赫斯 (HES) 2016 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2016 Hess Corporation conference call. My name is Shannon 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 of Investor Relations. Please proceed.

Good morning, everyone, and thank you for participating in our first-quarter earnings. 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 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 in the Risk Factors section of Hess's annual and quarterly reports filed with the SEC. Also, on today's conference call we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP 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 first-quarter call. I will provide an update on the steps we are taking to manage in the low price oil price environment, and review some of the highlights from the quarter. Greg Hill will then discuss our operating performance, and John Rielly will review our financial results.

Our strategy in this lower for longer price environment is guided by three principles: preserve our balance sheet, preserve our operating capabilities and preserve our growth options.

To preserve our balance sheet, on February 4 we successfully executed a capital raise of $1.6 billion through common and mandatory convertible preferred stock offerings. These proceeds will keep our strong balance sheet strong in the low oil price environment, and provide the financial flexibility to continue to invest in our growth projects -- North Malay Basin in the Gulf of Thailand, Stampede in the Deepwater Gulf of Mexico, and Exploration Offshore Guiana.

Further to preserving the strength of our balance sheet, in January we announced our 2016 capital and exploratory budget of $2.4 billion, 40% below 2015 levels. Our focus remains on value, not volume, and we do not believe that accelerating production in the current oil price environment makes sense.

Rather, we have reduced activity levels across our producing portfolio both onshore and offshore. Our Bakken rig count will be reduced from three rigs currently to two rigs during the third quarter, and is expected to remain at this level until the WTI price is closer to $60 per barrel. In the Utica, our one drilling rig was released in March, and no further drilling is planned this year. Offshore, we continued the drilling break in Norway and Equatorial Guinea, and the rig at South Arna in Denmark is set to be released in the second quarter.

In terms of our operating capabilities, we are delivering industry-leading performance as confirmed by third-party benchmarks, both in unconventionals and offshore drilling and development. Our resilient portfolio is linked to our top quartile operating capabilities, and is balanced between unconventionals and offshore, providing an attractive mix of short cycle and long cycle investment opportunities.

This balanced portfolio also casts a wider net for future long-term growth options. Our portfolio is leveraged to oil and liquids with industry-leading cash margins, and advantaged tax positions in the US and Norway that will accelerate cash flow growth as oil prices improve.

In terms of our growth opportunities we have leading positions in the Bakken and Utica shale plays, new field start-ups, North Malay Basin and Stampede, which combined are expected to add 35,000 barrels of oil equivalent per day of new production over the next two years and, by 2018, will become material cash generators. And recent exploration success in Guiana that has the potential to provide significant long-term value creation and growth.

Turning to our financial results, in the first quarter of 2016 we posted a net loss of $509 million or $1.72 a share, compared to an adjusted net loss of $0.98 per share in the year ago quarter. Compared to the first quarter of 2015, our financial results were negatively impacted by lower crude oil and natural gas selling prices, and higher exploration expense, which more than offset the positive impacts of lower gas costs and DD&A.

While low crude oil prices significantly impacted our first-quarter financial results, we delivered strong operational performance. Net production was at the high end of our guidance range, averaging 350,000 barrels of oil equivalent per day compared to net production of 355,000 barrels of oil equivalent per day in the year ago quarter. Pro forma for last year's sale of our assets in Algeria.

Net production from the Bakken averaged 111,000 barrels of oil equivalent per day in the first quarter of 2016, above our guidance range. Our Bakken team reduced drilling and completion costs 25% from the year ago quarter, to an average of $5.1 million per well.

In summary, with our strong balance sheet, oil-leveraged portfolio, and attractive growth opportunities, we believe the Company is well-positioned to deliver strong cash flow growth and long-term value as oil prices recover.

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

Thanks, John. I would like to provide an update on our progress in 2016 as we continue to execute our E&P strategy.

Starting with production, in the first quarter we averaged 350,000 net barrels of oil equivalent per day at the top end of our guidance range of 340,000 to 350,000 barrels of oil equivalent per day, and once again reflecting strong operating performance across our portfolio.

In the second quarter, we expect net production to average between 320,000 and 325,000 barrels of oil equivalent per day, reflecting planned maintenance downtime at Valhall, and several of our Deepwater Gulf of Mexico fields. As usual, we will provide an update to our full-year production guidance on our midyear call in July.

Turning to operations and beginning with the Bakken, our lean manufacturing approach has once again enabled us to deliver outstanding performance from one of the best core of the core positions in the play, where we retain a substantial drilling inventory with attractive economics, even at current prices. Despite reducing our Bakken rig count to an average of four rigs in the first-quarter 2016 from 12 rigs in the year ago quarter, net production from the Bakken averaged 111,000 barrels of oil equivalent per day in the first quarter compared to 108,000 barrels of oil equivalent per day in the year ago quarter.

During the first quarter, we drilled 19 wells and brought 31 new wells online. This compares to the year ago quarter when we drilled 60 wells and brought 70 wells online. We currently plan to maintain a three-rig program through the second quarter to release one rig during the third quarter and operate two rigs for the remainder of the year.

In 2016, we now expect to drill 62 wells and bring 87 new wells online. This compares to last year when we drilled 182 wells and brought 219 wells online.

In the first quarter, our average drilling and completion cost was $5.1 million per well. We expect to be able to maintain this cost level over 2016, even as we transition from our previous 35-stage completion design to our new standard 50-stage completion design.

This higher stage count is expected to deliver a 15% to 20% increase and initial production rates, and with our rigs focused in the core of the play, we expect our estimated ultimate recovery per well to move toward 1 million barrels of oil equivalent per day in the -- oil equivalent in the latter part of 2016.

We also continue to successfully execute our 17 well per DSU spacing pilots and still see the majority of the wells performing in line with type curves and with minimal interference. The combination of both higher overall type curve performance and higher density well spacing has allowed us to increase our estimated ultimate recovery from the Bakken from our previous estimate of 1.4 billion barrels of oil equivalent to 1.6 billion barrels of oil equivalent. For the second quarter, we forecast net Bakken production to average between 100,000 and 110,000 barrels of oil equivalent per day.

Moving to the Utica, in the first quarter the joint venture drilled six wells and brought nine wells on production. Net production for the first quarter averaged 29,000 barrels of oil equivalent per day compared to 17,000 barrels of oil equivalent per day in the year ago quarter.

Similar to our Bakken position, our Utica acreage is largely held by production, which allows us to reduce activity in the short term while preserving optionality [in] longer-term upside. While we benefit from our acreage being in the core of the play at a low 5% royalty, we released the one rig we had operating in the play in early March.

As a result of applying our distinctive lean manufacturing approach, over the past several years we have been able to reduce our drilling costs per foot by approximately 75% and our completion costs per stage by approximately 50%, while at the same time drilling some of the longest laterals in play.

We plan to run the asset for cash in 2016, and to resume drilling following a sustained recovery in commodity prices and further third-party infrastructure buildout, which will reduce the currently wide basin differentials.

Now, turning to the offshore, at the Tubular Bells field in the Deepwater Gulf of Mexico, in which Hess holds a 57.1% working interest and is operator, net production averaged 10,000 barrels of oil equivalent per day in the first quarter. During the quarter, we conducted the remediation work highlighted in our fourth-quarter call, completing asset jobs at two wells.

We are now moving the rig to replace a defective subsurface valve that failed to open. This is the second failure of this type in the field, and we are working with the supplier to understand the root causes of the manufacturing defect.

In the second quarter, we have an extended shutdown scheduled to tie back Noble's Gunflint field to the [Williams own host] facility and we plan to spud a fifth producing well in the field. In early April, we also completed our first water injection well, and we expect commence injection in the third quarter.

In Norway, at the BP-operated Valhall field, in which Hess has a 64% interest, net production averaged 30,000 barrels of oil equivalent per day in the first quarter. The operator plans to commence an extended shutdown in the second quarter due to required maintenance work at the Conoco Phillips-operated Ekofisk field.

At the South Arne field in Denmark, which Hess operates with a 61.5% interest, we have completed the current phase of development drilling and do not plan to drill any additional wells in 2016. Net production averaged 14,000 barrels of oil equivalent per day over the quarter.

At the Malaysian/Thailand joint development area in the Gulf of Thailand, in which Hess has a 50% interest, work continues on the Booster Compression project, which remains on schedule for completion in the third quarter. Net production averaged 230 million cubic feet per day in the first quarter.

Moving to developments, at North Malay Basin in the Gulf of Thailand, in which Hess holds a 50% interest and is operator, progress continues on full field development. Six out of 11 development wells have now been drilled, and drilling results to date are better than expected. Net production from the early production system averaged 30 million cubic feet per day in the first quarter.

Following completion of full field development in 2017, net production is planned to increase to approximately 165 million cubic feet per day. At the Stampede development in the Deepwater Gulf of Mexico, in which Hess holds a 25% working interest and is operator, we successfully floated the topside's main deck onto the production deck, set the whole structure into the offshore floating dock, and installed the oil export line.

Drilling operations are under way on the first production well, and first oil remains on schedule for 2018.

Moving to exploration, in the Deepwater Gulf of Mexico, the Chevron-operated Sicily-2 well, in which Hess holds a 25% working interest, reached its target depth and results are currently being evaluated. Also in the Gulf of Mexico, the Conoco Phillips-operated Melmar well, in which Hess has a 35% working interest, reached target depth in early April, and logging operations are now complete. The well results are still being evaluated, but as noncommercial quantities of oil were encountered at the current location, the well was expensed in the quarter.

In Guyana, in the Stabroek Block, in which Hess holds a 30% interest, the operator, Esso Exploration and Production Guyana Limited spud the Liza 2 well in February. This well is designed to further evaluate the significant Liza oil discovery, and will include an extended drill stem test. We expect the operator to complete operations on the Liza 2 well late in the second quarter.

Following the Liza 2 well, the operator intends to move the rig to test a separate prospect located approximately 25 miles northwest of Liza. We remain excited about the opportunity set on this block, which we believe could be material to our Company.

In closing, we have maintained excellent execution and delivery across our portfolio. We believe that our focus on preserving the strength of our balance sheet, while also preserving our top quartile capabilities and growth options, is the right strategy.

I will now turn the call over to John Rielly.

Thanks, Greg.

In my remarks today, I will compare results from the first quarter of 2016 to the fourth quarter of 2015.

In the first quarter of 2016, we reported a net loss of $509 million, compared with an adjusted net loss of $396 million in the previous quarter. That excludes a net charge of $1.425 billion.

Turning to Exploration and Production, E&P incurred a net loss of $451 million in the first quarter of 2016, compared to an adjusted net loss of $328 million in the fourth quarter of 2015. That excludes net charges totaling $1.385 billion.

The changes in the after-tax components of adjusted results for E&P between the first quarter of 2016 and the fourth quarter of 2015 were as follows. Lower realized selling prices reduced results by $187 million. Lower sales volumes reduced results by $4 million. Lower cash operating costs improved results by $28 million. Lower DD&A expense improved results by $71 million. Higher exploration expenses reduced results by $18 million. All other items net to a decrease in results of $13 million, for an overall increase in the first-quarter net loss of $123 million.

In the first quarter, our E&P operations were over [lifted] compared with production by approximately 500,000 barrels, which did not have a material impact on first-quarter results. The E&P effect of income tax rate was a benefit of 41% for the first quarter of 2016 compared with a benefit of 38% in the fourth quarter, excluding items affecting comparability.

Turning to midstream, first-quarter net income of $14 million increased from $11 million in the previous quarter, primarily due to lower operating costs. Bakken midstream EBITDA, excluding the noncontrolling interest, amounted to $70 million in the first quarter of 2016 compared to $67 million in the previous quarter.

Turning to Corporate and Interest, after-tax Corporate and Interest expenses were $72 million in the first quarter of 2016 compared to $79 million in the fourth quarter of 2015, which excludes net charges totaling $32 million. The reduction resulted from lower professional fees and general and administrative costs.

Turning to cash flow, net cash provided by operating activities before changes in working capital was $148 million. A net decrease in cash resulting from changes in working capital was $208 million. Additions to property, plant, and equipment were $620 million.

Net debt repayments were $12 million. Net proceeds from the issuance of common and preferred stock were $1.644 billion.

Common stock dividends paid were $80 million. Other net amounted to a use of cash of $31 million, resulting in a net increase in cash and cash equivalents in the first quarter of $841 million. Turning to our financial position, we had approximately $3.6 billion of cash and cash equivalents at March 31, 2016, and total liquidity, including available committed credit facilities of approximately $8.3 billion. Excluding Bakken midstream, total debt was $5.9 billion at March 31, 2016 and our debt to capitalization ratio was 23.1%.

Now turning to second-quarter guidance, for E&P we project costs for E&P operations to be in the range of $16.50 to $17.50 per barrel of oil equivalent, reflecting lower production and higher maintenance costs from the planned offshore facility shutdowns. DD&A per barrel of oil equivalent is forecast to be $26.50 to $27.50 per barrel, resulting in projected total E&P unit operating costs of $43 to $45 per barrel in the second quarter of 2016. The Bakken midstream tariff expense is expected to be $3.75 up to $3.85 per barrel of oil equivalent for the second quarter of 2016, while exploration expenses, excluding dry hole costs, are expected to be in the range of $70 million to $80 million.

The E&P effective tax rate is expected to be a deferred tax benefit in the range of 42% to 46% for the second quarter. For midstream, we estimate net income attributable to Hess from the Bakken midstream segment, which reflects our 50% ownership to be in the range of $10 million to $15 million in the second quarter. For Corporate and Interest, we expect corporate expenses, net of taxes to be in the range of $25 million to $30 million, and interest expense to be in the range of $50 million to $55 million in the second quarter of 2016.

This concludes my remarks. We will be happy to answer any questions.

I will now turn the call over to the operator.

(Operator Instructions) Ed Westlake, Credit Suisse.

Two operational questions, if I may. The first one, obviously the move to 50-stage fracks and the race to EURs, obviously you give good guidance in the supplementals about IPs, and obviously we can see some of the state data. But when do you think the completions of the 50-stage frack will actually start show up in the data? I appreciate there are some time lags; maybe some color about that, and then I have a follow-on on Guyana.

Okay, thanks, Ed. If you look at the majority of the wells that we brought on in the first quarter of this year, the majority were 35-stage fracks. So we will move into that 50-stage frack as we move through the year, and recall we expect a 15% of to 20% uplift from those 50-stage completions.

So if you look at IP rates, Q1, it was just under 800. We expect that to move towards 1,000 as we move into the second half of the year. So you really see the benefit of those kicking in in the second half of the year as we complete those new wells.

Okay, and then a follow-on just on Guyana. I appreciate the seismic, I guess, is now complete and processing. Maybe any update in terms of -- perhaps not the well you are drilling today, but the confident integral from the data that you've seen on the other channels as you move further to the northwest of Liza 1.

I think as Exxon has said and we have said, we see a fair amount of press activity on the block, and that continues to be confirmed with the 3-D seismic that we are processing. Again, we've just got to drill more wells. We plan to drill one or two additional exploration wells this year, and that will give us some additional color on prospectivity. But it looks good on seismic.

Thank you very much.

Doug Leggate, Bank of America.

Can I start with a couple of housekeeping points, I guess, just on the numbers for the quarter? The differentials internationally looked a little wide, and I'm wondering if there's anything -- any nuance there, and I guess a similar thing with the oil mix in the Bakken. So and I have a follow-up on exploration, please.

I will start with the differentials. There was something unusual, just in the first quarter. And it had to do just with our timing of lift. So there's two aspects of why our differentials widen.

So with the timing, actually we produce about -- approximately 75,000 barrels a day of oil internationally, but our liftings were heavily in January and February. We actually lifted about 89,000 barrels a day in January and 130,000 barrels a day in February. In March, liftings were only 19,000, so obviously we lifted more just timing wise when oil prices were lower in the quarter. And so that had an impact on our differentials.

The other thing that did a true weakening was on West African crude. It is not just ours, but in general, West African crudes were kind of the differential, widened about $1, and that did happen with our [e.g.] liftings as well in the quarter.

And on the oil mix in the Bakken, it looked like it swung a little bit towards NGLs, John.

Yes, Doug, this is Greg. That was primarily just a weather-related operational issue in January. It had to do with complying with read vapor pressure requirements in the field. That caused it to shut in some oil production, so if you look at kind of oil in January, it was actually down around [69], but that completely reversed itself in February and March. And it was at 75,000 barrels a day for the months of February and March.

So that came back up. So it was just a temporary transient issue in January.

Doug, the only thing I will add to that with the wells is we are -- and it is our focus this year with our midstream infrastructure -- we are out gathering more gas. So, from the wells as Greg said, the wells were impacted by the vapor pressure, and we will be adding additional gas into our gas plant and therefore NGLs throughout the year.

But just to be clear, the oil should come back or did come back, Greg, (multiple speakers) towards the end of the quarter?

As Greg said, it did. And so it is 69,000, 75,000 -- 75,000. So that 5,000 barrel a day increase was -- decrease was just impacted by those vapor pressure issues in January.

Just to be clear, from our wells themselves, there's no change in the oil and gas mix. It is steady as she goes.

Got it, that is what I was getting at. Thanks, John. My follow-up, though, is I am not going to ask about Guyana. But I would like to ask about Melmar and Sicily.

Has Melmar now been condemned by this well? And on Sicily, are you really just holding out, waiting on the operator commenting? Or is there some nuance in your commentary that you are still evaluating the results? Could Sicily end up being a field appraisal as well, I guess is what I am getting at.

No, Doug, on both wells it is really too early to comment. They are both under evaluation. As we said in the script, Melmar at the current location did not have economic quantities of oil. But that does not mean that the block is done. So we are under evaluation of all the data that came out of the well right now.

And on Sicily, Greg?

Same thing, Doug, under evaluation with the operator.

All right, thanks, guys.

Brian Singer, Goldman Sachs.

First question on the Bakken. I believe you said to think about ramping up there you would want to wait until you saw $60 a barrel WTI. And I wondered if you could add some color on why $60 versus lower or higher price.

How much of that decision is driven by your view of what the breakeven oil price is at the well level to meet your return thresholds versus your corporate needs to improve your balance sheet versus the competition for capital elsewhere, such as potential Guyana development?

All those factors play into that decision. And you did round it off pretty well.

So let's just start with returns. We have an excellent acreage position in the Bakken, and as you know, we have got good returns that we can drill wells here at $40 and we can drill at $50 and get good return wells. But obviously, at $60 the returns are going to be better and more of our acreage then meets our return thresholds as you move toward $60. So obviously, we want to improve returns for our shareholders.

The next aspect of it is we are spending money on growth right now. You know North Malay Basin and Stampede, so we will have 35,000 barrels a day coming in 2018 from those two projects, and like you said, we have already added some valuable resources here in Guyana, and we are going to continue exploration there and see if we can add more valuable resources there.

Then, it comes to the last part of your point was we do look at overall corporate cash flow, and we want to deliver growth with free cash flow. And at $60, Bakken, we can add rigs and Bakken will grow and generate free cash flow. So that is something that we are looking to do from the portfolio aspect.

And then with our balance sheet, with this low point in the cycle, we want to come out of that low point in the cycle with this strong balance sheet. So, our plan is because our portfolio is so levered to oil, $1 for us gives us $75 million of annual cash flow. So, we want to bank that cash flow as you move up to $60, again to improve the balance sheet. All those factors play a role.

Great, thank you. And then shifting to the international assets, there were a couple of comments you made that I wanted to see if you can add some additional color. The first was in North Malay Basin, where I believe you said of the development wells drilled, they were coming in better-than-expected. How that may impact if at all the total production, which I think you seem to say would not change in any kind of returns or well costs.

And then in Guyana, I believe you mentioned that there was an extended drill stem test being drilled if it is at all possible to have any color around what precipitated that.

Yes, thanks for the question. On North Malay Basin, the wells are coming in with thicker pay overall. Now, that will likely not affect the initial volumes coming out on North Malay Basin. It could have a positive reserve effect, but we are -- all of that is under evaluation right now. So it's too early to say one way or the other.

Regarding Guyana, again, the operations that we are conducting in Guyana with the operator, Exxon Mobil, two major objectives. One is appraise the Liza discovery so that will be additional wells to find edges of the reservoir, let's call it. Also, an extended drill stem test as well. That is key dynamic data that we will need in terms of designing a development of Liza.

The second objective is to drill those one or two exploration wells that I talked about which are going after some Liza look-alikes on the block.

Great, thank you.

Paul Sankey, Wolfe Research.

Just an [immediate] (multiple speakers) follow-up. You mentioned Guyana was I think you said potentially material, or maybe just material to Hess. When is the best hope for actual first production?

I think again, Paul, I think we've got to get these appraisal wells down. So it's too early to say when an early reduction system might come on. So, let us get through the appraisal, which will be in the third quarter, and then we can hopefully get some more color after that.

Understood, and make is given that you said it's material, we can hope to see press releases as to what's going on there from here.

Yes, we would hope after the appraisal drilling and drill stem test, the operator will be in a position to provide more color on resource estimate or range of resource estimate.

Great, thanks, John. The -- just the outlook for CapEx for the year, you came in low, relative to our expectations for Q1. I think the Q2 numbers may be a little bit higher than we thought. Can you talk a little bit about the sensitivities of the CapEx outlook to the oil price?

And I had heard -- and I have to say this is secondhand, that you talked about $60 a barrel being the point at which you would resume growth, I think, in the Bakken. With that an accurate secondhand story that I got? Or am I thinking of the wrong price? Thanks.

On the $60, I can answer that because it was in my remarks. Our first priority is the balance sheet. So, to be clear, first and foremost we just want to strengthen the cash flow generation of the Company and the balance sheet to fund our growth projects, and also come out of this low price environment on our front feet.

The second is, we have plenty of locations that John talked about and we have in our investor pack, where we generate in excess of a 15% after-tax return. At $50, probably over 600 locations and $60, over 1,000 locations. So our locations compete not only with the best acreage in the Bakken, but the best acreage of any shale play in the United States, including the Permian.

So our focus, even though we have those locations, is on value, not volume. And we are going to be guided by capital discipline and financial returns. That's why we said the $60 is our price that we will focus on, where we start ramping up Bakken activity.

Got it. I guess what you're saying then, John, is in the interim between $50 and $60, it would be a balance sheet prioritization strategy. And then could you guys follow on with the CapEx (multiple speakers) [activity] for the year? Thanks.

As usual, we will update middle of the year. You are right. Our capital was running a bit lower than the run rate in the first quarter. Obviously we are focused on being tight on spending on capital and operating, so we are looking at all possibilities to reduce.

But I don't want to get ahead of it. We will get through the second quarter, we will get through these shutdowns that Greg mentioned, and we will update capital in the middle of the year.

Great, thank you.

Ryan Todd, Deutsche Bank.

Maybe if I could follow up with one on the Bakken, and then shift somewhere else. On the Bakken, can you provide any color on the expected trajectory of -- you mentioned you're going from four rigs to -- or you went from three rigs and then to two rigs in the third quarter. Any shift?

I mean, I think earlier the view was to go from four to two by late February. Was there a shift in the plan of rigs? Is there a reason in terms of any thoughts behind the shift there?

And then, should we expect the completion to be effectively kind of ratable over the remainder of this year?

Yes, so the reason in going from three rigs, extending that third rig just a little bit longer, that was purely just an efficient way to ramp down the Bakken and really complete some existing pads. Because you -- while the rig is there, you would just as soon complete those pads rather than get them partially done and then come back later.

So that was purely an efficiency thing as we kind of lined out [via] work for the year. If you look at the Bakken production character, what we've said is that our ranges for the year is [105 to 95], and certainly directionally that mimics what is going to happen to the production curve. So, that is going to start at a high and then end the year probably close to the end of that -- or the bottom end of that range. So that will give you a sense for kind of how Bakken production is going to look over the year.

Obviously we are starting a little bit higher, but you can assume about a 10% decline over the year in the Bakken.

Great, very helpful. And then maybe one more.

Obviously very, very strong results on the EUR uplift from the Bakken. The 1 million barrel, the EUR number that you are talking about, how much of your 3,200 well inventory should we assume that is applicable to?

Is that a small -- is that a portion of it? Is that all of it? And is it kind of a ratable EUR increase across -- or it kind of an equal EUR percentage increase across all of your inventory?

No, it is not ratable. So again, this is a result of drilling in the core of the core. So we are really drilling in the best part of the Bakken right now. I don't have the exact numbers, but it's a couple hundred wells, or probably in this 1,000 EUR.

We did not increase EUR for the 50-stage fracks yet. There may be an EUR increase in the wells associated with that, but we wanted to get more production history under our belt before we increase the EUR associated with 50-stage fracks.

Great, thanks, Greg. I will leave it there.

Evan Calio, Morgan Stanley.

Let me follow up on the Bakken to Ryan's (technical difficulty) [question]. What are your thoughts on increasing the full-year guidance with increased completions today? I think you are 87 versus 80 in the first quarter, and I think your option report just came out with this improved spud to spud time, which would potentially give you a tailwind there. Any thoughts there?

As we always do, we will update all of our guidance on the July call after the second quarter. We will be updating production capital in all of the guidance. What I will say from a Company standpoint, we do have extended shutdowns in this quarter that were longer than we had in our original planning assumptions, both associated with third-party shutdowns. So, how all of that kind of offsets higher production in the Bakken, that's what we will guide the market on in our July call.

Fair enough. And the follow-up also on Guyana, I mean, should we expect a resource estimate this summer specifically for Liza? Or is it potentially a broader delineation of the potential or other prospects on the block? And is that -- is the resource estimate something that is in conjunction with additional pre-feed work being done? Or how does that relate to the timing on ultimate development?

Fair question, Evan, and we are going to leave that to the operator. (laughter) But it is obviously subject to the appraisal drilling and well tests that we are going to do, and then out of that we would hope that we could get some granularity on what the resource estimate on Liza might be. And I would not want to get ahead of ourselves beyond that.

Okay, maybe I will ask them on Friday as well. If I could squeeze in one last one on the office report, any color on the 30-day IPs, kind of the relative performance on the 50-stage completions in the year-over-year down? Did I miss that explanation earlier? Any color there would be helpful.

So, if you look at our first quarter, the IPs were just under 800. That also had some downtime. Remember I talked about the downtime in January, so that holds the IP rates down a bit. We guided 800 to 950 for the year, so basically the IPs will increase in here and we will move towards 1,000 barrels a day in the latter half of the year.

So, this first quarter got pulled down by some operational issues, but also we were putting on wells online that were more like 35-stage fracks carryover from last year. As we move into the year, that will move towards 1,000 barrels a day.

Great, guys, appreciate it.

Paul Cheng, Barclays.

Several quick questions. First, with John Rielly, John you gave a guidance for the second-quarter unique DD&A and the cash costs. Based on that, and the first-quarter results, it looks like the full-year DD&A, the previous guidance, $28.5 million to $29.5 million, seems way high. Is there any reason why we should not assume the second half of the year [your unique] DD&A would be somewhat similar to the first half? And in terms of the cash costs on the other hand, it seems like your previous full-year guidance, say $14.5 million to $15.5 million, if we assume the second quarter $17.5 million -- $16.5 million to $17.5 million, should we assume there is more to it into the high end of the range?

Let's go through. I will start with the cash costs. So the first thing in our cash costs in the first quarter, were down to $14.62, so it was over a 5% decline from Q4. And again, like we said, we are very focused on where we are spending money on operating costs as well as capital. And some of the operating costs in the first quarter, as Greg had mentioned, we did have higher workovers as well. So we have been pretty good at being able to reduce the costs.

Now on the flipside, Greg just mentioned that we had some extended shutdowns that were not part of our original plan. So that is from that second-quarter guidance, is driving up. So we have lower production and additional maintenance costs coming in the second quarter. It is driving up our second-quarter costs.

What we would like to do, and like with all our guidance, we would like to get through that. Then we will have six months of data, we will come in July, and we will give you an update for the cash costs at that point. And we will see where we are moving for the rest of the year.

DD&A is a mix issue, so again basically offshore, had to do again what Greg was talking about from fields that we had a mix where some fields were producing more at a lower DD&A rate than some of the fields that were producing less had a higher DD&A rate. So it was purely a mix issue.

So again, I would like to get through these shutdowns, get through the six months of data, before I do update the numbers.

Greg, just curious that if the turnaround -- downtime primary focus in the second quarter or it is going to have equal money in the third quarter or third quarter will be significantly lower?

Yes, no, the majority is going to be in the second quarter. That is T Bells and Conger in the Gulf of Mexico and then Valhall in the North Sea. There is a smaller amount in the third quarter, and that will be at JDA and South Arne.

Okay.

So that's how the shutdowns kind of break out throughout the year.

And as you move to the 50-stage, do you intend to keep the well costs to be flat from the current level? How about the cash operating costs? Is that going to [strictly] higher cash flow operating costs, or you will be able to more than offset it with the efficiency gains?

No, I think we will be more than able to offset that with the efficiency gains as well.

Okay, and Greg, just curious that in the first quarter if you are looking at sequentially, the US oil price realization drop $10, $11. Benchmark seems to be dropping $8 to $9.

Is there any mix issue that we should be -- realized that is causing that? And then reverse in the second or third quarter? Or that this is really going to be a new defense of looking at this is a good base now going forward?

You are correct. The onshore differentials did widen between the fourth quarter in the first quarter, so it is driven obviously up in the Bakken with our production.

Clearbrook was approximately $1 under WTI in the fourth quarter, and it moved to $1.80 under TI in the first quarter. So, that $0.80 was driving some of our differential.

The overall differential, though, moved about $1.55 in our production, and that is because the rail market was weaker than the first quarter versus the fourth quarter, again due to the narrowing of the Brent TI spread. Clearbrook has been getting a little better in April and May, not a big change. But it has been a little better than we are seeing on the sales volume.

So that could come back and then the rail market, that will move and we will try to optimize (multiple speakers) depending on where the best economics are.

And just a little more color, in the last year, our oil moved (technical difficulty) from 50-50 pipeline/train to 70%/30% pipeline/train. And we are maxing out our pipeline deliveries as we speak to make sure we get the most for our oil that we sell.

Final question if I could. Greg, if you're looking at your current manpower and organizational capability, if you are not having any headcount, what is the maximum number of rigs that you can handle, and how quickly that you can [ram it] down to that level if you want to?

Yes, good question. As John mentioned, our second priority is to preserve the capability. So, what we have done, one of the reasons that we did not cut the Bakken rigs to zero was we wanted to leave a couple rigs so that we could maintain the capability and ability to ramp up.

As we look at it, we think with the manpower that we have, because we have gone down substantially in manpower, but we think because the manpower that we do have, we think we can efficiently ramp up from two to six rigs over a nine- to 12-month period.

So we can go from two to six relatively painlessly without losing a lot of the efficiencies that we've worked so hard to maintain with lean manufacturing capability.

Thank you.

(Operator Instructions). Jeffrey Campbell, Tuohy Brothers.

Regarding the two Bakken rigs in 2016, my memory was that the Company once the four rigs were required to maintain efficiencies and skilled labor. I was just wondering has this efficiency just proved too expensive to afford or have you taken efficiency to new levels that allow for core competency preservation of the two rigs?

It's more the latter. We have taken our efficiency to new levels, and we believe that we can preserve enough capability with two rigs versus the four to be able to efficiently ramp up when prices improved to $60, as John has mentioned.

Okay, thank you. We are hearing a lot about cost reduction efforts from other offshore operators. I was just wondering if you have any line of sight for cost reductions that could support a resumption of drilling in places like Equatorial Guinea and South Arne and Ghana at lower oil prices than might have been the case earlier in the downturn.

Yes, so I think again, if you think about when we would restart drilling, as John Rielly mentioned in his comments, it is really going to be a function of corporate cash flow. So we are really going to be watching corporate cash flow before we restart drilling either offshore or onshore in the Bakken. So that's going to be the primary driver. But broadly, the pace of the cost reductions has been slower offshore than onshore due to the need to work off the backlog of those higher cost rig contracts, and also the work in the yard associated with previously sanctioned projects.

Now, rigs, boats, and associated equipment are already started to come down substantially and we know that because we are seeing a lot of those benefits in Guyana, for example, on the rig rates and the seismic boat rates. And then we expect that to continue as offshore projects are completed, so we think further rig cost capitulation will occur.

And importantly, the yard rates will start to come down as well, as capacity becomes available. And so, and in fact in some of our pre-feed work that we are doing around the globe, we are already seeing significantly lower in the indicative bids in the offshore yard and rig space. So, more to come in the offshore.

But again, I think it's going to be back to what John Rielly said. It is going to be a function of corporate cash flow.

Okay, thank you. I appreciate that.

Pavel Molchanov, Raymond James.

Very similar to the previous one with a small tweak, for Ghana, what Brent price would you need to see to sanction a full-scale development? So, above and beyond corporate cash [levels]?

Well, I think first of all, Ghana's is right now in suspension because of the border dispute. So we are working with the government to try and get the deadlines extended there. So until the border dispute is clear, which the earliest would be mid-2017, we would not be in a position to say what sanction price Ghana would need, because it would depend upon the cost curve. At that point in time, we do see costs coming down. So, way too early to speculate what price it would take.

Okay, and then same question about the Utica. What Henry Hub threshold do you have in mind to put at least one rig back to work in the Utica?

It's not the -- obviously it's the low commodity prices, and as Greg mentioned earlier, the wide basin differentials that are causing us the issue right now. The rock is very good. We like the asset. So it really is depending on the additional infrastructure being built out to get the product out of that basin. So we do see that happening, so as that infrastructure is built out, and we see the basin differentials narrow, along with improving commodity prices, is when we go back to work in the Utica.

Understood. Thanks, guys.

Arun Jayaram, JPMorgan.

I was wondering if you could just give a little bit more color around the magnitude of the Q2 downtime at Valhall, Conger, and Tubular Bells?

Let me give you directionally how many days of downtime or plans. So again, this is all third-party shutdowns, so Valhall expected to be around 25-day shutdown. That is associated with Ekofisk, so it is coincident with the Ekofisk shutdown. Tubular Bells, about 31 days down -- again that is a third-party tie-in of Gunflint to the Williams-owned host facility at Tubular Bells. And finally, there is the anticipated 22-day shutdown in Conger associated with Shell's turnaround of Enchilada Salsa during the second quarter, so that gives you an idea of how much.

Okay. And these would not have been in your original guide, right? These were outside of that?

No, they were. But the way the forecast works is you get an estimate from the operator when you are putting your business plan together and then the operator updates that as it gets closer to the forecast. So what happened is there were more days now as the operators have come forward, and given us the final data. They have extended those shutdowns longer than we thought. So that is why (multiple speakers) difference in the assumption there.

Okay. Just one on the Bakken, understanding you're capturing more gas. Do you have -- give us a sense of what you think as things normalize your oil, gas, NGL mix could look like, ballpark?

I think through 2016, this percentage of oil at mid-$60s, say, is where we see the crude being as it goes through 2016.

Mid-$60s? Okay. And last question is the G&A expenses were down pretty significantly on a sequential basis. Is that -- do you think you can hold that level of G&A they saw the first quarter, $98 million? (multiple speakers) It was down almost $40 million sequentially.

Right, so now some of that -- if you are just looking sequentially on the G&A line itself, we do have in the first quarter -- I'm sorry, in the fourth quarter there were some specials that were there. But we did have a good sequential decline in G&. Like I said, across the Company we are looking at costs all over operating, G&A. So, some of it is timing. We did have lower professional fees in the quarter, but we are trying and looking to reduce the costs. And the corporate guidance that we gave is a bit down now even for the second quarter.

So we are beginning to see some savings throughout the Company, but I would like to wait until the midyear before I update all the rest of the guidance.

Okay, thank you very much.

Phillip Jungwirth, BMO.

(technical difficulty) [$50] is the price required to increase activity in the Bakken, would that threshold be similar for some of your conventional offshore development areas such as the North Sea in West Africa? And can you provide any color on what you are doing in these areas to maintain operator capabilities?

I will just first talk about like when we are going to put capital back to work. And again, I just want to remind you, we have some great opportunities in great return locations even at these lower prices. But due to corporate cash flow, and maintaining the strength of the balance sheet is why we are going to move towards $60 before we put rigs back to work in the Bakken.

The way we are thinking about it with -- we have our development projects, Stampede and North Malay Basin. That is going to generate 35,000 barrels a day of production, 2018, we have Guyana. But the next call on our capital will be Bakken. That is when, as we look -- as we get to $60, there is plenty of running room there. We will start putting more rigs to work.

What it means now on offshore is -- and I think Greg might have mentioned it. It's not that we don't have very good return opportunities of tiebacks on our offshore assets. We do, some as good or even better than the Bakken. The issue that we, though, have is that you have to then commit to a rig. So you will have to get a rig to location. And what that is going to mean is that you are going to have to commit to multi-wells, or maybe even more than one year. So at that point, we are going to want even stronger prices than $60, and feel that it is sustainable before we go commit to that.

(multiple speakers) In terms of preserving capability, the second part of your question, we have done -- just like we done in the Bakken, we have moved people over, put them on special projects, special assignments. What you really don't want to lose is the drilling and completions capability. So we think we have adequately covered that in redeploying people to other opportunities.

Great, and on Tubular Bells, what is your expectation for second-half production there, and is there anything you've experienced to date that would cause you to believe peak production or EUR would differ from expectation?

No, I think again, as we mentioned in our opening remarks, we've had a failure of a second downhole valve which was unfortunately one of our largest producers. And so we've got to move the rig over to do that. It is not a rig-less intervention. It requires the rig.

So the second half of the year, Tubular Bells will hopefully be in that 25,000 barrel a day range that we thought it would be at this point, and would be had it not been for the valve failure.

Great, thanks.

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