about at this point. So the first call would go to the Bakken.

Okay, thanks. And my final one -- and I'm going to try this. I'm not sure I'm going to get a lot of mileage out of you guys on Guyana, but I'll give it a go. So on the last call, John Hess, you suggested we were now at the upper end of Liza. I realize that the X on guidance is above 1 billion. But upper end would be 1.4 billion plus the 100 million to 150 million, I guess, gets you to 1.5 billion.

But my question is Greg suggested that you are going to drill the eastern flank of the field. So can you tell us what proportion of the Liza structure is, quote-unquote, de-risked to get to the 1.5 billion to give us some idea as to what proportion of the overall field capacity could ultimately look like? And I'll leave it there.

A very fair question, Doug. As we pointed out after the Liza-3 well, we confirmed and our partners did as well that we were in excess of 1 billion barrels of oil. I think it's very important to note when asked.

Liza Deep will be accretive to the number. Payara will be accretive to the number. SNOOK and potentially Liza-4 will be accretive to the number. So to give specificity at this point in time would just be too early. We got to finish the appraisal that we are underway, but there is upside to the numbers that we gave guidance on last quarter.

John, just a quick follow one. Are we going to get a second rig done here, given the potential move to FID?

That's under discussion with the operator, Doug. Obviously, after we take out FID, we will want to start drilling development wells at some point.

All right. Thanks, everybody.

Brian Singer, Goldman Sachs.

Can you talk to your cost inflation assumptions that are built into your capital budget guidance and what, if anything, you are seeing now? I thought I heard you mention that you are going to be able to keep Bakken costs, Bakken well costs, flat in 2017. I may not have heard that right. But can you talk to what risks that you could see as the year progresses and mitigation on your [assets]?

I think in 2017, we anticipate seeing some pressure in the onshore on commodity-based chemicals and potentially sand as well. But we are pretty confident -- you are exactly right; we're pretty confident that we can hold our well costs flat in the Bakken on the 50-stage completions in the core. That's kind of that $4.8 million average number that we had in 2016.

The way we're going to offset increases in sand, commodity-based chemicals, those kind of things, is basically by continuing to apply our lean manufacturing capability, which we have consistently, as you know, been able to pull $100,000 to $200,000 a quarter out of the well costs. And there's still a bit more room left for that improvement as well.

Got it, thanks. And then separately, as your completions in the Bakken are evolving, can you talk to how significant you see further technological improvement in the Bakken or whether you think we are in the later innings? And does the success in improving EURs solidify the Bakken as your key shale horse for the Company or, rather, give you more confidence to look at other areas?

Well, let me talk about the completions in the Bakken first. As we said in our opening remarks, we are doing a couple of pilots this year. And so in the core of the core, which is where we have been focused, where we have that very tight nine and eight spacing, we have demonstrated that the best way to optimize value in that core of the core is by using sliding sleeve technology and then steadily increasing the stage counts.

Which effectively kind of increases the per-well proppant loading, but it gives you a nice uniform frac all away down the wellbore. And as you know, we have worked with our supplier to continue to engineer more and more sliding sleeves in a 10,000-foot lateral.

Now, we believe that we could be approaching a technical limit on the number of sleeves, somewhere between 60 and 70. That's just given the tight tolerances between all the ball sizes. So, given that we may be approaching that maximum stage count with a sliding sleeve system, we now want to push the technical limits on the per-stage proppant loading.

So, given our tight nine and eight spacing, which is only about 500 feet between the wells, we're going to pilot those higher loadings to find out where the optimum point might be to further increase value while not causing significant well-to-well interference. What we know is with the proppant loading that we have, we haven't seen any significant well-to-well interference.

So that says you can probably get more proppant in the well and still be okay. So we are going to test the limits of that this year and see exactly how much that is.

And so certainly on the sliding sleeve system, in terms of your question on where we are in technology, I think again, we are -- as we approach 70 stages and kind of that number, I think we are starting to reach the technical limit there. The next thing will be proppant loading for us in the core of the core. But again, that sliding sleeve system, because it's so inexpensive and so efficient to install, it is the highest optimum completion technique in the core of the core.

As you move outside the core, which we will begin testing that in later years, 2018-2019, data seems to indicate that maybe slick water completions or even higher proppant loadings with plug and perf maybe the answer out there. And that's purely because there's a lot less natural fracturing when you get out of the core of the core. So you are going to need more sand and more energy in the reservoir to connect all those fractures up. So that's where I see it going.

And Brian, to your question about our position in the Bakken, how we feel about it, and potentially expanding our shale footprint in the US, in terms of the Bakken, obviously the improvements Greg and his team have made in lean manufacturing, improving productivity, advancing the application of technology, obviously everything governed by lean, we are very pleased with the investment opportunity we have there, the increasing ultimate resource count that we have that reflects that, the increasing IPs.

In terms of expanding our shale footprint, we are always looking to optimize the value of our portfolio in the normal course of business. However, given our robust portfolio of captured growth opportunities with excellent returns, starting with the Bakken, but also the low-risk, high-return infill opportunities that we have in our offshore hubs and now Guyana, outright acquisitions are low on our priority list.

Great, thank you very much.

Ed Westlake, Credit Suisse.

I'm sure we are not going to be able to necessarily get all the results. But as you move toward F&D costs on Liza, are you able to share like a total development cost for the field?

No. We will share that when we take FID. So we will give -- during sanction, you will get a lot more color on cost and volume and production rates and all that. That will most likely be around midyear is when we take FID on Liza Phase 1.

And could we get recovery per well, or that's all going to be at the same time, just as we try and model ahead of the announcement?

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

Okay. And then on Payara, obviously a narrower net pay. That does perhaps suggest a smaller recovery and perhaps more expensive development. Anything in that well to suggest that's the wrong approach, e.g., like pressure regime? Did you test the deeper zones there as well? Maybe some color on how Payara stacks up against Liza on a per-unit basis at this early stage?

You bet, yes. It's early days. Let me be clear upfront. Payara is separate and distinct from Liza. So it's 10 miles away. Now, having said that, the reservoir quality was outstanding, multi-Darcy permeability, same kind of porosity that we saw in Liza.

So we are very pleased with the initial results on Payara. But we're going to have to do further appraisal to determine the ultimate size of the Payara discovery, the aerial extent.

And then, maybe switching gears, you signaled acceleration of production growth into 2018. I appreciate there's a lot of variables. But I don't know if at this point you can share a range. Particularly, obviously, the Bakken will move up. But if oil does recover, there's room to perhaps even increase recoveries at Valhall, [Saffon, wins you get back] at Utica, all of these decisions. Just to give us a sense as to what the path into 2018 looks like.

Yes. So I think the only thing we can say with certainty at this point is the Bakken will -- we are investing a lot in 2017 in the Bakken. You will begin to really see production increase in 2018 in the Bakken. Obviously, the second thing, the second major catalyst in 2018, is Stampede. Beyond that, we really can't be specific on an activity set because, as you said, it's going to depend upon oil prices.

I think the other thing that will happen in 2018 is you will have a full year of North Malay Basin because, of course, you are only getting a partial year this year. So there's a lot of production catalyst upsides in 2018. And you begin to see that in the back half of this year.

Our low point, as we said, is the second quarter. But then in the third and the fourth quarter, you really start to ramp. And as I said in my opening remarks, if you look at the first quarter versus the last quarter, the delta on production, if you just take the midpoint of the range, is about 40,000 barrels a day. So we really start to surge in the last half of the year.

Thanks very much.

Guy Baber, Simmons.

Thanks for taking my question. I wanted to ask about your reserve report, which I thought was pretty impressive. But reserves and F&D obviously can be lumpy. But the $13 per barrel F&D you highlighted was a pretty solid result.

So the question is, do you think that is the type of F&D cost that is representative for your Company through cycle or were there some reserve lumpiness that may have contributed to that? And then more broadly, just wanted to get thoughts about how you are thinking of the evolution of your F&D for the total Company over the next few years on what you think is a sustainable level.

Sure. Like you said, this will be qualitative because the reserve adds in F&D can be lumpy. For the most part, let me just tell you what drove our reserve adds and the very good FD&A that we reported.

So half of it, as Greg mentioned earlier, is really driven in the Bakken. And it's moving up to those 50-stage fracs, so getting higher EURs in there. And over time, as we continue to move up to potentially 60 stages and things like that, the F&D in the Bakken is going to be increasingly accretive, if you want to say, to our past F&D numbers. So that investment will be investing in low-cost reserves. So that's one.

Let me go longer term. So we don't have the numbers yet, right, as Greg just mentioned, and we get to FID in Guyana. But we clearly see, for all the reasons that John Hess mentioned and Greg mentioned in the opening scripts, that the positive attributes that you see in Guyana -- the low well costs, the recoverabilities, the high-quality reservoirs that we see -- that F&D is definitely going to be accretive, again, post our past F&D costs.

So our continued investment in Guyana -- now, that's going to be lumpy when you get the reserves in. But that's going to be very positive to our F&D reporting going forward.

Then within the year itself, that you would see, North Malay Basin we picked up some additional reserves. But that's just increased drilling and as we spend money there. The only one that you could see that was kind of, if you want to call it, lumpy or not, tied to CapEx as much was South Arne.

We did have a license extension in South Arne. So that was extended out to 2047, and we picked up about 20 million barrels there in South Arne. The rest of it was just from our normal portfolio adds and the positive things that we are doing in E&P.

That's very helpful. And then my follow-up is I just want to better understand the flexibility embedded in your plans to ramp from two to six rigs in the Bakken. So can you talk about the variables that might have you ramping up faster than that or slower than what you've indicated?

Are there price-related trigger points you can share with us or any other issues you are monitoring around people, equipment? If you could just help us with a framework for how you are thinking about managing that pace I think would be helpful.

Yes. So I think for the first half of the year, we will be adding a rig a quarter. And then for the back half of the year, the rigs will probably come in the fourth quarter. And that just has to do with the scheduling of the wells, getting the pads ready, all that sort of thing.

Now, there is potential to accelerate those rigs. Maybe another rig comes in the third quarter rather than two in the fourth quarter. We are looking at all that. But for us, the limiting factor for us is we want to bring these wells on safely.

And the cadence for us seems to be that we can bring a rig on about one a quarter and confidently say that we can do that safely and efficiently. So those are our two drivers, safety and efficiency, in terms of how fast we can ramp those rigs.

Thank you.

Doug Terreson, Evercore ISI.

First, let's hope that John's oil price or outlook ends up proving correct. Because I think we will all be better off in that scenario.

You and me both, Doug.

So just to clarify, first of all, on the Bakken comments, was the point that despite all the commentary that's in the market about personnel, equipment availability, etc., you believe that your drilling time and costs per well are going to be pretty close to flat year over year in 2017, that is, as long as you are drilling in the core? Was that pretty much the message on that?

Yes, it was, Doug. And as we've spoken about before, during the downturn, we tried to preserve a lot of capability in the Bakken, particularly on the contracting side, so that we could enable a smoother transition as you ramp back up.

So we are reasonably confident that in 2017, we can manage that very efficiently, which is why we set our 50-stage fracs in the core. We believe we can hold the costs at that $4.8 million number that we achieved in 2016.

Okay, perfect. And then strategically, in United States and also overseas in the E&P business, when you consider reversion to the mean that we've seen on returns for the big oils and declining dispersion of returns in E&Ps, it seems like competitive conditions are pretty intense out there. And then we've also had a fairly staggering rise in energy private equity funding over the past couple of years, which doesn't help that much, either.

So while you guys were early in refocusing the Company on advantaged areas, you've done a really good job there, my question is that when you think about the future, what are the strategic imperatives for companies like Hess, such that you can continue to navigate this competitive condition successfully in the future? What would you have to do to ensure that shareholders were rewarded, given this change of condition? Or do you think that the threat is not so significant that it requires a response?

No, I think you're absolutely right. It's a competitive world out there for oil resources. And obviously, the two years of a lower-for-longer price environment has challenged everyone.

Having said that, we think our Company is extremely well positioned. And what's going to guide us, Doug, is value, allocating capital to the highest returns. And we continue to look at shale opportunities in the United States. You are right to point out that that's a very crowded market and a big question mark on returns going forward because of some of the prices being paid.

Where we are actually seeing better opportunities to invest our capital is in the offshore. That is much less competitive. And we are getting very, very attractive opportunities that will fit our cash flow profile, but also give us opportunities to make significant value for our shareholders going forward.

So obviously led by Guyana, but the opportunities we have in the Guyana Basin, I think, has legs. There's some other offshore opportunities we see there. So we're going to be driven by value. And in the long run, we believe that strategy is the one that will reward our shareholders the most.

Okay. Good answer, John. Thanks a lot.

Paul Cheng, Barclays.

The first one is for John Rielly. John, you mentioned that you are not going to have any -- recognize any deferred tax in US, Denmark, and Norway. Is that purely just a function of price? And at what point that you -- those area that if the price is high enough and you start making money, should we assume that you start recognizing the deferred tax benefit in the cash flow, or that is going to be a while?

I just wanted to clarify. So it's US, Denmark, and Malaysia is where the -- those are the three areas. And so as a result -- again, this is just a bookkeeping requirement that is in the accounting rules because of this three-year cumulative loss that we have or any company would have; you'd have to take down your net deferred tax assets. When we try to or have losses going forward, we can't book deferred tax benefits in those three countries until we reestablish the deferred tax assets.

So your question is, when is that going to happen? And that is not exactly also in the rules. So it's going to be a facts and circumstances analysis at a time. So first of all, it will be emerging and starting to show profits. But then you have to see -- just like your point, what are market conditions at the time, and any other relevant evidence at that point.

So usually putting a deferred tax asset back on your books is going to require a little bit more positive evidence, including now that you are out of this three-year cumulative loss position. So again, I just want to make sure everybody does understand there is no effect on cash flow. There is no economic impact to this at all. So -- from this charge or the lower effective tax rate going forward.

The second question is for Greg. Greg, when I'm looking back, when North Malay first -- their early production system started, I think the expectation is that you will run that pretty steady at 40 million cubic feet per day until that the full development done, and then you'd would ramp to 165 million. Obviously, last year that you had run much below 40 million cubic feet.

So the lower production -- is it -- what really is causing it? Is it an equipment issue? Is a reservoir issue or just a contract issue, demand issue? Can you just -- in other words, what confidence that we have, once that full production that you [already] did will be able to sustain at 165 million cubic feet?

The early production system -- the reason that production is down slightly this year is because of a well. So we lost a well. And that early production system is going to go -- remember, that goes away. So it doesn't make any sense to re-drill a well for a very short lifespan.

So I have all the confidence in the world that the 165 million cubic feet is a good number. We've got a great well stock. We've drilled 13 wells already. All of those wells have come in at or better than at predrill expectations. So the wells are healthy. We've got a great well stock. We've got a large number of wells in North Malay Basin, or will have. So I have a lot of confidence in the 165 number.

Greg, the 165 million cubic feet -- that's based on how many wells producing at the same time? And what is the average well production?

I can give you more color on that as we get closer to actually bringing it on, Paul. Ask me that in midyear and I can give you some more color.

Okay. For the Stampede, we have been talking for some time that is 2018 start up. I get that we are now getting closer. Is there any, maybe a little bit more granularity in terms of is it going to be first quarter, second quarter, midyear, second half, any kind of additional data?

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

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

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

So we should not expect the Waha production will be up until fourth quarter?

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

I see. All right, thank you.

Paul Sankey, Wolfe Research.

Just a high level question, John. You started out with a bull case for oil. Greg, you talked about more efficiency. I was wondering what was the balance between the decision to re-accelerate the Bakken in terms of an expectation of higher oil prices, or whether it's all about the fact that you can do more for less.

It's actually both. At the end of the day, we've said, as prices approach $60 and really have a firm 5 in the price and we feel pretty good about that, we would be comfortable starting to accelerate our Bakken program.

And obviously, with the great work that Greg and his team have done about lowering costs, increasing stage counts, increasing productivity, when you add it all up, it's about allocating capital at the highest returns. And we saw some very good returns there.

Yes, I think that's -- you've lead into the second part, John, which was I think previously you had talked about free cash flow generation at 60 in the Bakken, if I'm not wrong, and that being the number at which you would accelerate. Are you effectively saying that that number is now lower?

Well, actually, so you know, our plans, our capital -- fair questions. Our capital plans for the Bakken anticipate that asset generating free cash and growing as well. And obviously, that free cash is going to be a function of what the oil price is.

But our plans are not just to invest all the cash to grow production. It's also to make sure that we start getting some cash back from that asset. And that's an integral part of how we thought about allocating the capital.

Okay, thank you. And then I want to add to the pile of Guyana questions. Just wondering -- you said Payara, very similar to Liza. But one thing that's notable is that the net pay seems a lot less. Is there anything to say about that?

I think the key thing there is we just have more appraisal to do. But we think it will be a significant resource in and of itself. How big it is -- more appraisal is necessary.

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

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

Thank you, John.

Ryan Todd, Deutsche Bank.

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

Sure. And again, the key, as we've been talking about, we have been spending this capital on these development projects, North Malay Basin and Stampede. And we are getting, obviously, closer to getting them both online and generating free cash.

So if you were looking from like a general guidance of where we are this year, if you were excluding basically North Malay Basin and Stampede's capital, our operating cash flow would cover CapEx and dividends in 2017 at the current strip prices that we have.

And then going forward, it's like John just said. Obviously, prices are going to play an important role in this. But we're trying to balance our investment in growth and this generation in free cash flow.

And we've always said 2018 will be the big transition year for us where now we are generating free cash flow from this North Malay Basin and Stampede. And we can use that cash flow now to begin to generate into our development projects, say in Liza and other growth projects like in Bakken. So we will balance that continually going forward.

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

Yes. No, fair enough. Portfolio optimization, as I've said before, is something we look at every day and is in the normal course of business, so we are always looking to optimize that and go where the value is and go where the returns are.

Having said that, outright acquisitions are low on the priority list because what we have captured in our portfolio, both short cycle and long cycle already, offers very attractive returns to our shareholders.

And in terms of Guyana, it offers such attractive returns that that is not looking at something that we would sell down. But as I said, in our overall portfolio, we are always looking to optimize, and as opportunities present themselves, we will consider them.

Great. And maybe one quick follow-up on the Bakken. Fourth quarter, as you mentioned in your comments and as we've seen in the data, fourth quarter you saw a significant increase in well productivity, at least in terms of 30-day IPs, versus prior quarters.

Can you talk a little bit about what the mix shift was in terms of 50-stage fracs 3Q versus 4Q? And is that a number, what we saw in 4Q, that we should view as a more representative number of the drilling program going forward in terms of well productivity?

Yes. In the fourth quarter, you're right: all the wells that we drilled were 50-stage, and that was truly in the core of the core. So the best wells that we drilled in the Bakken, that 1,091 barrels of oil kind of IP 30, those were the wells we were drilling in the fourth quarter.

We will stay in the core in 2017. That will be the bulk of where our drilling is. Certainly on average, because of the 50-stage fracs, the IP 90s and the IP 30 rates will be higher in 2017 than they were in 2016. So the whole inventory is not going to be the 1,091 kind of IP 30s. That was truly some extraordinary wells. But it will still be -- the average is going to be higher this year than it was last year. So good upside there.

Great, thanks.

David Heikkinen, Heikkinen Energy.

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

David, make sure I understand your question. You want --

You gave BOEs. What's just the barrels of oil for fourth quarter?

Barrels of oil for the fourth quarter of 2016?

Yes, in that 330,000 to 340,000 guidance, what would be the split of gas and oil?

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

That's very helpful. Thanks, guys.

Jeffrey Campbell, Tuohy Brothers.

I was just wondering if you could share any early impressions of Aker as it takes over the operation of Valhall. I don't think it's rude to say that sometimes we felt like the prior operators left something to be desired. So I'm just wondering how you are feeling about them and your early impressions.

Yes, I think -- yes, thanks for the question. John and I have met with their senior management twice over the course of the year, as recently as a month ago. And we are encouraged by their approach. And we really look forward to working together with them to maximize value from the Valhall asset.

Hess did a lot with BP, and I will credit BP with their progress that they made in the last couple years using many of the techniques that we developed on South Arne, applying those to Valhall, both lean manufacturing and some chalk drilling and well abandonment techniques that we developed in the North Sea.

Aker BP is carrying on with that. And we are excited that they can even drive more improvement beyond what BP was able to achieve with our help in the last couple years.

Okay, great. I think we'll look forward to that. I just wanted to ask one quick question with regard to Guyana. It sounds like that the Liza-1, the Liza-3, and Payara all tested different formations.

So I was just wondering, with the next well that's coming and the visible exploration that you see, are you going to be just essentially testing one of those zones again in a different location? Or are you going to be testing an entirely new formation?

These are all Upper Cretaceous. So every one of these wells has been Upper Cretaceous. So all the well tests, everything that we are doing, is all confined to the Upper Cretaceous. Even Liza Deep is an Upper Cretaceous accumulation.

Okay, thank you.

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

Thank you.

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