HES
#Thanks <UNK>
I’d like to provide an operational update for 2016 and 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 cost
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 <UNK>ana, 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’ll continue to exclude it from our guidance
As <UNK> mentioned, in 2016 we achieved a reserve replacement ratio of 119% and SG&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 their shift to 50-stage completions and lower cost
Other areas with additions include North Malay Basin, South Arne and the Utica
In 2017, we forecast companywide production to average between 300,000 to 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 in forecast to increase in the third quarter with the start-up 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 the rig ramp up and the first new Valhall well comes online
Fourth quarter production is forecast to average between 330,000 to 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 continue to improve our drilling and completion performance with fourth quarter D&C cost 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’ve 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 IP30 during the quarter averaged a record 1,091barrels 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 IP90 rates which we feel are more reflective of a well’s actual performance
In 2017, we forecast IP90s 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 shutting facilities and wells
The net negative impact of weather in the fourth quarter on the Bakken was about 7000 barrels of oil per day
With the recovery in oil prices to the mid-50s, we plan to increase our rig count from the two rigs we currently have operating to six rigs 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, site spacing and higher stage counts deliver optimal value
Of the 75 wells we plan to bring on line this year, approximately 50 wells will be our new standard 50-stage design and we expect the D&C cost 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 our 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 and 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 dollars
For both of these trials, reservoir stimulation indicates a potential IP180 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 of 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 quarter 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 work over at the Tubular Bells field in the first quarter
A restart of a well at the Conger field also following a work over 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 <UNK> has 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're looking forward to working together with the new operator to maximize the value of the Valhall asset
Drilling from 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 <UNK> 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 <UNK> is 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 40 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 <UNK> 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 <UNK> 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 the 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 <UNK> as a 25% working interest and is operator, we successfully completed installation of subsea equipment at both drill centers and completed all topsides heavy lift on to the hall
Looking forward, in 2017 we will install the TLP and topsides on location, complete the subsea installation, and continue our drilling program
First oil remains on target for 2018. Turning to <UNK>ana, exploration and appraisal drilling activity continues at the 6.6 million acres Stabroek block in which <UNK> holds a 30% interest
As announced earlier this month, the Payara-1 well located approximately 10 miles northwest of Liza discovery, was drilled by the operator Esso Exploration and Production <UNK>ana Limited 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 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 Snoek exploration prospect, which is located approximately six miles south of the Liza-1 discovery well
The next well in queue is Liza-4 appraisal well, which will pass the eastern part at 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 are 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 span and operating costs while continuing to progress our future growth options
I will now turn the call over to <UNK> <UNK>
<UNK>, it is just too early to say on Tubular Bells and that’s because we are basically increasing the chokes and not only that the well that was worked over and they came on in December 31, but also the new well they came on late December as well, so we are just in the early stages of ramping Tubular Bells back up I want to get it stable, we are also getting wider injection stables, I really want to see kind of the well results from that before I be specific on that, so potentially maybe we could provide an update once we get stable
We aren’t going to give that and again <UNK>, I am not trying to be evasive, I just really want to see these wells ramp up and see what they are at
So if oil prices come in higher you know what we are doing with the rig ramp in Bakken, we have always said that first call in cash will be the Bakken
So we will continue to look and accelerate how we will bring the rigs in and so that’s what we would be thinking about at this point
So the first call would go to the Bakken
That’s under discussion with the operator <UNK>, obviously after we take out FID, we want third drilling development wells at some point
Well, let me talk about the completions in the Bakken first, as we said in our opening remark, 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 in eight spacing we 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 pro-well proppant loading that gives you a nice uniform frac all the way down the well bore and as you know we have worked with our supplier to continue to engineer more and more sliding sleeves in the 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 tolerance as 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 in eight spacing which is only about 500 feet between the wells, we are going to pilot those higher loading to find out where the optimum point might be to further increase value while not causing significant well to well interference
So when we know what 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 on technology, I think again as we approach 70 stages and got a lot number I think we are start to reach the technical limit there and next things will be proppant loading for us in the core of the core
But again that sliding sleeve system because it is 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 being testing that an in the later years 2018, 2019, data seems to indicate that maybe slickwater completions or even higher proppant loadings with plug and perf maybe the answer out there and that’s purely because there is a lot natural fracturing when you get out of core of the cores
So you are going to need more sand and more energy in the reservoir to connect all those fracture to that
So that’s kind of where I see it going
Yeah, so, <UNK>, the early production system, the reason the production is down slightly this year is because of well
So, we lost the well and that early production system is going to go, remember that, 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 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 pre-drill expectations
So, the wells are healthy
We've got a great wealth 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
I can give you more color on that as we get closer to actually bringing it on, <UNK>
If you ask me that in mid-year and I can give you some more color
No, we'll give you guidance on that later in the year as we get closer
So, we still have - remember what we're trying to do this year, we're going to float out the TLP and topsides, get those landed on location
We got to get all the subsea umbilicals and flow lines done and then we'll also continue drilling
So, 2018 is a big year of installation
So, we'll give you more color as those activities progress throughout the year
Sure
So, again the key is, as we've been talking about, we've been spending this capital on these development projects, North Malay Basin and Stampede and we're getting obviously closer to getting them both online and generating free cash
So, if you are 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 kind of at the current strip prices that we have
So, it's - and then going forward, it's like <UNK> just said, I mean 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
Now we're generating free cash flow from this North Malay Basin in 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
Yeah, I think in the fourth quarter, you're right
All the wells that we drilled are 50-stage and that was truly in the core of the core
So, the best wells that we've drilled in the Bakken that 1091 barrels of oil, kind of IP30, 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 IP90s and the IP30 rates will be higher in 2017 than they were in 2016. So, the whole inventory is not going to be the 1091 kind of IP30s
That was truly some extraordinary wells
So, it'll still be - the average is going to be higher this year than it was last year
So, good upside there
<UNK>, make sure I understand your question
Yeah, thanks for the question
I think <UNK> and I have met with their senior management twice over the course of the year as recently as a month ago and we’re encouraged by their approach and we really look forward to working together with them to maximize value from the Valhall asset
<UNK> did a lot with BP and I’ll credit BP with their progress that they’ve made in the last couple of years using many of the techniques that we develop on South Arne, applying those to Valhall both lean manufacturing and some shaft drilling and well [indiscernible] techniques that we developed in the North Sea
Acre, BP is carrying on with that and we’re excited that they can even drive more improvement beyond what BP was able to achieve with our help in the last couple of years
Now, these are all upper cretaceous, so every one of these wells has been upper cretaceous
So all of the well test, everything that we’re doing is all confined to the upper cretaceous
Even the Liza deep is upper cretaceous accumulation
Do you mind, I just want to clarify something for the group that I gave because that was - you were specifically asking before 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 into 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
