Conoco Phillips (COP) — Q4 2017 Earnings Call Transcript

Thanks, 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 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. Finally, during this morning’s Q&A, just to be efficient with our time, we’re going to limit questions to one and a follow-up. And now I’m happy to turn the call over to Ryan Lance.

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 discipline and continuing to deliver our returns-focused value proposition. For ConocoPhillips, our value proposition is an approach to the E&P business that focuses on 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 above $60 per barrel like they are right now. The 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. The 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 but we’re also building on it. On slide number 4, 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 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. Excluding disposition impacts, we delivered organic reserve replacement of 200%. Our lower sustaining capital and our pure leading sustaining price enabled us to deliver top-tier free cash flow. At 2017 average prices of $54 per barrel, our cash flow from operations exceeded CapEx by $2.5 million. We returned to profitability with full-year adjusted earnings of more than $700 million. And more importantly, we are 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% to less than $20 billion and improved our credit rating. We returned 61% of our cash flow from operations to shareholders via our dividend and buybacks. Last year, we grew the dividend by 6% and repurchased $3 billion or about 5% of our shares. Underlying production grew on a per debt-adjusted share basis by 19%, 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. 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 fair to argue that 2017 was 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. So, the 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 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 are 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% increase in our quarterly dividend, and we are upsizing our plan for 2018 share repurchases by over 30% to $2 billion. By the way, this represents a total of $5 billion in buybacks when combined with our 2017 repurchases. We are on track to deliver 13% 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 for growth's sake. And we will 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 are 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 will discuss some of our financial highlights.

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. Finally, we have been evaluating the recent U.S. tax legislation and its overall impacts to the company. As you have seen in our news release, we recognized a noncash benefit of approximately $850 million, primarily associated with the 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, we are 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 more closely to Brent than they do to WTI. If we look at the fourth quarter, about 83% 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 $9.13 a barrel from Q3 to Q4, and our U.S. oil realizations increased by slightly more than $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 companies do. So, we are 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 intact in 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 on 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 in cash proceeds. We used $11 billion of this cash to reduce debt and fund buybacks. So, during the course of the year, our portfolio and balance sheet were significantly transformed, and our shareholders received more than 60% 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 is improved by $1 billion compared to 2017 actuals. The reduction is primarily the result of our 2017 dispositions and the reserve additions that Al will cover. Second, our 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 start with a review of our preliminary 2017 reserves. We'll provide final reserve details in our 10-K filing in late February. The year began with 6.4 billion barrels of reserves, and we sold 1.9 billion barrels of primarily North American gas and bitumen reserves in 2017. After accounting for these sales, our pro forma 2016 year-end reserves were 4.5 billion barrels. We produced 518,000 barrels and recorded additions of 605,000 barrels. Without considering market factors, this yields a replacement rate from net additions of 117%, with a finding and development cost of less than $9 per barrel. Additionally, market factors increased year-end reserves by 431 million barrels, leading to total reserves additions exceeding 1 billion barrels. This results in a 200% organic reserve replacement ratio when excluding the impacts of dispositions. We finished 2017 with over 5 billion barrels of high-quality reserves as part of our 15-billion-barrel resource base, which has an average supply cost below $35 per barrel. It was strong performance in a year without significant project sanctions. Now, if you look at some highlights from 2017 operations, it was an exceptional year for us. We achieved our best safety and environmental performance while delivering a 3% underlying production growth with $4.6 billion of capital. In 2017, the Lower 48 Big Three unconventionals began to grow again, with fourth-quarter production averaging 236,000 barrels per day, a 10% increase from the same quarter in 2016. During the fourth quarter, we also acquired approximately 245,000 net acres of unconventional exploration leases in three early-stage Lower 48 plays for $235 million. We are still in the process of evaluating these positions and will provide more details today. It's important to note that the capital expenditure in the fourth quarter included this investment, so do not expect this to represent a typical run rate for 2018. Across the portfolio, we've made progress on several major projects, including Alaska's 1H news, which achieved first oil in November. In Norway, the first Aasta Hansteen well was spud in November and will be towed offshore in the second quarter of 2018, with production expected before the year ends. We also advanced our exploration efforts in Alaska and Canada, completing preparatory and permitting work for five exploration wells in Alaska this winter, and increased our equity position in the liquids-rich part of Montney in Canada to over 100,000 acres, achieving positive results in our early wells. Lastly, we've targeted to reduce greenhouse gas emissions intensity by 5% to 15% by 2030, reinforcing our leadership in environmental, social, and governance practices. That sums up 2017. Looking ahead to 2018, we remain committed to our $5.5 billion capital plan, while being mindful of inflation and working diligently to mitigate any cost pressures. We anticipate about 5% underlying production growth, or over 10% on a debt-adjusted share basis. The expected production range for 2018 is between 1,195,000 and 1,235,000 barrels per day, reflecting an increase of 15,000 barrels per day from our Analyst Day projection due to the higher actual production in 2017. Our first-quarter production is projected to be between 1,180,000 and 1,220,000 barrels per day. I want to highlight that we have accounted for the KBB field being offline this quarter due to a third-party pipeline outage in Malaysia, which reduced net gas production by about 25,000 oil equivalent barrels per day prior to the shut in. However, we are not altering our full-year production range due to this outage. We will see the typical second and third-quarter turnarounds in APME, Europe, and Alaska, with production expected to rebound in the fourth quarter. We also expect the Lower 48 Big Three to ramp up to achieve the projected 22% production growth this year. The capital and production guidance provided excludes the impact of the Alaska transaction announced this morning, where we acquired the remaining 22% working interest in our Western North Slope assets and 1.2 million gross acres of exploration leases, including the Willow discovery, for $400 million. We now own 100% of these assets, containing around 200 million barrels of gross reserves and about 900 million barrels of risk gross resource, with previous production of roughly 63,000 barrels per day in 2017. We will report on the capital and production from this asset following regulatory approval. 2018 is set to be another active year with several projects coming online by year-end, including Bohai Phase 3 in China, Clair Ridge in the UK, Aasta Hansteen in Norway, and GMT1 in Alaska. We'll keep you updated on these throughout the year. Additionally, we expect to enter front-end engineering design for the Darwin LNG backfill, a critical step for production in the early next decade. We have multiple exploration programs in progress, particularly in Montney in the Lower 48 and Alaska. In conclusion, we are focused on executing our disciplined plan from November, achieving our objectives, and keeping you informed throughout the year. Now, let's open the call for Q&A.

During the past year or so, ConocoPhillips and a few peers pledged to manage with value-based strategies and as returns on cash flow increased to return capital to shareholders, and this model is clearly being rewarded differently in the stock market. And on this point, I noticed that your spending rose in Q4 and you made a strategic acquisition in Alaska as well, but based on Al's comment, it sounds like you 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 are sticking with our base program. We had an opportunistic bolton 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 Q4 spending, we had the $235 million of land acquisition that we talked about in the quarter. So, that brought the fourth quarter in hot; if you subtract that back out and take the fourth quarter and multiply by four you get $5.1 billion. So, excluding that, that was the pace we were on in the fourth quarter.

Our plan hasn’t changed, Doug; we're sticking, as we said in our release, we're sticking to our $5.5 billion.

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, there is still a level of skepticism around the cost to 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've built into the portfolio?

Thank you, Neil. Alaska has been a core part of our operations for many years, and like other areas, we have made significant strides in reducing supply costs in our base business there. Even after being in Alaska for forty years and being the largest producer in the region, we continue to see numerous opportunities for growth. Our production is expected to remain stable or even increase over the next five to ten years, largely due to developments like the willow discovery, which aligns well with our portfolio, offering competitive supply costs compared to global investments. Anadarko has been making moves to enhance their operations, including selling some assets, and we see ourselves as the natural buyer for Alpine given our existing operations and majority interest in that area. We successfully negotiated terms with them, which benefits both companies in achieving our respective goals. As a result, acquiring that interest allows us to have complete control and define the capital pace and direction in Alaska. It was an opportunistic decision that we believe made a lot of sense.

I appreciate the comments. The follow-up is just the production guidance raised by 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 any comments there?

Yeah. So, you're right. That is just a rebase. There is a slide in the supplement that does the math for you, but of that 15 increase, 14 of it was delayed timing on asset sales that we assumed back at Analyst Day that were built in. And so, you just get a different base in the production that we had in 2017 and a little bit of it was a little bit higher performance as you saw on our fourth quarter volumes that 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.

First question is just on capital allocation; this will be for Don. So, Don, at the analyst day, you guys were basing everything on the $50 WTI scenario. Obviously, WTI is well above that now. But even if you're just going up, call it $10 on that assumption, that the $2 billion or so more of CFO and the amount is incremental; buyback here is about $500 million. So, it seems like there is still a lot of extra cash available, particularly if you are 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?

I think it's important to emphasize that we are not overly enthusiastic about the current high commodity prices. It's only been about 50 or 60 trading days since Brent surpassed $60 a barrel, which shows there is significant market volatility. We are maintaining our baseline and our plans are still aligned with what we presented back in November, based on a $50 WTI price. Even then, we indicated that we expected to generate surplus cash by the end of the three-year period. Therefore, we have the ability to raise the dividend, as we announced this morning, and also implement a 30% 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 you at the analyst meeting, and I think we wanted to re-demonstrate our commitment to shareholders up top. So, you got the number right: $2 billion of incremental cash flow as you go from $50 to $60 in our company, and the shareholder got the first call on that through the dividend increase and the incremental $500 million of share buybacks. I'll just remind people to follow our priorities. We are pretty clear as we outline them, and that’s what we are doing.

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 are pretty clear on the $15 billion target by the end of 2019. We do feel like that’s the sweet spot; you start going lower than that and adjusting the capital structure; it really kind of becomes inefficient and also expensive. So, we are pretty happy with the $15, kind of strikes the right balance for us.

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 ramping through the year, does that mean that you will have greater than 20% growth or you are ramping to a level of 20% growth through the year? I just wanted to clarify that.

We are going to ask Paul about the by-field breakdown. For the first quarter, I mentioned that the combined volume for the big three was 236, with Eagle Ford at 148, Bakken at 67, and Delaware at 21. Together, these figures represent an increase of 25 compared to the third quarter, or about 12%. However, this number isn't very telling due to the Harvey impact in the third quarter. It’s also important to note that there was a 10% increase quarter-over-quarter from the fourth quarter of '17 to '16. Regarding your question about our progression this year, the 22% growth is for the entire year of '18 compared to '17, as we discussed during the Analyst Day. The exit-to-exit growth will be higher. I expect that due to our shift towards larger pads, averaging more than 6 wells per pad, production will be uneven throughout the year. However, I anticipate our Big Three will exit the year at over 300,000 barrels a day. If you compare that to the 236 we recorded in the fourth quarter of last year, it illustrates the pace we are aiming for, even if it won't be consistent throughout the year. If you do the calculations based on the exit rates, you can see it’s significantly higher than 22%.

Why was Permian down in the quarter?

Permian is experiencing some variability, primarily due to the timing of our multi-well pads. When we are drilling on a multi-well pad, every well must be completed before we can bring them online, and in the meantime, our existing wells are declining. As a result, we saw a decrease of 1,000 barrels a day, which is the type of variability we should expect during these quarters. As we enter the first quarter, I don’t want to overanalyze our performance. I understand there has been some skepticism regarding our 22% growth forecast, which we’ve heard from investors and analysts since our Analyst Day. I have been reflecting on this, considering whether we provided any reasons to doubt our projections. Looking back at last year’s fourth-quarter call, I mentioned that I expected our fourth quarter of ’17 to be 5% to 10% higher than that of ’16 due to a trough we anticipated in ’17 followed by a rebound. We actually reached the high end of that estimate at 10%, which should instill some confidence. Additionally, public data shows that production rates from our wells in the Eagle Ford, Bakken, and Delaware regions have significantly increased in ’17 compared to ’16 and continue to improve. Even our Dakota rig, which we showcased at AIM, has performed even better since then. It's healthy for you to be skeptical, as it gives us the opportunity to validate our projections later this year. However, there is no evidence suggesting that we won't achieve our goals, and I feel assured about our trajectory.

So, Ryan, obviously oil is 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 put you on the spot a little bit, and you led us through your plans just three months ago. Should we anticipate, given what Don said about his comfort with the balance sheet, should we continue to have these kinds of windfalls over the next two to three-year period but that would be an incremental share buyback? And if I may just go to the backend, where do acquisitions fit in opportunistically otherwise?

Well, I think Don said that there have been 69 trading days since we approached $60; so I think we are not going to get overly excited about these prices. We are going to follow the market, and you should assume that our capital plan and the scope that we laid out at the Analyst Meeting are pretty firm and disciplined within the company. So, we are not planning to change that scope. So, we will look at incremental opportunities as they become available, and that's exactly what we did with the Alaska opportunity. And of course, the $400 million isn't included in that $5.5 billion. So, we recognize that as we execute our plans, we need to think about how we are delivering money back to the shareholders, what we are putting back into the company and how we are growing and developing the company is the priority as you guide when you do that. With prices hanging where they are, we will 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 will see how we will act.

My follow-up? I don't know if you will be able to answer this or if you would really like to answer this, but the $235 million land acquisition has been described as an early stage, so it doesn't sound like it's Delaware. Can you offer any color as to what you are thinking there? Also, as an add-on, is this opportunistic or is this probably going to get some attention because it seems there are a lot of asset holders around the place, whether it be Delaware, Eagle Ford, or whatever; they are likely to be asset sellers in this higher oil price environment? So, do you have a scale of where opportunistic acquisitions have a kind of ceiling, or do you look at everything?

The acreage acquisition is early-stage exploration land in various unconventional plays across the U.S. We are actively working to build on these positions. However, we're not going to discuss specifics at this time. On the opportunistic side, we evaluate many assets and M&A opportunities, ensuring they make sense and enhance our portfolio while remaining competitive overall. When considering an acquisition, we assess both the immediate and long-term costs, including the purchase price. While some high-demand areas like the Permian Delaware basin are costly and not competitive for us at $30,000 an acre, there are other opportunities we are pursuing that align well with our portfolio and make strategic sense.

Right, we are able to do that if it's less than $1,000 an acre here when you divide the two numbers obviously.

Yeah, so they made an incremental amount of sense for the long-term growth and development of the company.

I probably just stretched to get the location but we will wait for that in the future. Thanks, guys.

It will come, Doug; we are out there competing, and we want to maintain our competitive advantage.

Hey, guys, good morning.

Good morning, Paul.

Good morning, Paul.

Maybe this is for Al. Al when we are looking at the U.S. onshore, the nominal pause is that we are seeing some inflation, but with the productivity gain, do you think that on a per unit basis that your unit costs you will be able to operate or that you are going to see maybe a 2% or 3% increase?

Yeah. So…

And you can also maybe…

You are specifically asking about…

I was going to say, you can also comment on international; I think the spot cost is no longer dropping, but do you have any contract that is being rolled so that your international unit cost may actually be down?

Right. So, you are really asking an inflation question, I guess. Is that the main focus or are you interested in just Lower 48 onshore costs? I'm not sure where your focus was.

Yes, the combination. I mean we know that inflation in the onshore and I don't think we've seen any inflation in the international market, but…

Right. Okay.

But the productivity gain and also project overall just trying to understand how that all ramps up in terms of your own 2018 versus 2017 unit costs as a result?

To summarize our recent history with inflation and deflation, looking back at 2017, we recorded some inflation in the Lower 48 and some deflation internationally, resulting in a net decline of $29 million. While this was a slight net deflation, it was relatively even when compared to the previous two years, where in 2015 we experienced over $1 billion in deflation compared to 2014. Following that, in 2016, we saw an additional $900 million in deflation versus 2015. This marks a significant change from the last two years to have an overall neutral situation. In our 2018 plans, we anticipate some level of inflation included in the projected $5.5 billion, which was initially based on a $50 WTI scenario.

And you are talking about CapEx side but on the cash operating costs?

Okay. So, let me talk about our cash operating costs in 2018 versus 2017. 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 costs in 2017, then take the unit costs of that with our volume excluding Libya, what we've done is hold our unit costs flat in 2018 to what we've accomplished in 2017. What that means is that we're going to have to offset any inflation versus 2017 ForEx pressures. Libya has been producing more and more, and we're getting to where OpEx in Libya is alone rounding to a tenth of $1 billion; it's getting to be significant, and also, we have a heavy turnaround year in 2018 versus 2017. All of those are putting pressure on our unit costs and our plan is to offset all of those things with greater efficiencies in 2018 versus 2017 to hold our overall worldwide unit costs flat.

Okay. A quick follow-up, actually, no follow-up but a question on Alaska, the bolt-on acquisition; if I look at the price you pay, it seems like you paid for about $29,000 for daily production capacity or maybe about $9 per barrel of the recovered book barrel if we are using 200 million gross. Those seem very low number. Is this any hidden cost in that that's why that Anadarko is willing to sell at such a cheap price? I am trying to understand, is there any other thing that we need to consider when we are looking at those numbers? Those are great numbers.

No, there are 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 have got a lot of technical capabilities in drilling and exploration teams, and we believe that this Western North Slope will lead us forward. Willow was early evidence of that, but with that over 1 million acres out there, we have got a lot of prospectivity going forward. Remember I talked about the compressive seismic at the analyst day; we have got a compressive seismic shoot scheduled there this winter. So, there are a lot of interesting things that we see as upside that are core to us. I think for Anadarko, it just wasn't a core asset for them; so, it's just a little different view of the property.

Al, did I hear you say regarding the very strong reserves booking, you had no major project expansions last year?

That's correct, yes. So, to come in over 100% excluding the market factors in a year when we didn't have any major projects sanctioned is a good performance. And it was really driven by the Lower 48. I think that the improved recoveries just talking about you go look in the public data and you will 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 that combined with getting more mature on these Lower 48 unconventionals so we have 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 would have been able to without any major project adds.

Yes, times have changed Al. So, the outlook for the CRMs of sanctioned maybe for the next two to three, I guess you may be able to give us just an update on if there is other stuff in the pipeline?

We presented the pipeline during the analyst meeting, which is quite variable. We anticipate some sanctions in the coming years, including GMT2 expected next year, followed by the Darwin backfill. Recall that during the analyst meeting in November, we mentioned that in any given year without those projects, we might not reach 100%. However, when you look at the next five years and average out the significant project additions, we expect to exceed 100%. In fact, we were over 100% for 2017 regardless.

And then if I could ask you a follow up. I don't want to be negative, but there are fears of forEx and higher oil price type effects in your OpEx cost gains if 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? I mean you can keep driving it down without all the moving parts for the somewhat micro relative, I guess.

My expectation is that as we continue to grow our production, we will maintain our unit costs flat despite facing foreign exchange and inflationary pressures. We plan to offset these challenges with improved efficiency, which our operating teams have consistently demonstrated. I believe we can keep achieving this. The situation in Libya is a bit complex since we do not factor in the barrels from Libya when calculating the unit costs we aim to maintain. However, as Libya's production increases—it currently accounts for about 3% of our total production—I need to consider how to handle these costs, which are now approaching a significant amount. Despite this, I don't foresee any obstacles that would prevent us from keeping our unit production costs stable.

I absolutely agree with Paul; the underlying movement in reserves is a pretty impressive achievement in 2017. As the post, did 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 to 11 kind of range. We think that's a reasonable place to be, but it's not something we are 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 are developing. So, I think that we don't take any grand meaning from that particular number; we are not trying to manage it in one direction or another.

Maybe a point of clarification on the corporate tax reform stuff. Is there an impact to your effective tax rate, and is there use of the proceeds? Would you expect to repatriate foreign cash, and if so, will that just go into the mix in the balance sheet or whether there had to be any use of those proceeds?

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 about 12% to 14% or so. So, on a global basis that will probably push it down maybe 5% I would say.

Will that have any impact in 2017 on your actual taxes?

Well, as you may recall, we are not in a tax paying position in the U.S. and probably won't be until early 2020, so it's dependent on price of course. So, we are not going to see any cash impacts or very small cash impacts until we recapture those historic losses.

And then…

Sorry, the other question was on…

Repatriated cash?

Regarding repatriation, there are two main points to consider. We do not anticipate any changes in our ability to access our foreign accounts without incurring adverse tax consequences. Additionally, while we have substantial historic foreign earnings that will be subject to deemed repatriation tax, we have sufficient foreign tax credits to mitigate any potential impact. Therefore, the overall outcome is that there will be no effect from deemed repatriation.

Can you provide an update on the Montney? It has been mentioned several times during the presentation. I recall that at the analyst day, you pointed out some additional acres, over 100,000. What is the plan for the Montney this year? I understand there is a spacing test happening in 2018. What is the timing for that? Additionally, could you share your general thoughts on your objectives for the Montney this year?

There is a lot of work happening in 2018 and 2019 that I would describe as appraisal work. The challenge with these Montney wells is their high productivity; if we want to conduct a spacing and stacking test with a few wells, we need to construct significant infrastructure to manage the substantial production. To undertake a single pad spacing and stacking test, which is our direction, we need to build a gas plant, a crude condensate processing plant, and a water treatment plant. This involves about 35,000 barrels per day of capacity on an OEB basis, which translates to around a 110 million a day gas plant. This infrastructure is necessary to support the production from our appraisal testing. Our focus is on starting the construction of these facilities this year and completing them next year. This will provide us with valuable data on Montney that will inform our development work moving forward, so expect more updates on that.

I was wondering with APLNG in distribution, 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 address that. We noted last quarter that APLNG was building cash balances, and this continued through their quarter without any distributions in the fourth quarter. However, given the current prices, APLNG is now in a position to consider distributions from the company. If prices remain stable, we anticipate regular dividends throughout the year.

And when would we get better visibility on the timing of that? Is it the 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. I appreciate that. And my follow-up question. Obviously, you guys are pretty well positioned, especially if these oil prices hold firm, to have a lot of extra free cash flow this year. And it is a prior year priority obviously to invest organically at some point in time. Could you discuss, if say, circa $60 oil prices are here to stay this year, where would be that first lever as you look to add some organic activity?

Well, Scott, we're staying on our plan. So, you can think about that 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.

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

I mentioned in the last call the impressive results from the latest appraisal at Barossa and the progress we've made. We're engaging with key contractors and preparing to start the front-end engineering design for the project. I expect that by our next call, we will have either started or be very close to starting this phase, so we're approaching that milestone. Additionally, we will need to navigate through the FEED process, but everything is progressing on track and on schedule.

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 maybe leave Libya out of it. I'm just sort of curious; it's not like everybody hasn't been focused on costs 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?

Yes. What we have in every one of our business units and regions doing is they've each got these kind of challenge processes going; they have got 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 that is our $20 million ideas and sometimes, they're $20,000 ideas. We've been scooping them all up, and it's a very ground-up organic process. Data analytics has been a powerful force and helped us drive down our costs. And so, there's not some silver bullet thing that's driven our costs down; it's been thousands of small things adding up, and we're continuing to track. 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 we've built as soon as a sustainable process in our operating units going forward. So that's the tool that we are using to continue to offset the upward pressures.

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% annually over the next three years, we noted that the single largest contributor to that was really the investments we are making and where we are making them in places like Eagle Ford, where the lifting costs are ultra-low. And so, the investments that we are making this year over the next three years are going into areas that are extremely accretive to our corporate unit cost. And so, there's also that investment effect as well.

Two for Al. Do you expect on this new shale acreage in the U.S. to clear it up this year completely?

Yes, I think so. I mean I think it's a fairly near-term sort of process. So, I think that's right this year.

Could you provide the percentage of your proven reserves in relation to the total?

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

Al, I have been listening to you and it made me realize that you would excel as a sell-side analyst; however, you belong on the corporate side.

It's always good to have a backup plan.

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 by 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. Could you just elaborate on that?

No, that's really it; it's the improvement in the reserves primarily in the Lower 48.

And then on the deferred tax, I just wanted to confirm the revaluation; the negative $900 million or so seems like that's fully aligned with basically the revaluation you took on U.S. tax reform. So, I just wanted to confirm going forward like that's a one-time event, going forward do you expect that to be either flatter or positive? Is that the right way to think about that?

Yes, the tax reform and the deferred tax revaluation was a one-time event; I would say one-time, but the SEC has given companies the ability to make adjustments to those provisional numbers because they realized the amount of work it takes to revalue company 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 would say deferred tax would be a source of maybe $50 million in round terms; slight sources, so it’s basically balanced and kind of a wash.

Okay.

So, we would expect that to be about where we anticipate it will be.

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 time a bit, and we really appreciate your time and interest. Thanks again.