HES
#Thanks, Greg
Let me start by discussing our recently announced asset sales and the use of proceeds
We expect the sales of our interest in Equatorial Guinea and Norway to be completed by year-end 2017. And together with our Permian EOR sale, total proceeds are $3.25 billion from the announced transactions
Additionally, we anticipate that the Denmark sales process will be completed in 2018. As the proceeds from these transactions are received, we intend to reduce debt by $500 million and are evaluating plans to add up to two additional rigs in the Bakken during 2018 for a total of six rigs
The proceeds from asset sales along with our current cash position and importantly, our free cash flows from our low cost cash generative assets in the Gulf of Mexico and Malaysia, provide us the financial flexibility to fund our growing world-class investment opportunity in <UNK>ana in an extended $50 oil price environment without the need to access the debt or equity markets
We do not intend to pursue any M&A activity, and believe that our reshaped portfolio provides us with superior returns compared to other outside opportunities
We are highly cognizant of the importance of cash returns to shareholders, given the strength of our current liquidity position
However, we need more visibility into Exxon's plans for phase 2 and 3 of the Liza development in <UNK>ana
Until we have this clarity, we initially plan to maintain a strong liquidity position, but will clearly consider cash returns to shareholders as appropriate
I would also like to provide some additional comments on the deals just announced
The Equatorial Guinea and Norway asset sales will not incur any transaction taxes
We also will not incur any taxes on the repatriation of these proceeds
Additionally, the company has settled open tax matters with the EG taxing authorities for the tax years prior to the effective date
In this regard, the company will release $85 million in related tax reserves on the balance sheet, which it had accrued in prior periods for the years in question
These reserves fully cover the company's tax obligation under the settlement
Now turning to our results, I will compare results from the third quarter of 2017 to the second quarter of 2017. We incurred a net loss of $624 million in the third quarter of 2017 compared with a net loss of $449 million in the previous quarter
Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $324 million in the third quarter of 2017. Third quarter results include an after-tax gain of $280 million associated with the sale of our enhanced recovery assets in the Permian Basin
The sale transaction included both upstream and midstream assets, and as a result, an after-tax gain of $314 million was allocated to the E&P segment, and an after-tax loss of $34 million was allocated to the midstream segment
Third quarter results also included a non-cash charge of $550 million after-tax for the sale of Norway
In the fourth quarter, an additional charge relating to the Norway cumulative translation adjustment included in shareholders' equity will be recognized
The cumulative translation adjustment for Norway at <UNK>eptember 30, 2017 was approximately $840 million
Turning to E&P
E&P had an adjusted net loss of $238 million in the third quarter of 2017 compared with a net loss of $354 million in the second quarter of 2017. The changes in the after-tax components of adjusted E&P results between the third quarter and second quarter of 2017 were as follows
Higher realized selling prices improve results by $37 million
Higher sales volumes improve results by $10 million
Lower operating costs and expenses improve results by $18 million
Lower DD&A expense improve results by $33 billion
Lower exploration expenses improve results by $12 million
All other items improve results by $6 million for an overall improvement in third quarter results of $116 million
The E&P effective income tax rate excluding specials and Libyan operations was a benefit of 18% for the third quarter of 2017 compared with a benefit of 8% in the second quarter
For the third quarter, our E&P crude oil sales volumes were under-lifted compared with production by approximately 280,000 barrels, which did not have a material impact on our results
Turning to Midstream, on an adjusted basis, the Midstream segment had net income of $22 million in the third quarter, which was up from $16 million in the second quarter
Midstream EBITDA before the non-controlling interest and excluding specials amounted to $109 million in the third quarter, compared to $96 billion in the second quarter of 2017. Turning to Corporate, after-tax corporate and interest expenses excluding items affecting comparability were $108 million in the third quarter of 2017, compared to $111 million in the second quarter of 2017. Third quarter 2017 results include an after-tax charge of $30 million in connection with vacated office space
Turning to third quarter cash flow, net cash provided by operating activities before changes in working capital was $415 million
Changes in working capital reduced operating cash flows by $327 million
Additions to property, plant and equipment were $513 million
Proceeds from the sale of assets were $604 million
Net repayments of debt were $19 million
Common and preferred stock dividends paid were $91 million
Distributions to non-controlling interest were $33 million
All other items were a net decrease in cash of $2 million resulting in a net increase in cash and cash equivalents in the third quarter of $34 million
Changes in working capital during the third quarter of 2017 were net cash outflows related to Norwegian abandonment expenditures, advances to operators, premiums on hedge contracts and the timing of interest payments
Turning to cash and liquidity, excluding midstream, we ended the quarter with cash and cash equivalents of $2.48 billion, total liquidity of $6.8 billion including available committed credit facilities, and debt of $6.16 billion
As previously mentioned, we also have a strong crude oil hedge position through 2018 to protect our cash flow
Now turning to guidance, but before I give the guidance for the fourth quarter, I will provide third quarter pro forma financial metrics that remove the EG, Norway and Denmark assets being sold, but exclude the projected $150 million of cost savings to assist with your modeling of the portfolio post asset sales
Our third quarter pro forma cash costs were $12.80 per barrel as compared to actual reported results of $13.67 per barrel
Our third quarter pro forma DD&A per barrel was $23.72 and actual DD&A was $24.79 per barrel
Finally our pro forma tax rate excluding Libya was a benefit of 2% as compared to our reported benefit of 18%
I will now provide fourth quarter guidance with a cautionary statement that this can be impacted by the timing of the asset sales
Also, our DD&A rate will be lower than expected because DD&A will not be recorded on EG and Norway post the contract signings, since these assets will be classified as held for sale
The lower DD&A will improve results and therefore also impact our tax rate significantly since Norway has a high statutory tax rate
For the fourth quarter of 2017, E&P cash costs excluding Libya are projected to be in the range of $13.50 to $14.50 per barrel of oil equivalent and full-year 2017 cash cost guidance remains unchanged at $14 to $15 per barrel
DD&A per barrel excluding Libya is forecast to be in the range of $22.50 to $23.50 per barrel in the fourth quarter of 2017, and $24.50 to $25.50 per barrel for the full year, which is unchanged from previous guidance
As a result, total E&P unit operating costs are projected to be in the range of $36 to $38 per barrel in the fourth quarter and $38.50 to $40.50 per barrel for the full year
Exploration expenses excluding dry hole costs are expected to be in the range of $75 million to $85 million in the fourth quarter with full-year guidance of $225 million to $235 million, which is down from the previous guidance of $250 million to $270 million
The Midstream tariff is projected to be in the range of $135 million to $145 million for the fourth quarter and $535 million to $545 million for the full year, which is updated from previous full-year guidance of $520 million to $535 million
The E&P effective tax rate excluding Libya is expected to be an expense in the range of 16% to 20% for the fourth quarter
For the full year, we now expect a benefit in the range of 5% to 9%, which is down from previous guidance of 11% to 15% due to the asset sales
For Midstream, we anticipate net income attributable to <UNK> from the Midstream segment to be in the range of $15 million to $20 million in the fourth quarter and $70 million to $75 million for the full year, which is updated from previous full-year guidance of $65 million to $75 million
Turning to Corporate, we expect corporate expenses to be in the range of $30 million to $35 million for the fourth quarter and full-year guidance of $130 million to $135 million, down from previous guidance of $135 million to $145 million
We anticipate interest expenses to be in the range of $70 million to $75 million for the fourth quarter and $300 million to $305 million for the full year, which is updated from previous full-year guidance of $295 million to $305 million
This concludes my remarks
We would be happy to answer any questions
I will now turn the call over to the operator
Question-and-Answer <UNK>ession
This will clearly improve our F&D costs as we move forward
I mean, part of our strategy of divesting these high-cost assets is to free up capital, accelerate value and be able to put that capital into our high return <UNK>ana and Bakken assets
<UNK>o if you look at <UNK>ana, I mean, right now, if you just take phase one, that's a $7 F&D
If you just look at the gross costs there associated with Liza and the reserves that we're going to get, it's a $7 F&D
Take our Bakken numbers
Again, under $10 F&D
<UNK>o we'll have a substantial improvement and that is, again, part of the key of this portfolio strategy moves are to get this capital to invest in these great return assets
The other thing, the other aspect of it, as you said, Norway was not generating much cash flow from us at all
We have significant abandonment expenditures
Actually Norway was only going to provide us $20 million of net cash flow in the quarter
I mean, sorry, for 2017. EG, like you said, was in decline
<UNK>o there was $170 million of net cash flow in 2017, but we weren't investing because it didn't compete for capital
<UNK>o the way we look at this, from a net cash flow standpoint, the proceeds that we got, we received a 14 times multiple on that net cash flow
<UNK>o again that – and also that net cash flow on Norway was not going to improve here through 2020. EG was going to decline, so that wasn't going to be generating much free cash flow for us in our portfolio
As <UNK> mentioned too with the high costs of all these assets coming out of the portfolio and our cost reduction program, we can really start driving down our break-evens on F&D and our portfolio cash costs will be driven down under $10. <UNK>o, again we just think just great strategic moves for us and our portfolio
And can I – I just also want to clarify one thing on your question, because again we're seeing all positives
But the way – when you asked the question you said the increase in costs from second quarter to third quarter
If you're looking at our supplement, make sure you look at the footnote down there
We have apples and oranges between the second and third quarter
If we had broken out in the second quarter the 60, 140,000 wells and the 50, 70,000 there was no increase actually in cost from the same type of wells being drilled
The thing was we were just doing pilots here in the first and second quarter, so we were only putting the 50-stage fracs with the 70,000 pounds proppant there
And so now in the third quarter, since we've moved basically to the 60, 140,000s, we're just including all the wells there
<UNK>o I just wanted to clarify that there's no real increase in our well cost
At this point, I'd still – I'd stick with that guidance and here's what the difference is from that last quarter is
<UNK>o we do have the asset sales
<UNK>o Norway, you're in that $120 million to $130 million of capital this year that will not be there next year
EG was very low
Now, as Greg mentioned, we are considering adding two more rigs in the Bakken during 2018. <UNK>o you do have that type of offset
<UNK>o, we're still looking at being flat, but we're going to be going through our normal budget and plan process and we'll be updating that with our fourth quarter numbers
<UNK>o in the third quarter when you compare the third quarter to second quarter, actually even with DAPL, the Clearbrook was essentially unchanged, the second quarter to third quarter
And now, a good majority of our production doesn't go to Clearbrook
Just like all other operators, you have to get it out of the basin
<UNK>o with Clearbrook essentially unchanged, and you're moving your product outside of North Dakota, you just have some additional cost comparatively between the second and third quarter even with DAPL starting up
<UNK>o that's where that is in the third quarter
Now right at the end of the third quarter going into the fourth quarter, Clearbrook has clearly improved
<UNK>o, those values from Clearbrook would show up more in the fourth quarter
Well, first you should start with that, that the new projects or the projects like Bakken and <UNK>ana, they're going to have better returns than the assets that we're divesting
<UNK>o clearly, that's going to drive improvements in cash costs and DD&A and F&D, everything as we spoke about before
As far as just accounting, we go through and it goes on a quarterly basis
You evaluate what prices are
We'll be going through our budget and plan with the board and setting price (00:55:57) in the fourth quarter and we'll look at all assets at that point in time on where prices are, and then you go through your normal impairment reviews at that point in time
But that will happen on a quarterly basis
Yes
<UNK>o I mean, just now when you look at our portfolio now and as we get through to 2020 with <UNK>ana, we want to be in a situation right that we set ourselves up in this portfolio that we've got a low-cost, cash-generative portfolio and have the ability through these asset sales to bring cash forward to pre-fund effectively <UNK>ana
What Malaysia now provides us, and I'm saying now is because we were developing North Malay Basin
North Malay Basin now is coming on
It's ramping up to its full production capacity
Putting North Malay Basin and JDA together, I guess the best way I'd describe this as a nice long-term infrastructure asset that provides this cash brick
Just cash flows year-in, year-out in your portfolio and it's both the JDA and North Malay Basin
Obviously their P<UNK>Cs, prices go down, you get coverage as prices go down
<UNK>o it's a great part, that this Malaysia asset is just really key for us to drive our cash flow to help fund our assets
Now, go forward, you never know long-term what happens, but Malaysia is right now a key core asset for us to generate cash flow and drive us through to 2020 as <UNK>ana comes on
<UNK>ure
<UNK>o I gave on – when I gave the pro forma numbers, you saw the benefit that we were recording was – our actual was 18% in the third quarter and on a pro forma basis, that goes down to 2%
<UNK>o it all depends that – what that means is as you can tell, those assets had losses and were generating losses in the portfolio
And so, we'll have less losses and you won't be benefiting, just like you said, at those higher tax rates
<UNK>orry, I must have missed that
One other question for me
<UNK>o last month, the International Tribunal of the Law of the <UNK>ea decided in favor of Ghana in their maritime dispute with the Ivory Coast
How do you guys expect to proceed with your, I guess, acreage in that region or in the offshore of that country
Are you guys planning to continue drilling or monetize that acreage?
I mean obviously I think we've said it over and over
The whole goal of our strategy here in these portfolio moves are to improve the returns on invested capital
<UNK>o that's what we're focused on
<UNK>o now by selling those high cost assets and just from that prior question, as you know, those assets, just from, as I told you on a pro forma tax rate, were generating losses in the portfolio, and you're right
We are doing all this and planning for, can you call it a low price or an extended $50 oil price environment, and we believe we set ourselves up to win in this $50 environment because one, now we have the cash to be able to fund <UNK>ana just like you said
And then the assets that we will be investing in which are <UNK>ana and we've gone through the returns there, and I know we've gone through this, we have it in our investor deck of how <UNK>ana can compete and actually do better than even some Permian, Delaware type assets in a low price environment
<UNK>o, that will improve our returns
And like we said earlier, Liza has a $7 F&D, so that will drive down DD&A
The Bakken as well will continue with the investments that we have at four rigs and as you know, we're evaluating going to six rigs
The reason we're evaluating going to six rigs is because of the tremendous returns that we see in our portfolio there and we have plenty of well locations that work at sub $50. <UNK>o that will also, a low F&D and improved returns in both Bakken and <UNK>ana are going to be at a cash cost lower than our current portfolio average
<UNK>o the returns that we generate there are going to improve and the point and the goal and I guess the way you can measure it is, as we say post <UNK>ana in a $50 world, when that comes up, it's all these investments will be generating free cash flow post the <UNK>ana production starting up
And then as you will start to see that, we'll generate, post the <UNK>ana production again, net income will continue to increase along with that cash flow
<UNK>o it is all about trying to shift and reallocate the capital in our portfolio to the highest returns and we believe these Bakken and <UNK>ana investments will really drive that improvement in return on capital employed
Okay
<UNK>o I mean, you heard at least from a pro forma standpoint, we're dropping in the third quarter
It went over $1. <UNK>o that's one thing just starting there
When these assets come out of the portfolio, you're going to get that
Every time we bring on a new barrel in the Bakken, with this F&D, that's driving down our DD&A rate
And then <UNK>ana, now the big change there with the F&D there, that won't happen until 2020. <UNK>o it's just going to be a progression as we move through from 2017 to 2020 on driving down that DD&A rate
And like you said on the – we talked about on the cash cost, you can just start from where we are right now at $14 driving it down to under $10 as we go to 2020. <UNK>o it's just going to be that slow progression on cash costs and DD&A as we move through
No, I can't exactly at this point, but I can do that on the fourth quarter
With all else being the same, you would use this pro forma number of that I said were $23.72, and then that would come down based on the investments and the growth that we have in the Bakken coming through
<UNK>o it'll be lower than that number in 2018. And then we'll continue to look at all the assets and on our portfolio mix, it depends on where production is as we go into 2018. And I'll update on our call then
<UNK>o what we have in those numbers to get down to the $10 is, I'm not assuming any efficiencies per se in there
<UNK>o, I mean, again our teams have been really good on continuing to drive down our cash costs across our portfolio
<UNK>o there are potential upside to those numbers
<UNK>o you do have the higher-cost barrels that will be coming out and then you have the $150 million of cost savings which I did not factor into those numbers there
Then, what helps to drive is kind of the – going back to what Greg was talking about on the pro forma production momentum
<UNK>o you have North Malay Basin which is coming in at the full rate starting in 2018. That is one of the lowest cash cost assets we have in the portfolio
<UNK>tampede coming on
Gulf of Mexico assets very low cost, so that will continue to drive down the cash costs and then you have the Bakken
<UNK>o activity levels that we talked about in here, we've got four rigs in there
We know we're considering going to six
We have the four rigs and the additional production, as you can talk about our oil production growth of 10% per year
With that our low cash costs will also drive down the cost
And then obviously when <UNK>ana comes on you get the final piece to drive it down
<UNK>o, yeah, no, we're not assuming any heroic efficiencies or anything in there
It's the quality of our assets and the investments in these high-return assets along with the start-up of our developments that will drive these costs down to $10 and below
<UNK>o it will be across the board
I mean, I think, you will see the majority from an income statement line item will be in the G&A line item
But we will have some that will be – some of our reduction will be in our operating costs as well
And just so – like we will be finishing all our work on that and our organization redesigning in 2018 and we will have transition costs in 2018 that offset some of these savings
<UNK>o it's really, from 2019 on is where you'll see this $150 million cost savings kind of flowing through our numbers
No, I
This will be – it'll be a
Yeah
It's a big number
I mean obviously with Norway, EG and then Denmark being sold, there is a reduction in our portfolio and what we're doing is just rationalizing our fixed cost base that we have here to support our production portfolio
And it's just going to be part of that
We've done high level design on this
The reductions will be across all aspects be it central functions, be it corporate, be it E&P
<UNK>o we're looking at all of that
And as I said, you'll start to see it in 2018 because we will be enacting it
It's just that we will have transition costs in 2018 and get the full benefit in 2019.
<UNK>o look, we have put it on paper and we feel comfortable, very comfortable with that $150 million
You've got to factor in a lot of ancillary costs
<UNK>o you've got supply chain activities in every one of those areas
We've got tax activities in every one of those areas
We do have finance support in all of those areas, IT support in all of those areas
<UNK>o we've looked at all of that
And so, it will be head count, it will be other operational type costs that will be reduced and I will tell you I feel very comfortable about the $150 million by 2019. Again we will incur this transition cost in 2018.
The bulk of this was because the support is really for our E&P, so the bulk of it will be in the E&P numbers, being able to reduce our costs within E&P, but there's going to be clearly corporate cost reductions as well
<UNK>o, at this point, we're not going to provide that number
The cost reduction of $150 million are going to run across the board
There will be head count reductions, there will be vendor cost reductions, just due to the size of the portfolio getting smaller
But it's just premature for me to give those type of numbers
<UNK>o, your estimates are exactly right on the cash flow and that the asset sales are coming into to fund this great opportunity that we have in <UNK>ana
As you said, you have that phase one cost
We don't have any guidance out there
The only thing I will tell you is that the initial phase one FP<UNK>O has a capacity of 120,000 barrels per day
It has not been landed what phase two and phase three are, but it could be likely to be at a larger size than that 120,000 [barrels per day]
But outside of that, we haven't had any additional guidance that we're able to give out at this point in time
