康菲 (COP) 2017 Q4 法說會逐字稿

Welcome to the Fourth-Quarter 2017 ConocoPhillips Earnings Conference Call.

My name is Christine, and I will be your operator for today's call.

(Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Ellen DeSanctis, VP, Investor Relations and Communications.

You may begin.

Thank you, Christine, and hello, everybody.

Welcome to today's earnings call.

Our speakers today will be Ryan Lance, our Chairman and CEO; Don Wallette, our EVP of Finance, Commercial and our Chief Financial Officer; and Al Hirshberg, our EVP of Production, Drilling and Projects.

Our cautionary statement is shown on page 2 of today's presentation.

We will make some forward-looking statements during this morning's call that refer to estimates or plans.

Actual results could differ due to the factors described on this slide as well as in our periodic SEC filings.

We will also refer to some non-GAAP financial measures today, and that's to facilitate comparisons across periods and with our energy and E&P company peers.

Reconciliations of non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and on our website.

(Operator Instructions)

And now, I'm happy to turn the call over to Ryan Lance.

Well, thank you, Ellen, and welcome, everyone, to today's call.

We're excited about the release we issued this morning.

In it, we provided a summary of 2017 performance but also announced several significant actions we've already taken in 2018 that should send a very strong message about our commitment to staying disciplined and continuing to deliver our returns-focused value proposition.

For ConocoPhillips, our value proposition is an approach to the E&P business that's aimed at delivering predictable performance and superior returns through cycles, not chasing the cycles.

Our strategy works when prices are below $50 per barrel like they were for much of 2017 or $60-plus per barrel like they are right now.

Our value proposition is focused on creating long-term value and winning back both energy and generalist investors to a sector that has underperformed for far too long.

Industry is in the early innings of the earnings season, but what you'll hear from ConocoPhillips today is that we're not only sticking to our disciplined plan, we're building on it.

And that's what we'll point out to you on slide 4.

In the middle column of this slide, we've listed the things we're focused on as a company, namely having a low cost of supply portfolio, generating top-tier free cash flow and returns, maintaining a strong balance sheet, distributing a differential payout to shareholders, growing cash flows via per debt-adjusted per share production growth, and last but certainly not least, demonstrating leadership in ESG.

On the left side of this chart, we've listed some of the key 2017 achievements that allowed us to fully activate our value proposition across these focus areas.

Let me step through those now.

As you know, we had a very significant portfolio reset in 2017.

We substantially reduced our exposure to North American gas and oil sands, with dispositions that generated about $16 billion of proceeds.

Including -- excluding disposition impacts, we delivered organic reserve replacement of 200 percent.

Our lower sustaining capital and our peer-leading sustaining price enabled us to deliver top-tier free cash flow.

At 2017 average Brent prices of $54 per barrel, our cash flow from operations exceeded capex by $2.5 billion.

We turned the corner on profitability with full-year adjusted earnings of more than $700 million.

And more importantly, we're in a much stronger position to deliver improved cash and financial returns even at crude prices of $50 per barrel or less.

We reduced our debt by almost 30 percent to less than $20 billion and improved our credit rating.

We returned 61 percent of our cash flow from operations to shareholders via our dividend and buybacks.

Last year, we grew the dividend 6 percent and repurchased $3 billion or about 5 percent of our shares.

Underlying production grew on a per debt-adjusted share basis by 19 percent, and we continue to emphasize CFO expansion not production growth for growth's sake.

We delivered on our operational metrics while achieving one of the best years ever on safety, and I'm extremely proud of our organization for this.

We can never take our eye off that ball.

And in 2017, we announced a long-term target to reduce greenhouse gas emissions, a significant step forward demonstrating our commitment to ESG.

So it's hard to argue that 2017 wasn't an exceptional year for ConocoPhillips.

But we know that's the past and what matters now is what's next.

We laid out a 2018 plan a few months ago that was based on $50 per barrel WTI prices but certainly, prices have moved quite a bit higher since then.

So the obvious question is, will our plan change?

The answer is no, not with respect to our organic investment plan.

Our $5.5 billion capital plan is unchanged from what we outlined in November.

Of course, that excludes the bolt-on transaction in Alaska we announced this morning for $400 million.

This is a very attractive transaction that allows us to consolidate our existing position on the Western North Slope where we have an ongoing development activity and an exciting 2018 exploration program currently underway.

Even with the higher prices today, we believe it's critical to maintain discipline on our capital program.

Why?

Because that's the key to free cash flow generation and through cycle returns.

While we would expect 2018 cash flows to be significantly higher at current prices, we are not increasing capital activity.

Instead of increasing capex, we're following our priorities by allocating excess cash flow toward our dividend, our balance sheet and our share buybacks.

We have already paid down an additional $2.25 billion of debt this year.

We just announced a 7.5 percent increase in our quarterly dividend, and we're upsizing our planned 2018 share repurchases by over 30 percent to $2 billion.

By the way, this represents a total of $5 billion in buybacks when combined with our 2017 repurchases.

We're on track to deliver 13 percent production growth on a per debt-adjusted share basis, largely from activating our high-margin Lower 48 plan.

Again, our goal is cash flow expansion from high-margin volumes, not growth per se.

And we'll stay focused on our ESG leadership throughout the year.

So while the outlook for the business looks better than it did just a few months ago, we are not changing our plan.

We're staying committed to our priorities and taking steps early in the year to deploy additional cash from the stronger outlook to our shareholders.

2017 was a very strong year for the company, and we certainly intend to make 2018 another strong year by safely executing and delivering on our plans.

So let me turn the call over to Don and he'll discuss some of our financial highlights.

Thanks, Ryan.

Before I recap the fourth-quarter results, I want to summarize some notable milestones since our November analyst and investor update.

In December, we reached the successful conclusion of our arbitration with Ecuador, allowing us to recover over $300 million.

Also in December, we retired $1.3 billion of debt, which took our year-end balance sheet debt to $19.7 billion.

And as Ryan just mentioned, we also front-end loaded our 2018 debt reduction, paying down a further $2.25 billion in January.

Today, our debt is about $17.5 billion.

In the fourth quarter, we repurchased $1 billion of stock and completed our 2017 buyback target of $3 billion.

And finally, we've been evaluating the recent U.S. tax legislation and its overall impacts to the company.

As you've seen in our news release, we recognized a noncash benefit of approximately $850 million, primarily associated with revaluation of our U.S. deferred taxes to the lower rate.

We'll also see an improvement in our earnings going forward because of the lower effective tax rate.

With Lower 48 unconventionals and Alaska development being core to our capital program, the lower U.S. tax rate and enhanced capital recovery will further enhance the attractiveness of those investment programs.

So as an active finish to 2017 and we're entering 2018 with the same strong conviction about our value proposition.

If you turn to slide 6, I'll cover adjusted earnings for the fourth quarter.

2017 full-year adjusted earnings were about $740 million.

This was an increase of around $4 billion compared to 2016.

Fourth-quarter adjusted earnings were $540 million or $0.45 a share.

Compared to the prior quarter, this was an improvement of about $350 million due to higher price realizations and higher volumes, partly offset by higher operating costs.

Compared to the fourth quarter of last year, adjusted earnings improved by about $850 million, driven by higher commodity prices, higher underlying production and lower depreciation expense.

Fourth-quarter adjusted earnings by segment are shown on the lower right.

The supplemental data on our website provides additional financial detail on our segments.

If you turn now to slide 7, I'll cover cash flow during the quarter.

First, looking at the sources of cash shown in green.

Cash from operations, excluding working capital, was $2.5 billion.

This includes a benefit of about $300 million associated with the Ecuador arbitration.

Excluding this benefit, we were right in line with our published sensitivities.

The uses of cash are shown in red and we've already covered the debt reduction.

On capital, I want to note that the $1.5 billion included about $230 million in land acquisition costs, which Al will cover in a few minutes.

We also distributed $1.3 billion to shareholders through dividends and share buybacks.

We ended the quarter with $8.2 billion of cash and short-term investments, and we also hold 208 million shares of Cenovus.

Before leaving the quarter, I want to take a moment to make a few comments about realizations in the quarter and our leverage to price upside.

We're not certain that the market fully appreciates our differential exposure to Brent and similar premium markers.

Partly due to our global diversification and partly due to the pricing of our U.S. production, our realizations correlate much closer to Brent than they do WTI.

If we look at the fourth quarter, about 83 percent of our global oil production was priced either on a Brent basis or a premium marker that's closely correlated to Brent.

The evidence of that pricing advantage is shown in our crude oil realizations.

Brent increased by $9.30 a barrel from Q3 to Q4, and our U.S. oil realizations increased by slightly more, $9.50, whereas WTI weakened relative to Brent by over $2 a barrel.

You can see that we don't have the same exposure to relative WTI weakness that other E&Ps do.

So we're in a very strong financial position today with significant leverage to rising commodity prices.

We believe we have differential upside to prices because our portfolio is unhedged, heavily weighted to Brent and predominantly in tax and royalty regimes.

And we also benefit from contingent payments as a result of the recent transactions.

I want to leave the 2017 financial review with a slide that emphasizes our focus on free cash flow generation and on our disciplined priorities.

Slide 8 illustrates our priorities at work.

Starting with the first set of bars on the left, with Brent averaging just over $54 a barrel in 2017, we generated $7.1 billion of cash from operations, excluding working capital.

We spent $4.6 billion of capital, which resulted in $2.5 billion of free cash flow.

Our free cash flow generation power is a result of our low capital intensity, low sustaining price and leverage to price upside.

You either have these things or you don't.

And we do.

The second set of bars shows the significant progress we made on our balance sheet and distribution priorities in a short period of time.

In 2017, we generated $14 billion of cash and proceeds -- cash proceeds.

We used $11 billion of this cash to reduce debt and to fund buybacks.

So in the course of a year, our portfolio and balance sheet were significantly transformed, and our shareholders received more than 60 percent of cash from operations.

Lastly, a reminder.

We provided 2018 guidance as well as earnings and cash sensitivities in the appendix of the deck.

I want to draw your attention to two items that have positively impacted our income sensitivities.

First, our 2018 DD&A guidance of $5.8 billion has improved by $1 billion versus 2017 actuals.

The reduction is primarily the result of our 2017 dispositions and the reserve additions that Al will cover; second, our earnings sensitivities also reflect the benefits of the new lower U.S. income tax rate.

With that, I'll hand the call over to Al to discuss 2017 reserves and operational highlights.

Thanks, Don.

I'll begin on slide 10 with a review of our preliminary 2017 reserves.

Final reserve details will be published in our 10-K in late February.

We started the year with 6.4 billion barrels of reserves.

We sold 1.9 billion barrels of primarily North American gas and bitumen reserves in 2017.

Adjusted for dispositions, our pro-forma 2016 year-end reserves were 4.5 billion barrels.

We produced 518,000 barrels and booked additions of 605,000 barrels.

Excluding market factors, this represents a replacement rate from net additions of 117 percent, with an F&D cost of less than $9 a barrel.

In addition, market factors increased year-end reserves by 431 million barrels for a total reserves addition of over 1 billion barrels.

This equates to a 200 percent organic reserve replacement ratio, excluding disposition impacts.

We exited 2017 with over 5 billion barrels of high-quality reserves as part of our 15 billion barrel resource base that has an average cost of supply below $35 a barrel.

This was good performance in a year when we did not have additions from any major project sanctions.

If you turn to slide 11, I'll cover some 2017 highlights from our operations.

2017 was an exceptional year operationally.

We had our best year ever on safety and environmental performance while delivering 3 percent underlying production growth for $4.6 billion of capital.

So let me cover a few highlights.

In 2017, the Lower 48 Big 3 unconventionals hit an inflection point and began growing again.

In the fourth quarter of 2017, production from the Big 3 averaged 236,000 barrels per day, a 10 percent increase from the fourth quarter of 2016.

Also in the fourth quarter, we acquired about 245,000 net acres of unconventional exploration leases in 3 different early-stage Lower 48 plays for $235 million.

We're still coming -- we're still coring up these positions so we aren't going to say much more about them today.

I'm mentioning it partly to make a point that our fourth-quarter capex included this capital, so don't assume fourth-quarter capex represents a run rate for 2018.

Across the portfolio, we advanced several major projects, including Alaska's 1H NEWS that achieved first oil in November.

In Norway, the first Aasta Hansteen well was spud in November, and the spar will be towed offshore in the second quarter of 2018.

We're still on track to achieve first production before the end of the year.

We also advanced our exploration efforts in 2 exciting areas: Alaska and Canada.

We completed the preparatory and permitting work to drill five exploration wells in Alaska this winter.

In the Montney in Canada, we grew our 100 percent equity position in the liquids-rich part of the play to over 100,000 acres and achieved encouraging results in our early wells.

And finally, we announced a target to reduce greenhouse gas emissions intensity by 5 percent to 15 percent by 2030.

This is an important step in maintaining our ESG leadership.

So that was a very quick recap of 2017.

If you turn to slide 12, I'll cover the 2018 outlook, outlining some key catalysts to watch for in the coming year.

As Ryan said at the beginning of the call, we're committed to keeping our discipline.

We're sticking with the $5.5 billion capital plan we announced in November while keeping an eye on inflation and working hard to mitigate those pressures if they come.

We expect to deliver about 5 percent underlying production growth or over 10 percent on a per debt-adjusted share basis.

The bar on the right shows the basis for underlying target as well as the expected range for full year 2018 of 1,195 to 1,235 thousand barrels per day.

Some of you may have noticed that the midpoint of this range is 15,000 barrels per day higher than what we showed at our Analyst Day in November.

That increase accounts for the fact that underlying 2017 production was 15,000 barrels per day higher than we had assumed at the Analyst Day.

We expect first-quarter production to be between 1,180 and 1,220 thousand barrels per day.

I want to bring one item to your attention.

Early this year, a third-party pipeline outage in Malaysia caused the KBB field to be shut in.

In the first-quarter guidance range, we have assumed that KBB is offline for the remainder of the quarter.

KBB's net gas production was about 25,000 oil equivalent barrels per day prior to the shut-in.

But we're not adjusting our full-year production range for this outage.

A couple of quick comments on the production profile for the year.

We will have the usual second- and third-quarter turnarounds in APME, Europe and Alaska, so those segments will dip in the middle of the year and rebound in the fourth quarter.

Meanwhile, we expect our Lower 48 Big 3 volumes to ramp up to deliver the 22 percent production growth for this year that we showed you in November.

The capital and production guidance I just provided does not include the impact from the Alaska transaction that we announced this morning.

As you saw in the release, we paid $400 million to acquire the remaining 22 percent working interest in our Western North Slope assets that we already operate and the 1.2 million gross acres of exploration and development leases in the area, including the Willow discovery.

We now own 100 percent of these assets containing about 200 million barrels of gross reserves and about 900 million barrels of risked gross resource, with gross production of about 63,000 barrels per day in 2017.

We will begin reporting capital and production from this asset once we get regulatory approval.

2018 will be another busy year and there are some important milestones ahead.

Several projects are expected to come on line before the end of the year, including Bohai Phase 3 in China, Clair Ridge in the U.K., Aasta Hansteen in Norway and GMT-1 in Alaska.

We'll keep you informed on these throughout the year.

We also expect to enter FEED on the Darwin LNG backfill, which is an important step for production early next decade.

We have several exploration programs underway and look forward to progressing those in Montney, the Lower 48 and Alaska.

So to close, we remain focused on safely executing the discipline plan we laid out in November, delivering on our goals and keeping you informed during the year.

Now we'll turn the call over for Q&A.

(Operator Instructions) And our first question is from Doug Terreson of Evercore ISI.

So during the past year or so, ConocoPhillips and a few peers pledged to manage with value-based strategies and has returned and cash flow increased to return capital to shareholders.

And this model has clearly been rewarded differentially in the stock market.

And on this point, I noticed that your spending rose in Q4 and that you made a strategic acquisition in Alaska as well.

But based on Al's comments, it just sounds like we should consider these to be normal seasonal or maybe opportunistic type expenditures rather than an early-stage expansion of the spending program.

Is that the correct way to think about it?

Yes, Doug, I think that's exactly the right way to think about it.

We're sticking with our base program.

We had an opportunistic bolt-on opportunity in Alaska that we can talk more about if people have questions.

But really, that is a separate item from the base $5.5 billion plan that we have.

In terms of the 4Q spending, we had the $235 million of land acquisition that we talked about in the quarter.

And so that brought the fourth quarter in hot.

If you subtract -- back that out and take fourth quarter and multiply by 4, you get $5.1 billion.

So ex that, that was the pace we were on in the fourth quarter.

Yes, our discipline hasn't changed, Doug.

We're sticking -- as we said in our release, we're sticking to our $5.5 billion.

Our next question is from Neil Mehta of Goldman Sachs.

Ryan, I want you to talk a little bit about the Alaska opportunity set.

From conversations with investors, whether it's your existing portfolio or these bolt-ons or Willow, there's still a level of skepticism around the cost of supply of Alaska.

So can you talk about how you think about Alaska in the context of your cost of supply curve?

And then a little bit more detail about the asset that you built into the portfolio a little bit more today.

Yes, thanks, Neil.

Alaska has been one of our legacy areas for a long time for the company.

Similar to other parts of our portfolio, Alaska's made some tremendous progress in lowering the cost of supply for the base business up there as well as when we look at the opportunity set for investments to grow and develop.

So despite us being in Alaska for 40 years, the largest producer up there, we still see a lot of opportunity.

And in fact, our production is flat to growing over the next five to 10 years.

A lot of that's driven by things like the Willow discovery.

And when we look at that, it competes very well, and the portfolio sits at a cost of supply that is very competitive to investments around the world.

And we had an opportunity.

I think Anadarko was doing some things for their company to improve what they're doing.

They had listed or expressed a desire to sell some assets, and Alpine was one of those.

I think we're the natural buyer because we operate and we have the majority interest in the area.

So we were able to come to terms with them.

And we think it's attractive for both companies in terms of what they're -- what we're each trying to go do.

So make a heck of a lot of a sense to us to pick up that interest and be in complete control, 100% percent and control the capital pace and destiny over there.

So yes, it made a lot of sense for us and it was opportunistic so we took the chance and came to terms with them.

The follow-up is just the production guidance raise of 15,000 barrels a day.

It sounds like that's just rebasing off of a higher 2017 level.

Where was the outperformance was that Lower 48 and just any comments there?

Yes, so you're right.

That is just a rebase.

You'll see a -- there is a slide in the supplement that does the math for you.

But of that 15,000 increase, 14,000 of it was delayed timing on asset sales that we had assumed back at Analyst Day that were built in.

And so you just get a different base in the production that we had in '17.

And a little bit of it was a little bit higher performance that you saw in our fourth-quarter volumes were a little bit above what we'd assumed at the time of the Analyst Day.

But it's mainly just rebasing off that higher underlying production in 2017.

Our next question is from Phil Gresh of JPMorgan.

First question is just on the capital allocation.

This would be for Don.

So Don, at the Analyst Day, you guys were basing everything on a $50 WTI scenario.

Obviously, WTI's well above that now.

But even if you just went up, call it, $10 on that assumption, that'd be $2 billion or so more of CFO, and the amount of incremental buyback here is about $500 million.

So it seems like there's still a lot of extra cash available, particularly if you're not going to be increasing activity or CapEx.

So could you just talk about how you think about that flexibility and why the decision to raise $500 million versus a different number?

Well, Phil, I guess, maybe the important thing is to note that we're not going to get overly excited about the high commodity prices right now.

I think it's only been about 50 or 60 trading days since Brent broke $60 a barrel so there's a lot of volatility in the market as you've seen.

We're not changing our baseline.

Our plans are still based on the same plans that we showed you back in November with the $50 WTI type price.

And I think even there, we showed you that we had surplus cash built at the end of the -- over the 3-year period.

So we certainly had the capacity to increase the dividend as we announced this morning and also increase to 30 percent -- or have a 30 percent increase in our buybacks.

I would add, Phil, that we recognize there's some cash flow generation potential above and beyond what we were showing at the analyst meeting.

And I think we wanted to re-demonstrate our commitment to the shareholders up top.

So you've got the numbers right, $2 billion of incremental cash flow as you go from $50 to $60 in our company and the shareholders got the first column through the dividend increase and the incremental $500 million of share buybacks.

I just remind people, follow our priorities.

We were pretty clear as we outlined them and that's what we're doing.

Yes.

No, very fair about where we are in the year.

I guess just to clarify, there is no desire to put more cash on the balance sheet and reduce debt below $15 billion or anything like that, correct?

No, not really, Phil.

We're pretty clear on the $15 billion target by the end of 2019.

We do feel like that's the sweet spot.

When you start going lower than that, adjusting the capital structure, it really kind of becomes inefficient, I think, and also expensive.

So we're pretty happy with the $15 billion kind of strikes the right balance for us.

Okay.

And then my second question is just on the Lower 48.

If you could give the numbers for each of the three areas of unconventional.

And then as I look at that 2018 guidance of ramping through the year, does that mean the year will have greater than 20 percent growth or you're ramping to a level of 20 percent growth through the year?

I just want to clarify that.

Okay.

You're going to ask Paul's question there for the first piece which is the by field breakdown so he'll have to ask something different.

But so for fourth quarter, I mentioned the 236,000 for the Big 3 added together.

Eagle Ford's 148,000, Bakken is 67,000 and Delaware was 21,000.

So those together sequentially were up 25 over the third quarter or about 12 percent.

But that's not a very good number to just focus on because we had Harvey deficit in the third quarter.

But I think it is relevant to notice that it was up 10 percent quarter-over-quarter, fourth quarter of '17 versus '16.

In terms of your question about how we're going to move through this year, the 22 percent is a full year '18 number versus a full year '17 number.

That's what we were talking about at the Analyst Day.

The exit to exit will, of course, be higher than that.

In fact, I really expect, as I look at the timing and the shape of the curve and we're doing a lot of bigger pads now than we were, say, a year ago, more six and greater than six wells per pad that make the production lumpy.

And so I don't expect it to be ratable through the year.

But to give you an idea, I would expect our Big 3 to exit the year at over 300,000 barrels a day.

So if you kind of eyeball that with where we just were at 236,000 in the fourth quarter of last year, you can see kind of the pace that we'll be on even though I don't expect that to be linear through the year.

That kind of exit rate, you can do the math and see that we'll be -- if you look exit to exit, it's a considerably bigger number than 22 percent.

Great.

Why was Permian down in the quarter?

Permian, that's just lumpiness.

It's just the timing of -- as we're doing these multiwell pads and when the different wells, you have to -- when you're doing a multiwell pad, you've got to drill every one of those wells, and you got to come back through and complete every one of those wells before you turn any of those wells on and of course, your other wells are declining while you're doing that.

So it was down 1,000 barrel a day.

That's just this kind of lumpiness that you're going to see through the quarters that I'm talking about.

So when first quarter comes along, I don't expect to over-interpret how that's doing.

If you -- I know there's been a lot of -- in fact, one of the messages we've heard from investors and analysts since our Analyst Day is some doubt about this 22 percent number.

And I've been scratching my head trying to figure it out.

So I tried playing analyst for a day and looked back at things we've said before and did we give you some reason to doubt us?

I went back and looked at the transcript from this same call one year ago, the 4Q '16 call, to see what I said then.

And I said, I thought the fourth quarter of '17 would be 5 percent to 10 percent higher than the fourth quarter of '16 because we were going to go through a trough during '17 and then come up.

And in fact, we've hit the very high end of that range, 10 percent.

So that should give you confidence.

Then I went back and looked at the public data.

The public data that you can pull on Eagle Ford, Bakken and Delaware, and you can clearly see that the production rates, the per well production rates of our wells are considerably higher in '17 than they were in '16 and continue to improve significantly.

And so even our Dakota rig that's moved up that we showed you at AIM has gotten even better since then.

And so just -- I'm okay.

It's good for you guys to be skeptical so we can prove you wrong later in the year.

But there's just not any data out there that says we're not going to make it, so I feel confident.

Our next question is from Doug Leggate of Bank of America.

So Ryan, obviously, oil, where it's standing right now, I don't want to beat a dead horse here, but you know what's going to happen a year from now.

I could still hear people are going to be asking why you're not spending more money.

So I guess, can I ask you, maybe put you on the spot a little bit and see -- you laid out a three-year plan just two months ago.

Should we anticipate, given what Don said about his comfort with the balance sheet, that should we continue to have these kind of windfalls over the next two- or three-year period that, that would be an incremental share buyback?

And if I may, just bolt on the back end, where do acquisitions fit in, opportunistic or otherwise?

Well, I think Don said it.

There's 69 trading days since we broke $60, so I think we're not going to get out over our skis too much but we're going to follow the market.

And you should assume that our capital plan and the scope that we laid out and the plans that we laid out at the analyst meeting are pretty firm and disciplined within the company.

So we're not planning to change that scope.

So we're going to look at incremental opportunities as they become available, and that's exactly what we did on the Alaska opportunity.

And of course, the $400 million is included in that $5.5 billion.

So we recognize that as we execute our plans, you got to look at our priorities.

You got to think about how we're delivering money back to the shareholder, what we're putting back into the company and how we're growing and developing the company and use the priorities as your guide when you go do that.

If prices hang in there, we'll continue to evaluate as we go through the course of the year over the next two or three years, depending on what prices may do.

And if you follow our priorities, you'll see how we'll act.

My follow-up, I don't know if you'd be able to answer this or who would like to answer it.

But the $235 million land acquisition, I guess, is being described as an early-stage so it doesn't sound like it's Delaware.

Can you offer any kind of color as to what you're thinking there?

And as an add-on, this opportunistic word is probably going to get some attention because it seems there's a lot of asset holders around the place.

Whether it be Delaware.

Whether it be Eagle Ford or whatever.

There are likely to be asset sellers into this high oil price environment.

So do you have a scale of where opportunistic acquisitions has kind of a ceiling or will you look at everything?

Well, yes.

So the acreage acquisition is early-life exploration acreage in some unconventional plays around the U.S. We're still really actively trying to core that up, as Al talked about, so we're not talking about it because we're in the market today trying to build on some of those positions.

So we're just not going to speak to that today due to that.

On the opportunistic side, we look at a lot.

We look at a lot of assets.

We look at a lot of stuff on the M&A side.

And it's just got to make sense and be accretive in our portfolio and competitive on a full cycle basis.

So when we look at an acquisition, we have -- we don't just look at the forward kind of spend that we think is going to take and is that competitive.

We twoook at it on a full cycle basis, including what we have to pay for.

So some of the hot stuff in the Permian, Delaware Basin, it's expensive.

And while we look at it, it's just not competitive in the portfolio at $30,000 an acre.

But obviously, we're not -- and some of these opportunities that we're buying there, they're very competitive in the portfolio, make a lot of sense.

We're coring up existing positions that we have, and we look to do that more often if we've got opportunities to do that.

Right.

And we were able to do that for less than $1,000 an acre here when you divide the two numbers, obviously.

Yes.

So we're -- they make an incredible amount of sense for the long-term growth and development of the company.

I thought it was a stretch to get the location but we'll wait for that in the future.

It will come, Doug.

We're just -- we're out there competing and we want to maintain our competitive edge.

Our next question is from Paul Cheng of Barclays.

Maybe this is for Al.

Al, when looking at the U.S. onshore, the nominal cost is we are seeing some inflation.

But with your productivity gain, do you think that on a per unit basis that your unit cost, you will be able to hold flat?

Or that you're going to see maybe two or 3 percent increase?

Yes, so...

And then maybe also maybe -- I was going to say that you can also comment on international.

I think the spot cost is no longer dropping, but do you have any contract being rolled so that your international unit costs may actually be down?

Okay.

So you're really asking an inflation question, I guess.

Is that the main focus or were you interested in just Lower 48 onshore unit costs?

I'm not sure where your focus was.

It's a combination.

I mean, we know that inflation in the onshore, and I don't think we have seen any inflation in the international market.

But with your productivity gain and also project rollover, just trying to understand how that all wrap up in terms of your own 2018 versus 2017 unit cost as a result.

Right.

So I'll just remind us where we've kind of been with inflation, deflation.

When you look back for the full year 2017, when we do that math, it did end the year with some inflation in the Lower 48 and some deflation internationally.

And when we add all that up, it comes to a negative $29 million.

We -- so there's a slight net deflation, but you can -- so basically, about a wash.

But compare that to the past two years and in 2015, we had over $1 billion of deflation versus 2014.

And then even after that $1 billion, we had another $900 million of deflation in '16 versus '15.

So this was quite a change from the last two years to come out roughly even.

In '18, in our plan, we are assuming some level of inflation is built into that $5.5 billion.

But remember, as we said during the Analyst Day, that $5.5 billion was -- the amount of inflation we built into that was set for a $50 WTI world.

That's the inflation that we have built in there.

And you're talking about in the CapEx.

How about on the cash operating cost?

Okay.

Yes, so let me talk about our cash operating cost in '18 versus '17.

Basically, what we're doing is after you adjust out for dispositions, kind of one-time items and get to sort of our core pro forma operating cost in '17 and then take the unit cost of that with our volume, excluding Libya.

And then what we're doing is holding our unit costs flat in 2018 to what we accomplished in 2017.

What that means is that we're going to have to offset any inflation versus '17 forex pressures.

Libya has been producing more and more, and we're getting to where OpEx in Libya alone is rounding to $100 million.

It's getting to be significant.

And also we have a heavy turnaround year in '18 versus '17.

So all of those are putting pressure on our unit costs.

And our plan is to offset all of those things with greater efficiencies in '18 versus '17 to hold our overall worldwide unit costs flat.

Okay.

A quick follow-up -- actually not a follow-up but a question on Alaska bolt-on acquisition.

If I look at the price you pay, it seems like you pay for about $29,000 per daily barrel of production capacity or maybe about $9 per barrel after recoverable barrel if you were using $200 million gross.

Those seem very low number.

Is there any hidden cost in that that's why that Anadarko willing to sell at such a cheap price?

I'm trying to understand is there's any other things that we need to consider when we're looking at those number.

Those are great number.

Yes.

No, there's no hidden things in the deal.

What you see is what you get.

I think for us, clearly, this is a core strategic position for us in Alaska.

We've got a lot of confidence in our Alaskan operating and drilling and exploration teams and the things they're going to bring us on the Western North Slope going forward.

Willow is early evidence of that, but with that over a million acres up there, we've got a lot of prospectivity going forward.

Remember, I talked about our compressive seismic at Analyst Day.

We've got a compressive seismic shoot scheduled there this winter.

So there's a lot of interesting things that we see as upside that are core to us that, I think, for Anadarko, it just wasn't a core asset for them.

So just a little different view of the property.

Our next question is from Paul Sankey of Wolfe Research.

Al, did I hear you say in passing that in relation to this very strong reserves booking, you had no major project sanctions left here?

That's correct.

Yes.

So to come in over 100 percent, excluding the market factors in a year when we didn't have any major project sanctions, is good performance.

And it was really driven by the Lower 48.

I think that the improved recovery, just talking about how you go look in the public data and you'll see how much our wells have improved, particularly in the Eagle Ford since our latest completion design changes.

And that's not only given us higher rates, it's given us improved recoveries.

And so that -- combined with getting more mature in these Lower 48 unconventionals, so we've got more well history, allows us to book additional reserves.

And our continuing lowering of unit costs also takes out further in time the economic life of these wells and allows you to book a little more.

So those increased bookings in Lower 48 is really what allowed us to do that when you wouldn't have thought we'd been able to without any major project adds.

Yes, times have changed, Al.

The outlook for this year on sanctions or maybe for the next two or three, I guess, you may be able to give us just an update on if there is other stuff in the pipeline.

Yes, we kind of showed you that pipeline at the analyst meeting and it's pretty lumpy.

And so we will have some sanctions over the coming years, things like GMT-2 that we would expect for next year.

You've got the Darwin backfill that should come after that.

And so recall that what we said at the Analyst Meeting in November was that in any given year, when you don't have any of those, we might not make 100 percent.

But when you look at it, say, over the next five years and average out those lumpy major project adds, that we will -- we would expect to be over 100 percent.

In this case, I know we didn't have any.

We were over 100 percent for '17 anyhow.

Good, great.

Then if I could ask a follow-up.

I don't want to be negative but there are a few sort of ForEx and higher operate type effects in your OpEx cost gains, as I understood your commentary on that.

Could you just sort of try and give us a pro rata view of where you think that can get to, let's say, by 2019?

I hope that makes sense.

Do you think you can keep driving it down without all the moving parts for the somewhat macro-related, I guess?

Well, I mean, my expectation is that as we continue to grow our production, that we're going to maintain our unit costs flat.

And that as we experience ForEx pressures, inflationary pressures, that we're going to offset those with continued improved efficiency.

Our operating teams have demonstrated they're able to do that.

So I -- my expectation is that we continue to be able to do that.

The Libya thing is a little bit of a tough deal because we don't count the Libya barrels and the unit costs that I'm trying to hold flat.

But as they get bigger and bigger, Libya now is producing about 3 percent of our total corporate production.

But I'm not using the barrels in my unit cost calculation but I am including the cost in my costs.

So like I said, it's getting to be a tenth of a billion now.

And so it's -- we may have to think about how we're doing that calculation at some point.

But that's -- I don't see anything coming that's going to keep us from being able to continue to hold our unit production flat.

Our next question is from Alastair Syme of Citi.

I absolutely agree with Paul, the underlying movement in reserves is a pretty impressive achievement in 2017.

As the portfolio reshapes do you have a view on what would constitute an efficient reserve life for the business?

Or do you think it's even realistic or right to measure efficiency around reserve loss as a metric?

Well, I mean, I guess, if you look at our RP now with this latest, it's north of 10, 10, 11 kind of range.

We think that's a reasonable place to be, but it's not something we're aiming for one way or the other.

By selling some of our SAGD assets, that tends to shorten your RP because those were high RP assets.

A lot of what drives that is more mix of the kind of assets that we're developing.

So I think that we don't take any grand meaning from that particular number.

We're not trying to manage it in one direction or another.

Our next question is from Ryan Todd of Deutsche Bank.

Maybe a point of clarification on the corporate tax reform stuff.

Is there an impact to your effective tax rate?

And the -- is there a use of proceeds -- would you expect to repatriate foreign cash?

And if so, would that just go into the mix in the balance sheet or will there be any use of those proceeds?

Yes, Ryan, on the effective tax rate, sure, we'll see a lowering of the effective tax rate.

The U.S. effective tax rate will go down, what, 12, 14 percent or so.

And so on a global basis, that will probably push it down maybe 5 percent, I would say.

Would that have any impact in 2017 in your actual taxes, on your cash taxes paid?

Well, as you're -- you may recall, we're not in a taxpaying position in the U.S. and probably won't be until the early 2020s depending on price, of course.

So we're not going to see any cash impacts or very small cash impacts until we recapture those historic losses.

And then I think -- sorry, your other question was on the repatriation.

Right, well, there's two aspects of sort of repatriation of the cash.

We don't expect to do -- to see that.

We've always been able to access our foreign accounts without adverse tax consequences, so there's really no change there.

And then as far as the deemed repatriation on foreign earnings, of course, we'll -- we've got a lot of historic foreign earnings.

But -- and there'll be a deemed repatriation tax on that, but we have ample foreign tax credits to offset any impact that would have.

So the net-net result is no impact from deemed repatriation.

Okay.

That's great, Don.

Maybe can I just ask one on the Montney?

I mean, it's come up a few different times during the -- over the course of the presentation.

I know at the Analyst Day, you highlighted some of the incremental acres up there, over 100,000 acres.

Can you talk a little bit about what the plan looks like for the Montney over the course of this year?

I know that there's a spacing test going on in 2018.

What's the timing around that?

And maybe just general thoughts on what you're looking at in the Montney to accomplish this year.

Right, okay.

There's a lot of work going on there in '18 and '19 that I would characterize as appraisal work.

The problem with these Montney wells is they're so great that if you want to do a spacing and stacking test where you have a handful of wells, you've got to build quite a bit of infrastructure just to handle all the production that comes gushing out.

So to do a single pad spacing and stacking test, which is where we're headed, we have to -- we've got to build a gas plant.

We've got to build a crude condensate processing plant.

We've got to build a water treatment plant.

And it's about 35,000 barrels a day worth of capacity on an OEB basis, so about 110 million a day gas plant, that kind of thing, just to be able to handle the production from our appraisal testing.

So that's really what we're focused on.

We'll start construction of those facilities this year and finish the construction next year.

And so that'll get us into the next round of really solid data on Montney that will guide our development work.

So there'll be more to come on that.

Our next question is from Scott Hanold of RBC Capital Markets.

I was wondering, with APLNG and distributions, with where oil prices are, can you just talk through the process you and your partners are going to go through to decide if and when the timing is appropriate in 2018?

Sure, I can take that.

I think we mentioned last quarter that APLNG at that time was continuing to build cash balances, and they did through the quarter.

No distributions were made during the fourth quarter.

But I would say that at current prices, APLNG is in a position where they will consider distributions from the company.

And we would expect, if prices hold where they are, that we would have regular dividends through the year.

Okay.

And when would we get better visibility on the timing of that?

Is it this next quarter call or is this more of a back half of the year type of event?

I think we'll be prepared to discuss any action that's been taken at the next quarterly call.

Okay, appreciate that.

And my follow-up question.

Obviously, you guys are very well positioned, especially if these oil prices hold firm, to have a lot of extra free cash flow this year.

And it is a part of your priority obviously to invest organically at some point in time.

And could you discuss if, say, circa $60 oil prices are here to stay this year, where would be that first lever or two that you'd look to add some organic activity?

Well, Scott, we're staying on our plan.

So you can think about that on at least on a capital investment side independent of what happens this year on prices.

We set our scope and we're executing that scope this year.

Our next question is from Roger Read of Wells Fargo.

I was wondering, could we follow up a little bit on the Barossa field development in Australia, just kind of where that is?

There's been some chattering in the press about how that may move forward more aggressively here in '18, and whether or not that is accurate or how you're looking at it?

Yes, we -- I think I talked in the last call about the impressive results we got from latest appraisal at Barossa and the progress we've been making.

We're -- we've been in the marketplace, talking to the key contractors, getting ready to enter FEED, front-end engineering design, on the project.

And so I expect by the time we get to this next -- to our next call that we'll be -- we'll have entered or will be very close to it.

So we're getting close to that point.

And then, of course, we'll have to make our way through the FEED process.

But it's continued to move on track, on schedule.

Okay.

And then the unrelated kind of follow-up, a lot of talk about how to keep your OpEx on a per unit basis flat.

Let's leave maybe Libya out of it.

I'm just sort of curious, it's not like everybody hasn't been focused on cost the last couple of years.

What are the sort of identifiable, let's say, efficiencies or cost savings that you can pull out over the coming quarters and maybe next couple of years?

The -- what we have, every one of our business units in regions do, and as they've each got these kind of challenged processes going, you get different names for them in each of the different countries, but it's really a ground-up process where we have an organized way of people suggesting ways to save money.

And sometimes, these ideas are $20 million ideas and sometimes, they're $20,000 ideas.

And we've been scooping them all up, and it's a very ground-up organic process.

Data analytics has been a powerful force in helping us drive down our costs.

And so it's -- there's not some one silver bullet thing that's driven our costs down.

It's been thousands of small things adding up.

And we're continuing to drive -- you might have thought that it would have been a low-hanging fruit kind of process, and there was some of that.

But we found that it's -- that really we've built as soon is a sustainable process now in our operating units going forward.

And so I -- that's the tool that we're using to continue to offset the upward pressures.

I'd say in addition to the hard work of lowering costs that Al just referred to, we also, kind of going back to the Analyst Day when we talked about cash margin expansion of 5 percent annually over the next three years, we noted that the single-largest contributor to that was really the investments that we're making and where we're making them in places like Eagle Ford where the lifting costs are ultra low.

And so the investments that we're making this year, over the next few years are going into areas that are extremely accretive to our corporate unit costs.

And so there's also that investment effect as well.

Our next question is from John Herrlin of Societe Generale.

Two for Al.

Do you expect on this new shale acreage in the U.S. to core it up this year completely?

Yes, I think so.

I mean, I think it's a fairly near-term sort of process.

I think that's right, this year.

Okay, that's fine.

Next one, could you give the percentage -- I know you don't have your supplemental disclosures out, but what was the percentage of your proven reserves that were put as a percentage of total?

Yes, we'll have to follow up with you on that, give you those detailed numbers.

And our last question is from Blake Fernandez of Howard Weil.

Al, just in listening to you put your analyst hat on, it made me realize you'd be quite the sell-side analyst but trust me, you ought to stay in the corporate side.

I wanted to ask a couple of Don, if I could.

Just on the DD&A.

Based on our numbers, that's going to add just under $1 a share to EPS.

And I guess I was surprised at the magnitude.

I think we had $7 billion post-asset sales previously.

So it seems to us like the whole move, I guess, would have just been reserve revisions but could you just kind of elaborate on that?

No, that's really it.

It's the improvement in the reserves primarily in the Lower 48.

Okay.

And then on the deferred tax, too, I just wanted to confirm.

The revaluation, the negative $900 million or so, it seems like that's fully aligned with basically the revaluation you took on U.S. tax reform.

So I just wanted to kind of confirm going forward like that's a one-time event, and going forward, you'd expect that to be either flat or positive, is that the right way to kind of think about that?

Yes, the tax reform and the deferred tax revaluation is -- was a one-time event.

I say one-time, but the SEC has given companies the ability to make adjustments to those provisional numbers because they realize the amount of work that it takes to revalue a company's assets and liabilities.

So there might be minor tweaks as we go through the year.

But that's not really the point.

So if you strip that effect out of the fourth quarter, then you'd see deferred tax be, I believe, a source of maybe $50 million in round terms, a slight source.

So it's basically balanced and kind of a wash.

So we expect that to -- that's about where we would expect it to be.

I will now turn the call back over to Ellen DeSanctis, VP, Investor Relations & Communications, for closing remarks.

Thanks, Christine, and thanks to all of our listeners.

We are obviously more than happy to answer any follow-up questions that you have.

Thank you for staying over a tiny bit.

And we really appreciate your time and interest.

Thanks again.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This document contains forward-looking statements.

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