Occidental Petroleum Corporation
Q4 2016 Earnings Call Transcript

Published: 9 Feb 2017

[Operator:]

Good morning and welcome to the Occidental Petroleum Corporation's fourth quarter 2016 earnings conference call. Please note, this event is being recorded. I would now like to turn the conference over to Chris Degner. Please go ahead.

[Christopher M. Degner:]

Thank you, Kate. Good morning, everyone, and thank you for participating in Occidental Petroleum's fourth quarter 2016 conference call. On the call with us today are

[Vicki A. Hollub:]

Thank you, Chris, and good morning, everyone. Today we'll provide you a summary of our 2016 results, a high-level preview of 2017, and a more detailed update of our Permian inventory. But the key message I'd like to convey is that we will continue to provide value to our shareholders through an attractive dividend and an ability to grow our cash flow and earnings through moderate production growth while maintaining a strong balance sheet. This has been our strategy for a long time and it has not changed. What has changed is that we have dramatically derisked the delivery of that value proposition. The quality of our portfolio today enables us to achieve our corporate goals through organic growth. Our exit from non-core areas along with proving up our Permian Resources inventory provides us with a good blend of low-decline long-term cash flow generating assets that are important to support our dividends, along with significant short-cycle growth opportunities. We can now provide all of our targeted cash flow and earnings growth through organic development. In fact, Permian Resources can do it alone. From 2013 to 2016, we've doubled Permian Resources production. We can more than double it again over the next four years in a moderate commodity price environment. We can do this because we are a more geographically-focused company today. This focus has led to technical and operational improvements in all of our core areas. We have long been recognized as a global leader in enhanced recovery technology. As shown on slides 6 through 8, with our more focused approach, we have built on our historical successes and are achieving even greater success today in our core international operations. A recent example is the Al Hosn gas team, who increased the rated capacity of the gas plant to 110% of its original nameplate. We have now achieved the same level of success in our unconventional operations in the Permian. In late 2013, we began the transformation of our unconventional business by restructuring into smaller strategic teams with greater emphasis on subsurface technical excellence and operational execution efficiency. This has paid off as we executed an aggressive appraisal program in 2014 followed by focused development plans in 2015 and 2016. Our expanded subsurface expertise along with our innovative drilling and completion practices has resulted in step-change improvements in our unconventional operations. We can now generate play-leading returns that are robust, even with lower oil prices. Jody will provide more detail on our Permian business. As excited as we are about Permian Resources, the powerful combination of our long-term resource potential, our technical capability, and our partner relationships is even more compelling. The Permian, our Middle East countries, and Colombia all have one thing in common. They have significant remaining resource potential waiting to be unlocked by our technical expertise, from primary to secondary to tertiary recovery. Unlike some of our competition, we don't have to look elsewhere for opportunities, and we believe the Middle East and the Permian will continue to play a critical role in supplying the energy needed to meet the world's ever-increasing needs. We are unique in providing this opportunity to investors. In 2016, our oil and gas operations continued to lower total cost structure and increase recoveries from our reservoirs. You'll see the impact of this later in our reserve statistics. Slides 10 through 12 show highlights of key 2016 accomplishments in all of our areas. I won't read them all, but I would like to point out that we ended 2016 with $2.2 billion in cash, and we were able to achieve the higher end of our production guidance with less capital than expected. This is due to our capital execution efficiencies and is reflected in our F&D costs. We replaced nearly 190% of our production at a cost of $9.65 per BOE. As a result, our total proved reserves increased from 2.2 billion BOE to 2.4 billion BOE, mostly due to Al Hosn and Permian Resources. Al Hosn reserves increased due to better than expected reservoir performance. The increased reserves in Permian Resources were driven by a successful development program and higher well productivity. Based on our Permian Resources current inventory of 11,650 wells, we'll be able to continue to replace reserves for the foreseeable future. Our current proved reserves are limited only by the five-year SEC rule. Last year's drilling program in Permian Resources delivered strong reserve replacement at an F&D cost of less than $9 per BOE. When combined with our total cash costs of approximately $11 per BOE, an incremental dollar investment in our Permian Resources business delivers pre-tax margins in excess of 50% at $55 WTI. As we go into 2017, we have more confidence in the stability of the oil markets and increased flexibility in our capital plan, as we have completed most of our multiyear investment programs. We are encouraged by the recent OPEC decision to lower production quotas, and we've seen the read-through in our operations and an increased demand for our crude in international markets. Our capital plan will prepare the business for an improved commodity price environment heading into 2018 while maintaining the flexibility to adjust activity if market conditions warrant. We'll continue improving our operational and technical excellence to further reduce our cost structure and improve recoveries. Based on our available cash and market conditions, we'll execute a capital plan of between $3 billion and $3.6 billion in 2017. In addition to cash flow from operations, our capital program will be supported by cash flow from a sizable tax refund and the monetization of non-core assets. We're reducing capital in Permian EOR and Chemicals while holding capital flat in the Middle East and Midstream. We'll increase capital moderately in Colombia and significantly in Permian Resources. Our plan anticipates oil prices to remain approximately as reflected in the futures markets. In the Permian Basin, the increase in capital spending will be mostly directed to increased activity in southeast New Mexico and the Greater Barilla Draw area. As I mentioned previously, the short-cycle nature of our development programs provide us the flexibility necessary in an uncertain market environment. If we see declines in oil prices, we will adjust our capital program down. With increased spending in our oil and gas business, we expect production from our core assets to grow 4% to 7% in 2017 adjusted for production-sharing contract effects. Most of the increase in production will be driven by Permian Resources. In closing, I'd like to reiterate that our cash flow priorities have not changed. Our top priority for cash flow is and always will be the safety of our employees, contractors, and public along with the maintenance of our operations. The next priority is to support the growth of our dividend. Any remaining available cash will be used to fund growth opportunities, primarily through organic growth and Permian Resources. All of our decisions are driven by a focus on returns and our strategy to continue to grow the dividend over the long term. As you know, this puts us in a unique position in the industry. We are more similar to majors with respect to our dividend, cash flow, and balance sheet objectives. But unlike majors, we have a greater growth potential because we have an incredible portfolio. To maximize the value of this unique position, we must be technically excellent and have a high level of operational efficiency. Focus will do this for us, allowing us to widen our competitive advantage. And, we'll continue to make deliberate decisions with respect to capital allocation. Keeping our capital allocation decisions consistent with our long-term strategy we believe will result in increased stock market value. Now I'll turn the call to Chris Stavros for a review of our financial results.

[Christopher G. Stavros:]

Thanks, Vicki, and good morning everyone. Today I'll focus on the following items

[Joseph C. Elliott:]

Thank you, Chris, and good morning, everyone. During 2016 we asked our teams to outperform many demanding operational and financial targets. Our teams rose to the occasion and exceeded our expectations during an extremely challenging time in our industry's history. Our team showed their resolve and ingenuity by staying focused on the priority needs of the business while developing new ideas and innovative technologies. In particular, I'd like to acknowledge our field employees, who maintained a safe and productive environment every day across our operational locations. Our four main accomplishments in the Permian Basin during 2016 were

[Christopher M. Degner:]

Thank you, Jody. We will now open up the call for questions.

[Operator:]

The first question comes from Evan Calio of Morgan Stanley. Please go ahead.

[Evan Calio:]

Good morning, everybody, and thanks a lot for the new disclosure this morning. My question is your relative capital allocation in 2017, it's increasing for the Permian Resources up to the mid-30s following these positive well results and inventory update. That appears to be a shift in the strategy towards the Permian. So how should we think about relative capital allocation within this growth bucket? Is it the high end of your Permian guidance, the first call on incremental capital above the dividend and maintenance? And would asset sales like those mentioned in Chris's opening comments, would that drive activity upside in 2017 on the strip, or how do you plan that?

[Vicki A. Hollub:]

Thanks, Evan. First of all, going back to our cash flow priorities, when we're looking at the use of cash flow from operations, as I said in my script, we first allocate to our maintenance capital, our HES [Health, Environment, Safety] safety and sustainability capital. Then we fund the dividend. Beyond that, what we consider the growth capital, to allocate that, what we really look at is the combination of what it can provide for us in terms of returns, and also what it does for us in terms of long-term cash flow. So when we make the allocation decisions, it's a combination of those two that we need to support our objectives and to continue to support the dividend. But within the portfolio now in terms of what we see in the Permian Resources business, that has been and will continue to be generally our highest return business. And we had this past year – it was really a focus for us. We've said for a long time that the Permian Basin is pretty much the foundation of our company, and so Permian Resources is the main growth engine. However, as you can see from the slide 23, of our free cash flow swing in 2017, $400 million we're expecting to come from our international operations. And of that $400 million, about two-thirds of that will come from our Block 9 contract, which we re-signed last month. So the rest will come from Colombia and Al Hosn. So it's critically important for us to continue to work on growing our cash flow while at the same time ensuring that we invest as much as we can in the Permian Resources business, which for now for us is generating really good returns.

[Evan Calio:]

Maybe just a point of clarification, does the asset sales that were mentioned earlier, do asset sales then drive upside to what you've provided in the guidance today?

[Vicki A. Hollub:]

Today's guidance was based on the liquidity that we expect to have available to us for 2017. So we don't expect any increase in our capital spend for 2017. We expect $3.6 billion to be the upper end. We'll go into 2018 with what we believe is a pretty strong cash balance, and we'll plan accordingly for increases in capital in 2018 should the market conditions warrant. So what we will look at is we'll look at the prices for not only oil, but in our Chemicals business, and we'll see what the market conditions look like.

[Evan Calio:]

Great, my second question, if I could. If we go to the new updated inventory data, can you provide color on what – I think you did in some of your prepared comments, but color on what the 300,000 acres that the location count is based upon represents? Meaning I just want to understand potential location upside from what's been analyzed and understand better your cash priority statement that includes acquisitions, if that reflects a desire to add acreage in the Permian.

[Vicki A. Hollub:]

Okay, we'll let Jody answer the first part of that.

[Joseph C. Elliott:]

Evan, good morning. The 300,000 acres, I think the way to think about that is it's really development-ready. We've been through that appraisal, subsurface evaluation, infrastructure investment, precursor to getting it to our development team. So that's the 300,000. The difference between that and the 650,000 is that's now in the appraisal queue, being worked. A lot of that is being derisked by competitor activity and our OBO [Operated by Others] activity. So that's the difference between the 300,000 and the 650,000 acres.

[Vicki A. Hollub:]

And, Evan, with respect to the monetization of assets, we're continually looking at opportunities too in our portfolio and prioritizing the projects that we have, and we'll always do that. And there may be opportunities down the road where we may find things that would be better monetized today rather than waiting on development. The issue in the Permian Basin is that everywhere we look, as we look deeper, we find more opportunities. So the Permian is a place where we think that it's first of all very difficult to drill a dry hole there. Secondly, the more you learn about it and the more you engineer it, the better your wells get. And so we value that portfolio, but we're still very conscious of the fact that we need to optimize the net present value. So we'll continually look at that. It's this process that we've gone through that's driven us to exit the non-core areas that we've exited in the last couple years. So we'll continue that process.

[Evan Calio:]

Great, I'll leave it there. Thank you.

[Operator:]

The next question is from Ed Westlake of Credit Suisse. Please go ahead. Mr. Westlake, your line is open. Next we have Roger Read of Wells Fargo.

[Roger D. Read:]

Good morning. Thank you. I'll take Ed's question for him. Actually, we could go back to the discussion, Jody, at the end there, the 2,500 locations, and then I guess the discussion of the 650,000 acres. What should we think of as the key items that get analyzed and changed such that you are able to double the number of locations and then think about and increase the number of below-$50 breakeven locations going forward? What are the critical path items we should be paying attention to here?

[Joseph C. Elliott:]

Roger, for us it's really probably two things. It's better execution efficiency. So we're drilling more wells with the same number of rigs at a lower cost. So our time to market is faster. That changes your economics. The other is subsurface characterization combined with stimulation design. So we're landing our wells in places that we believe give us the highest stimulated rock volume. We're staying in zone at a much, much higher percentage through our drilling technologies. And our stimulation designs, in general you're seeing larger, per-sand volumes tighter cluster spacing. But those are really custom designed by each area. So that's really created a lot of the increase as well as we continue to appraise and derisk new acreage. The 2,500 locations below $50, I would think that's a pretty conservative number given that our approach to spacing we think about in that capital-efficient return-based approach. We don't want to overcapitalize these assets, and so we look hard at what spacing ought to be. We evaluate that. We test different spacing scenarios, and then continue to look at spacing scenarios from our OBO exposure and learn from those as well.

[Roger D. Read:]

Thanks. And then along those lines, as we think about on slide 34 the nine-rig baseline of 20% CAGR and the higher rig count for 30%, does that require those 2,500 well sites going up, or is it an oil price-driven event? Or maybe another way of thinking about it, if all these efficiencies come through maybe quicker than you think, do we get 15 rigs and a 30% CAGR, even if crude stays, say, $50 to $55, where it's been here year to date?

[Joseph C. Elliott:]

Roger, there's plenty of inventory. That projection of the 20% and 30% CAGR is from those core development areas. So there's over 14 years of rig activity if you were at 10 rigs to drill up that inventory. So it's not an inventory question at all to drive those kind of growth rates. And the capital requirement for both the 20% and the 30% growth rates are pretty moderate.

[Roger D. Read:]

So I guess then my final question is why not something – and maybe this goes more to Vicki – but why not something a little more aggressive here if the numbers work fairly well?

[Joseph C. Elliott:]

It goes back to being capital-efficient and return-focused. We want to make sure we have the subsurface understanding, our execution efficiency, our technology and the infrastructure all timed properly so that you get the best rate of returns. And then the amount of capital that gets allocated goes back to the priorities that Vicki mentioned earlier.

[Roger D. Read:]

Okay, all right. I think I get that. Thank you.

[Operator:]

The next question comes from Ed Westlake of Credit Suisse. Please go ahead. Edward George Westlake - Credit Suisse Securities (USA) LLC Hello. Can you hear me now?

[Vicki A. Hollub:]

Yes, we can. Edward George Westlake - Credit Suisse Securities (USA) LLC Oh, thank God, okay. So just on the international production and CapEx, I was thinking that CapEx would come down a bit this year. The $900 million still feels flat year over year. But maybe talk about how long you can keep the international production flat or the growth outlook, say, out through the next few years and how much CapEx it would take to do so.

[Vicki A. Hollub:]

So, Ed, we have lots of opportunities in both – especially in Oman, where we just recently obtained some seismic over Block 9. So we're doing infill drilling that's very successful. We've got Block 62 gas development. We also see opportunities above and below our current steam flood interval in Mukhaizna. And so we have a lot of potential there, and that's why I mentioned it in my comments. I think people don't realize that actually Oman and Qatar have stacked pay, not exactly as obvious to most of the industry as the Permian is. But they're stacked pay intervals, and we're having success developing outside of what our traditional and original completion intervals were. So we're really excited about what the seismic is showing us. We're also pretty excited about our cost-cutting in Qatar, where our team has been able to develop a modular platform that will be able to enable us to expand what we're doing there at a much lower cost. And I'll pass it to Ken Dillon to talk a little bit more about those, but we have opportunities both in Oman and Qatar to continue to keep production flat, or slightly grow.

[Kenneth Dillon:]

Good morning, it's Ken here. As you can see from the slides, we've increased the Al Hosn gas plant capacity by 10%. That was done by very detailed technical reviews both by engineers and operational staff. And then controlled trials were done throughout the process before running the whole plant at capacity. That's an increase in capacity of 10% with virtually no capital at all. If you look at Qatar and you look at the new jacket design there, we basically eliminated the lift barge. We've eliminated going to large fabricators in the region, so we've dramatically dropped drilling costs in Qatar, which opens up all sorts of opportunities there. In terms of Block 9, as Vicki said, we last month signed the new Block 9 contract with His Excellency the Oil Minister. That's a 15-year contract where we see substantial growth opportunities both in oil and gas and in exploration. We think there are other opportunities in Oman that are a good fit long term for us, so overall very positive. Mukhaizna you can see from the slide, the growth trajectory that's possible with investment there. And we've also been trying to build on the Permian experience of assembly line processes in drilling, rolling out OXY drilling dynamics around the world. We're making significant savings, significant reductions in time to market. So in terms of opportunities, our goal is to try and compete with Jody and also deliver long-term cash flow for the corporation. In terms of how much capital you would need to keep it going, that's really a capital allocation point for Vicki, I believe. But our goal is to continue to get better for our international and continue to offer alternatives for the corporation. Edward George Westlake - Credit Suisse Securities (USA) LLC Okay. And then on the theme of competing with Jody, on slide 34 you've laid out a Permian growth trajectory at different rig counts. Maybe just a little bit of color on how you've risked the EURs or the well performance behind that because obviously, your first half wells in the Sand Dunes area were better than your – third quarter was better than the first half, fourth quarter was better than the third quarter. Maybe just give a sense of how much of that improvement have you baked into that production forecast. Thank you.

[Joseph C. Elliott:]

It's a good question. I don't think we baked a lot of that improvement in the forward look, so I think there's upside potential. Our type curves represent the production from full-section development. So your first wells may be better than the last well on a section. So our type curves are based on the average, and that forward look is based on the average. So throughout this year, just like we did last year, we expect continued improvement in both cost and well productivity. So I think there's upside to that production plot, both from a pace standpoint, number of wells you drill per rig line, and productivity. Edward George Westlake - Credit Suisse Securities (USA) LLC Thank you.

[Operator:]

The next question comes from Asit Sen of CLSA. Please go ahead.

[Asit Sen:]

Thank you, good morning. I have two questions. One, on slide 14, Permian Resources gas margin looks like greater than $30 per BOE. When compared with EOR, which has a low cash cost, it looks like the cash flow profile of OXY Permian as a whole has improved. So, Chris, could you frame for us at what price given improvement are we cash flow neutral? And interest of cash flow overall, Permian for OXY, what happens at $60 or $70 oil?

[Christopher G. Stavros:]

At $60 or $70 oil, things change fairly significantly based on the numbers we gave you on our sensitivity around oil prices obviously. But keep in mind that what we said was that there's a lot of flexibility in the capital program. As Vicki pointed out, we'll see how things go in terms of commodity prices through the year. Obviously, we'd be more encouraged to maybe spend a little bit more money at the higher end of the range, better prices. So we'll just see how things go. We gave you all sorts of points in terms of cash flow changes and deltas from the different business segments. So I think I have a high degree of confidence in your modeling ability, so you should probably be able to come to some sense of what's going on. The Permian business as a whole, as I mentioned, generated quite a bit of free cash flow, and Permian EOR is there largely to harvest the free cash flow to redeploy into Permian Resources. So on cash neutrality, it could be whatever you want it to be. We were under $50 WTI in the fourth quarter. We're spending – so you're almost there now if you wanted to spend lower amounts of capital to keep production flat. But it's largely dependent on how much you'd like to grow, and we think we have a lot of opportunities, as Jody pointed out, 11,650 places to park the money at good returns. So I think that is the best way to frame it.

[Asit Sen:]

Okay. And then given the new information, I was just wondering your thoughts on balancing the opportunity to sell some Permian acreage that's not in your core development areas and potentially use the proceeds to accelerate development drilling. And I didn't hear on asset sales the Texas gas assets. Has anything changed there?

[Vicki A. Hollub:]

As I said previously, we're continuing to look at our opportunities to monetize things where it makes sense, where we think that would increase the net present value for our shareholders. And while we're not prepared to talk about specific assets today, we'll continue that process. And as we make decisions, certainly we will share that with you. But it's something that we think about and evaluate pretty much on an evergreen basis.

[Asit Sen:]

Thanks, a follow-up for Jody please. Jody, average lateral lengths have gone up 20% to 7,100 feet. Could you talk about the ability to drill longer laterals in this development mode? And could you remind us what percent of your Permian acreage, that focus area, is operated versus non-operated?

[Joseph C. Elliott:]

So the operated versus non-operated in that core 300,000, you can think 75% to 80% operating position there. With regard to the longer laterals, that's been a great effort by our business unit and our land organization to continue to core up, so doing swaps, doing trades, picking up pieces of acreage to drive that lateral length longer. So I expect us to continue to do that. The majority of our wells will be longer laterals. That's just an average of the whole inventory. Technically there's not a problem. 10,000 feet early on in horizontal development was a bit of a challenge. 10,000 feet is no longer a challenge. We're looking at even the option of 15,000 feet now.

[Asit Sen:]

Thank you.

[Operator:]

The next question is from Brian Singer of Goldman Sachs. Please go ahead.

[Brian Singer:]

Thank you, good morning, a couple of follow-up questions to what's been asked. First with regards to the Permian, to clarify on the longer laterals, can you talk about what the lateral length is that you expect for the 2017 program as it regards to the 300,000 acres your focused on? And then with regards to the 350,000 acres where you don't have identified locations, I think you mentioned in your prepared comments that you are delineating that. Can you talk more specifically about those plans and whether you see scale-enhancing acquisitions as likely in that part of the Permian?

[Joseph C. Elliott:]

So, Brian, the bulk of the development this year will be 7,500-foot or 10,000-foot laterals. If we have to drill a 4,500-foot lateral, it's because we've already developed or started developing a section that way and we really can't change. So most of our wells will be the longer version. On the 350,000 acres we're delineating, it's really multiple things. We're drilling appraisal wells on our own acreage. We're evaluating 3-D seismic. Again, those two equivalent non-operated rigs really are six to eight actual rigs any day of the year. So we get a lot of information from that non-operated position that helps derisk, plus just watching what other competitors do offset of this acreage. So with regard to acquisition, it's going to be a function of what we think about that acreage, what the current position is, what trade opportunities there are to core up before you go down the acquisition path.

[Brian Singer:]

Got it, thanks. And then going to the point on free cash flow, I just wanted to also get just a clarification between slides 23 and 17. We see on slide 23 the $950 million to $1 billion incremental free cash flow you expect. And I think in your prepared comments you said you expect an incremental $500 million from the Permian, which I think was Resources and CO2. If you could, maybe just verify if that was the case. So is that essentially the incremental free cash flow you expect overall in 2017? And then more broadly, are you trying to reflect some greater comfort about spending cash flow relative to the dividend assuming the balance sheet doesn't go out of control, or is there still a more specific objective to try to stay within cash flow after dividend?

[Christopher G. Stavros:]

No, we provided the delta to free cash flow that we expect and some of the pieces of the business based on prior investments that we've made that are now completed, so there's to some extent that specifically around Chemicals. The Permian, a lot of that is driven by the production growth and the volume improvements that we've seen at good returns. And part of it obviously in oil and gas is some view around a little bit better price, but not much. And going forward, I would tell you that not sort of – we started the year with $2.2 billion of cash, and the capital program remains quite flexible. So we'll see how it goes as far as the spending. But again, the number one priority, as Vicki said, right after maintenance is really to continue to be able to fund and grow the dividend over time based on our ability to grow volumes.

[Brian Singer:]

Great, thank you.

[Operator:]

Our next question comes from Pavel Molchanov of Raymond James. Please go ahead.

[Pavel S. Molchanov:]

Thanks for taking the question, guys. Like many companies, you've been finding ways to squeeze out cost from the CapEx budget. But since the original budget last November, of course we've seen an escalation in U.S. service costs, particularly pressure pumping, et cetera. So what is the underlying assumption in your new budget for service cost inflation, whether it's by geography or by segment?

[Joseph C. Elliott:]

So we do believe there will be inflation pressure, and you mentioned pumping service. That's probably one of the areas where you'll see it the strongest. But to counter that, we're really working two approaches. One is to continue to get better technically, some innovations that are happening in the drilling space and in the completion s space. We can drill our wells faster and better over time. That will help offset that inflation pressure. But on the commercial side, we're working very closely with a group of suppliers to create the ability for them to have greater margins without just a price increase, more efficiency, better utilization, better logistics management. And so we think the combination of those two things can hold our overall well costs flat or continue to improve it.

[Pavel S. Molchanov:]

Okay. And supposing that second half commodity pricing ends up being better than the current strip suggests, would the incremental dollar go back to the buyback program that you formerly had active, or would it go directly into the drill bit again?

[Vicki A. Hollub:]

We'll have to see how conditions look in the second half of the year. But currently our plan would be not to increase our capital for this year but to go with the plan that we have in place and to look at what our program next year would look like. But it really is going to depend on how we feel about oil prices.

[Pavel S. Molchanov:]

All right, I appreciate it.

[Operator:]

That concludes our question-and-answer session. I would like to turn the conference back over to Chris Degner for closing remarks.

[Christopher M. Degner:]

Thank you, everyone, for participating today. Have a great day.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.