Earnings Call: Q2 2015

Jul 30, 2015

Good morning and welcome to the Occidental Petroleum Corporation's 2nd Quarter 2015 Earnings Conference Call. All participants After today's presentation, there will be an opportunity to ask Please note this event is being recorded. I would now like to turn the conference over to Chris Degner. Please go ahead. Thank you, Emily. Good morning, everyone, and thank you for participating in Occidental Petroleum's 2nd quarter 2015 conference call. On the call with us today are Steve Chazen, Oxy's President and Chief Executive Officer Vicki Hollub, Senior Executive Vice President of Occidental and President, Oxy Oil and Gas Chris Stavros, Chief Financial Officer. In just a moment, I will turn the call over to our CEO, Steve Chazen, who will provide an updated outlook for 2015. Our CFO, Chris Davros will review our financial and operating results for the Q2 and also provide some guidance for 2015. He will be followed by Vicki Hollub, who will provide an update of our activities in the Permian Basin. As a reminder, today's conference call contains certain projections and other forward looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that cause results to differ is available on the company's most recent Form 10 ks, our Q2 2015 earnings press release, the Investor Relations conference call slides, our non GAAP to GAAP reconciliations can be downloaded off our website at www.oxy.com. I'll now turn the call over to Steve. Steve, please go ahead. Thank you, Chris. We've made progress towards our objectives for this year. Principal goal for the year is to achieve cash flow neutrality where our operating cash flow covers both our capital spending and dividend outlays at $60 per barrel realized oil prices. We will achieve this goal through deploying our capital and operating cost savings into further production and cash flow growth, driven mostly by our Permian Resource Business Unit and the start up of the Elhosin Gas Project. Year to date, we estimated about $450,000,000 in captured cost reductions. We expect our 2015 capital outlays to be about $5,800,000,000 as we have redeployed some of the cost savings in drilling more wells in our Permian Resource Business Unit. In short, we are learning to do more with less and expect continued improvement in productivity through the year. Despite volatile product prices, our oil and gas segment has been operating well in nearly all of our key assets. We've increased total oil production by 16% since the Q2 of 2014. The focused development program in Permian Resources has driven most of the growth as well as strong production volumes in Oman and Colombia. We have also focused on optimizing our base production. Rather than making headcount reductions during this downturn, we've sent many of our engineers out into the field to replace contractors. They have done a good job of maintaining our base production and driving operating efficiency. In the Permian, we have shifted our resources business to a focused development program. We're drilling completing wells at a faster pace and accelerated our time to market. Total production increased by about 50% year over year again exceeded our internal outlook. As such, we have increased our estimated production for the second half of the year to 117,000 BOE a day. Actual results continue to improve and outperform our internal outlook. Elhosin is a large world scale project and the first of its kind. It is reasonable to expect some operational pains as it's ramped up to full production. In the Q2 of 2015, Elhosin produced 18,000 BOE a day and sold its 1st shipment of sulfur. Due to mechanical challenge in the sulfur recovery units, the plant was limited to 50% of capacity for most of the quarter and production was curtailed for most of the month of April. Repairs to stabilize the sulfur units were completed in July and the plant has responded well as production is ramped up. The plant is currently producing at about 50,000 BOE a day to us and we expect to contribute about 30,000 BOE a day in the Q3. Despite a lower capital production, we expect production growth of 70,000 to 80,000 BOE a day in 2015 driven by the start up of the El Hosen Gas Project and focused development program in Permian Resources. In the United States, we expect oil production growth about 8 percent, partially offset by declines in NGLs and natural gas production. Vicki Hollop will provide further details on the outlook for the U. S. Oil and gas business. Construction on the Ingleside ethylene cracker is ahead of schedule and on budget. There are currently 1300 workers on-site. Construction is about 30% complete and over 80% of the equipment has been purchased and delivered. We expect to be more than 70% through our capital spending on the project by year end and for the plant to start up in early 2017. As we capture price savings from suppliers and improve the efficiencies of our operations, we're able to do more with less spending. Our capital spending in the 2nd quarter declined by about $250,000,000 and will continue to decline throughout the year. As for our forecasted capital spending level in some Middle Eastern assets may be slightly higher than expected this year, However, the production sharing contract should allow us to quickly recover our capital costs with an increase in oil production. We expect the exit this year at a quarterly spending rate of to $1,200,000,000 If oil prices remain at current levels around $50 our 2016 capital will be less than both the 20 15 full year and the 4th quarter run rate. Given our large acreage position and deep inventory, we have the flexibility to deferred drilling and appraisal activities. Although we will outspend our cash flow this year, we expect that going forward our operating cash flow will cover our capital and dividend payments assuming $60 per barrel oil price realizations. We continue to invest growth capital in the Permian Resources segment. Over the first half of the year, we did not make any meaningful acquisitions nor do we have any in the pipeline. Market for asset acquisitions in the Permian Basin has been heated with new entrants paying sizable premiums for acreage. With our deep inventory of assets, we will focus on organic growth with a low possibility of selective bolt on acquisitions that leverage our our repurchase authorization. At current stock price levels, we would view the stock as attractive for repurchase. Now I'll turn the call over to Chris Stavros for review of our financial results. Thank you, Steve, and good morning, everyone. First, I want to highlight some new formatting around our quarterly disclosures. We created a set of earnings release schedules that replaces the previous IR supplemental schedules. The new format is more comprehensive providing condensed quarterly financial statements plus quarterly data going back for the entire prior year. We generated core income of $165,000,000 for the Q2 of 2015 resulting in diluted earnings per share of $0.21 an increase of $0.04 per share in the Q1 of 2015 and a decrease from $1.38 per share in the Q2 of 2014. Worldwide oil prices improved about $6 a barrel in the Q2 of 2015 compared to the Q1, but still remain well below prices comparable to last year. U. S. Natural gas prices continue to decline down about $0.40 per Mcf from the Q1 and NGL prices stayed essentially flat. Our 2nd quarter capital spending was about $1,500,000,000 down 14% from the $1,700,000,000 we spent in the 1st quarter. We continue to ramp down our capital program in the 2nd quarter focusing our development activity in core areas of the Permian Basin and parts of the Middle East with an emphasis on growing our production volumes and importantly our operating cash flow. Despite the reduction in this year's capital program, we continued to grow our domestic oil and gas volumes driven by Permian Resources operations. Permian Resources grew its oil production 78% in the second quarter adding 31,000 barrels per day compared to the year ago period with total BOE growth of 51%. Production from Permian Resources improved 11 BOE per day sequentially with 9,000 barrels per day coming from oil. Turning to the specific business segments. Oil and Gas core after tax earnings for the Q2 of 2015 were $108,000,000 $130,000,000 higher than the Q1 and $833,000,000 lower than last year's Q2. As I mentioned earlier, the largest impact of the change in year over year earnings was due to lower oil prices. For the Q2 of 15, total company oil and gas production volumes averaged 658,000 BOE per day, an increase of 13,000 BOE in daily production from the 1st quarter and 78,000 BOE per day from the same period a year ago. Total company oil volumes were 433,000 barrels per day in the 2nd quarter, 61,000 barrels per day higher than the year ago period for an increase of 16%. Total domestic oil and gas production averaged 333,000 BOE per day during the Q2 of 2015, up 7,000 BOE per day sequentially and 25,000 BOE on a year over year basis with all of the increase coming from Permian Resources. This was partially offset by lower production from our Mid Continent assets where we have ceased our drilling activity. Domestic oil production was 205,000 barrels per day during the 2nd quarter, an increase of 7,000 barrels per day sequentially and up 26,000 barrels per day or 15% from the year ago quarter exceeding our earlier guidance for the period. For the year to date, overall domestic production volumes have exceeded our expectations. Our domestic production growth for the 1st 6 months of 2015 resulted in an additional $175,000,000 of operating cash flow when compared to the last 6 months of 2014 and using current product prices for both periods. We achieved this growth while reducing our domestic capital by $389,000,000 In summary, we not only drilled and completed the wells, but sequentially grew both our production volumes operating cash flow, which can be reinvested in the business. International oil and gas production volumes averaged 325,000 BOE per day during the 2nd quarter, up 6,000 BOE per day sequentially and 53,000 BOE per day on a year over year basis. Production from the Alhosin gas project increased by 9 1,000 BOE per day from this year's Q1 to 18,000 BOE per day in the second quarter and as Steve mentioned also realized the sale of its first shipment of sulfur. Production was curtailed during much of the second quarter as mechanical modifications and adjustments were made to the sulfur recovery units. These adjustments have been completed and we expect our net production to exit this month around 50,000 BOE per day. Our 2nd quarter oil and gas cash operating costs of $12.10 per BOE declined 9% from the first quarter of $36 per BOE due to lower surface and down home maintenance costs, lower workover costs as well as higher production volumes. DD and A for the Q2 was $16.06 per BOE compared to $15.35 per BOE during the Q1. Taxes other than on income, which are directly related to product prices were $1.85 per BOE for the Q2 of 2015 compared to $1.63 for the first quarter of $2,017.45 per BOE for the full year of last year. Chemical pre tax earnings were $136,000,000 for the Q2 of 2015. Results were lower than expected due to higher ethylene feedstock costs and lower caustic soda prices as well as some unplanned outages at 2 of our VCM plants. Midstream pretax earnings were $84,000,000 during the Q2 compared to a loss of $5,000,000 in the Q1 of this year and income of $130,000,000 in the same period a year ago. Our Midstream segment is composed of physical marketing, pipelines, power and gas physical marketing is exposed to spreads between WTI Midland and Gulf Coast pricing through multiple pipeline commitments. In the Q2, our midstream segment results benefited from wide price differentials. We expect this benefit to partially reverse in the Q3 as price differentials have narrowed. Our gas processing business converts wet gas to NGLs. Currently NGLs are trading at equivalent price of natural gas, which is insufficient to cover the plant operating expenses. Our domestic pipelines as well as the Dolphin pipeline generate a relatively stable and strong stream of tariff income from transporting crude oil natural gas. Operating cash flow before working capital changes for the 1st 6 months of 2015 was $2,600,000,000 As I mentioned, higher production volumes resulting from our continued investment in the Permian as well as improved oil price realizations resulted in a sequential increase of about $400,000,000 in operating cash flow before working capital changes to 1 point dollars in the second quarter. Working capital declined by $950,000,000 during the 1st 6 months of 2015. At December 31 last year, accounts payable was $5,200,000,000 and as of June 30 this year, it decreased by $1,100,000,000 to $4,100,000,000 This decrease was due payments related to higher capital and operating spending accrued in the Q4 of last year, but not paid until 2015. Total company capital expenditures for the 1st 6 months of 2015 were $3,200,000,000 and about on track with our full year 2015 capital budget of $5,800,000,000 Oil and Gas spent $2,700,000,000 in the first half of twenty fifteen with Permian Resources expenditures comprising 47% of the total and the remaining $500,000,000 split nearly evenly between Chemicals and Midstream. The continued growth in our operating cash flow should help us to achieve our goal of being cash flow neutral after capital expenditures and dividends at oil prices of roughly $60 a barrel. In June, we completed a bond offering issuing senior notes of 3.5 percent and 4.625 percent and received net proceeds of approximately $1,500,000,000 The proceeds were used to build liquidity and partially prefund some of our debt maturing in the first half of twenty sixteen. Oxy's credit ratings remain unchanged at A by Moody's and S and P. We paid cash dividends of $1,100,000,000 in the 1st 6 months of 2015 and purchased 7,400,000 shares of our stock for $571,000,000 This amounts to an annualized cash return of 6.2% for our shareholders. The share repurchase activity for the 1st 6 months also has the benefit of reducing our annualized dividend outlays by approximately $22,000,000 Our cash balance at the end of the second quarter was $5,100,000,000 Our long term debt to capitalization ratio was 17% at the end of the 2nd quarter. The worldwide effective tax rate on our core income was 65% for the Q2 of 2015. Looking ahead to the Q3 domestically, we expect production from Permian Resources to grow by roughly 5% sequentially on a BOE basis including 5,000 barrels a day of oil growth. Growth in the Permian should be roughly offset by declines in our midcontinent production, leaving overall 3rd quarter domestic production about flat with the Q2. We expect our international production volumes to increase by about 10,000 BOE per day in the Q3. Production rates at Alhozan should continue to improve increasing to about 35,000 BOE per day on average in the 3rd quarter. The increase from Alhozan should be partially offset by approximately 8,000 barrels per day of lower volumes in Colombia due to pipeline disruptions experienced during July. Assuming no meaningful disruptions during the second half of the year, we are raising the lower end of our full year 2015 production guidance range from 650,000 to 660,000 BOE per day. Our current estimate of full year 2015 volumes of 660,000 to 670,000 BOE per day will provide year over year growth of 12% to 13%. Price changes at current global prices affect our quarterly earnings before income taxes by $30,000,000 for a $1 per barrel change in oil prices and $7,000,000 for a $1 per barrel change in NGL prices. A swing of $0.50 per 1,000,000 BTUs in domestic gas prices affects quarterly pretax earnings by about $15,000,000 Our Q3 2015 exploration expense is anticipated to be about $20,000,000 pre tax. We expect our Q3 2015 pre tax earnings to be about $140,000,000 Our 3rd quarter midstream earnings will be principally impacted by Midland to Gulf Coast oil price differentials. We expect our interest expense to increase to about $50,000,000 in the 3rd quarter from $7,000,000 in the 2nd quarter. The sequential increase is due to expensing of previously capitalized interest on the Al Hosn project and the $1,500,000,000 senior notes we issued in June. Using current strip prices for oil and gas, we expect our full year 2015 domestic tax rate to be 36% and our international tax rates to remain about 65 percent. To summarize, we demonstrated strong year over year production growth of nearly 13% in the 2nd quarter bolstered by continued growth in Permian Resources and from the Alhozan project. We also continued to grow our operating cash flow, which is being used to organically reinvest in the business, while providing a balanced return of cash to our shareholders. I'll now turn the call over to Vicki Hollub, who will provide an update on our operations in the Permian Basin. Thank you, Chris. Today, I'll review the highlights of our Permian Resources and Permian EOR activities in the second quarter And then I'll provide guidance on our program for the remainder of 2015. I'd like to highlight a few key messages. First, Permian Resources is continuing to drive capital cost down through improved execution efficiency in drilling and well completions. 2nd, production again exceeded expectations due to reduced time to market and better than planned well performance. Finally, the positive returns of our Permian unconventional programs in this environment along with a large volume, low decline production from our EUR operations provides us flexibility in a wide range of product prices. The advantages this portfolio provides can't be duplicated in the Permian Basin. In the second quarter, Permian Resources achieved daily production of 109,000 BOE per day, a 12% increase from the Q1 and a 51% increase versus the prior year. Oil production increased to 71,000 barrels per day, a 15% increase from the previous quarter and a 70 8% increase from a year ago. We drilled 47 wells, including 42 horizontals. We placed 71 wells including 53 horizontals. In the second half of this year, we'll operate about 12 rigs and drill and complete at least 100 horizontal wells. We continue to work on 4 key activities that are adding more wells to our inventory and reducing the and to build the petrophysical and geochemical models necessary to improve well performance and to add more locations to our inventory. 2nd, our teams have further reduced our drilling and completion costs and optimize the value of the manufacturing approach in our key areas. 3rd, although we have achieved significant cost savings from our vendors, we continue to look for creative ways to reduce service and materials cost further. Lastly, we're enhancing base management and maintenance operations to maximize at minimal and incremental cost. These activities have generated higher than expected production and have lowered our finding and development cost, thereby increasing our inventory of drilling locations that deliver returns, which exceed our cost of capital. We'll provide an update our inventory by play and breakeven prices later this year. In the Q4 of last year, we began transitioning from appraisal mode to a targeted development program, utilizing a manufacturing approach combined with integrated planning and engineering. This has reduced non productive time, maximize maximize the efficiencies of pad drilling, including the use of zipper fracs and has reduced infrastructure costs. As a result of these efforts, we have achieved significantly improved well delivery and lower well costs. As the example on Slide 27 illustrates, we've reduced our drilling time by about 50 percent and our cost by about 40% in a recent Wolfcamp A well in the Delaware Basin. Our improvements were driven by adopting and adapting oil fill technology, including an advanced salt interval in the wellbore. Oxy Drilling Dynamics is a proprietary system we have developed by expanding upon mechanical specific energy concepts to improve rates of penetration. This improvement in drilling efficiency is a structural change to our business that will sharply lower our cost irrespective of pricing concessions from our suppliers. In the Delaware Basin, our Wolfcamp A 4,500 foot well cost decreased by about 40% from 20 fourteen's cost of $10,900,000 to a current cost of $6,800,000 We've reduced our drilling time by 23 days from 20 fourteen's average of 43 days to 20 days. I would note that even as we have lowered our completion cost per well, we've optimized the density of our completions and proppant loads and have been drilling longer laterals. As I'll highlight later, our productivity has continued to improve while we have lowered our costs. In the Delaware Basin, we've identified 900 additional horizontal development locations for a total of 5,700. We have 2,000 horizontal well locations ready for development including 800 sites in the Wolf Camp A bench. The majority of these locations are in our operated areas in Reeves County. In New Mexico, our Bone Spring potential is equally as as significant with 2,300 location. Our well performance in the Delaware Basin continues to be strong. We placed 13 horizontal wells on production in Wolfcamp A benches in the Q2. These wells achieved an average peak rate of 13.59 BOE per day and a 30 day rate of 9.88 BOE per day. The Moore Hooper 3H well achieved a 23.89 BOE per day peak rate and a 17 69 BOE per day 30 day rate. Additionally, our Lennox II-5H well achieved a 2,425 BOE per day peak rate in a 15.06 BOE per day 30 day rate. Both of these wells produced around 70% oil and we believe that they are among the prolific drill to date in the Permian Basin. Now I'd like to shift to the Midland Basin. We've made similar improvements in well cost and drilling days in our Wolfcamp A wells in the eastern part of the Midland Basin. We reduced the cost of these 7,500 foot horizontal wells by 30% from 20 fourteen's cost of 9 $200,000 to a current cost of $6,500,000 We reduced our drilling days by more than 50% from 46 days in 2014 to 20 in the second quarter. Through our program this year and in evaluating the acreage from the acquisition in December, we've added 600 horizontal locations in the Midland Basin for a total now of 3,100. Most of the additions were in the Wolfcamp A and Spraberry formations and we now have 2,000 identified locations ready for horizontal development. A new area for us is in the Midland Basin. It's called Big Spring, which was part of the December acquisition. We launched into development early this year. And in the Q2, we brought online the May 1102 Wolfcamp A well at a peak rate of 18.4 6 BOE per day and a 30 day rate of 12.62. The well is producing at over 85% oil. These Wolfcamp A well results have been outperforming our initial type curves for this emerging play in Howard County. Now shifting to Permian EOR, where year to date, we're ahead of plan and meeting our aggressive cost improvement target. We've reduced the cost of drilling San Andres wells by about 30% through optimized drilling parameters efficiency. Additionally, we've reduced our downhole maintenance hours per job by 20% since the Q4 by applying the learnings gained from a manufacturing approach to well maintenance. We have 15,000 wells in the Permian EOR business and expect to reduce our 2015 downhole maintenance enhancement cost by $60,000,000 versus 2014. These cost reductions will further increase the free cash flow generated by Permian EOR business in the current oil price environment. Despite the low price environment, we are continued to commit to developing our technical talent and recently finished construction of a new training center in Midland that will open in September. In previous industry down cycles, we've seen the industry overreact through widespread layoffs. We're taking a different approach with our response to low oil prices and have deployed many of our engineers in the early stages of their careers out into the field where they have In closing, we'll continue to execute a focused development strategy in 2015 and we'll pursue additional step changes in well productivity and cost structure. For the remainder of 2015, we plan to operate an average of about 12 drilling rigs to drill around 100 horizontal wells in Permian Resources. This is a higher activity level than planned, but we believe investing efficiency gains back into Permian Resources is a prudent action to take. We expect to produce an average of 117,000 BOE per day in the second half of twenty fifteen and for the business to drive continued growth in operating cash flows. Strong production growth from our Permian Resources business along with the high volume, low capital and intensive Permian EOR business keeps us well positioned to not only meet the challenges of this lower price environment, but also to profitably grow our combined Permian business. Now I'll turn the call back to Chris Degner. Thank you, Vicki. We'll now open up for questions. Emily? Thank you. We will now begin the question and answer session. Our first question is from Evan Kallio of Morgan Stanley. Please go ahead. Hey, good morning everybody. My first question, Permian Resources production beats again very impressive cost and efficiency improvements here. Really two questions. Does your performance lower your existing targets? And secondly, how would you benchmark your Permian operating performance versus peers where there's a peer scope to see some continued improvement for a group that's improving at a pretty fast pace? Currently, we feel like in the Delaware Basin, we've we're definitely upper quartile in terms of drilling performance. And actually, we've recently compared our performance to some of our with the direction that we're headed, we expect to be first in performance and drilling in the Delaware Basin due to the activities and initiatives that I just discussed. And with respect to well performance, we looked recently at what some offset operators are doing. And compared to offset operators in the Delaware Basin, as I said in my discussion here, we believe that we've just completed some of the best wells in the basin in the Delaware. In the Middle basin, this new area that we're developing now in Big Spring is certainly showing some of the best production that we've seen yet in Midland Basin as well. So in some areas in the Midland Basin, we're about par and in some cases slightly lower than some of our competition. But certainly, this Big Spring area is competing very well as is Merchant. Right. And does that reset your targets in terms of the targets you've put forth in the slides? For now, what we're trying to do is for we feel comfortable with what we've stated for the second half of this year. So that's the target we expect to be able to hit, which equates to about $109,000 average for 2015. With respect to 2016, our targets on a per well basis on the average are going to increase. But what we haven't determined yet is what level of activity we'll have for 2016. So we feel very comfortable that we're going to have a stronger program going into 20 16, but the level of capital spend will depend on market conditions. Yes. Fair. My second question relates to locations. I mean, also a large uptick in locations in Delaware and Midland and particularly in development ready locations. I mean it sounds like a model change there that you discussed, but can you give us maybe any further color on that change? And how is that change continuing to evolve throughout the year? Are there drivers for additional scope change given the pretty significant jump there? Yes. What's happening is our teams have become so efficient in a number of areas. So we're not just getting good with drilling. And the drilling has been the part of our performance that we've highlighted a lot. So drilling performance is significantly improving and it's improving because of the modeling work that our teams are doing in addition to the execution in the field. So it's a combination of our planning, our design and our guys in the field executing it very well. In addition to that though, we have an efficiency team that's driving how we do our business from the time that we go out, we decide to spot a well to the time that we get it to sales. Every segment of that we've worked on to try to improve our efficiency and that's gone really well, which has been a big part of the acceleration in addition to the improvement in a per well basis in terms of initial rates and performance. The other thing that's helping us significantly is the business units working with our exploitation team to enhance what we understand about the reservoir So our modeling work, especially our petrophysical geomodeling and our mapping has enabled us to do a better job of selecting where to place the lateral part of the well, not only where to spot the well, but where to put the lateral section of the well and also how to complete it. And while we've seen significant improvements in our wells with the design changes we've made, we feel like there's still more improvements to be made and we're continuing to work it. I think you mentioned that you are going to provide price sensitivity later in the year. But I mean are these locations conditioned on a strip or any particular price level currently? Well, in the slide you'll see that we have an inventory of our current well locations identified. And what it shows is the inventory that we can drill by price range. But I want to point out here that this inventory is on Slide 25, I think. But the inventory that's shown on that slide really is not updated for not only well performance, but it's not hasn't been updated for our current cost structure. So we'll be updating that at the end of the year. And you can use that as a guide to see the level of inventory that we have based on what the oil price is. And this is based on delivering returns that are greater than our cost of capital. Very good. Great. I'll leave it there. Thanks. Okay. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thanks. Good morning, everybody. Vicki, I can't help but notice that the absence of any meaningful commentary around the Middle East in the slide deck this quarter. I guess following on from Evan's question, substantially greater opportunity perhaps in the Permian Basin. How as you think about the transition of the CEO role over the next year or so, how does your view of the Middle East as an area generally, obviously, there's a lot of large core assets, but there's also a lot of smaller non core assets. How do you think about your preparedness to invest in those kind of areas, the type of returns, the risk profile and so on compared to the short cycle fairly well known entity that you have right in your backyard? In other words, is the Middle East back on the table as a potential rationalization story? I've got a follow-up please. Well, we're looking at the Middle East and basically as a group of what we consider core assets versus non core assets. And the assets that we consider to be really core to our business over there is are the assets in Oman, the Alhozan project, the Dolphin project, those are our cash flow generators. So the steam flood in Macaesna is certainly one of the projects that's very important to us. Some of the other assets in the Middle East, we're currently in Qatar. That's been a good project for us. That still has 5 years left on the contract there. Some of the other assets are assets that as we've mentioned before, are assets that are non core to us. And given the opportunity, we would work to try to monetize or exit those. I don't want to risk wasting my follow-up on this, but the Omani contract obviously is something that when you mentioned Omani you mentioned the steam flood, but you've got other 35 or so 1,000 barrels a day of production there today in a contract. Are those is that asset competitive? Is it delivering free cash flow at this point? In other words, we can go ahead, Steve. She's new to the Middle East. But she'll answer next quarter. The answer is, yes, it's free cash flow generator at this point. Whether it's competitive or not hard to measure. And so as you know what happens is you invest the capital and you get it back within the year typically. So while you show a lot of investments you get it back fairly quickly and then some profit oil to go with it. So it's an okay contract at this point. Whether but that's the same kind of financial characteristic that the Permian Resources has frankly, just look at it financially. And so the issue that Vicki will wrestle with over the next few months is whether it's competitive with the continue to invest in basically shifting that capital to resource which basically has the same kind of payout timeframe, maybe a little longer in resources, but not much. So that's really the what we're having to wrestle with. And we'll look for a contract extension that is at least as good as what we could get a lot closer to home. Okay. Thanks for elaborating Steve. My follow-up is, again, I guess it's one of the things that we periodically revisit and it's the dividend. And obviously, you've got a big dividend commitment. The stability of the underlying cash flow is a big, I guess, funding mechanism, CO2 Chemicals and so on. But if you shift your capital allocation, let's say, to the Permian away from those long life assets that you have in the Middle East, one could argue that the visibility on long life cash flow to sustain that dividend growth kind of starts to deteriorate a little bit. So what we're really coming around to is how do you reset the dividend level such that you're able to maintain one of the I guess the anchors of obviously legacy investment case, which is dividend growth. And of course, what we're really getting at is, where's your head out on the buyback? Are you going to scale down the shares in order to reset that dividend commitment? And I'll leave it there Steve. Thanks. Yes. I'll answer that for now. And we've talked about this a lot. It's not some new topic. If we concentrate the Middle East on the few on the long life projects, that will generate relatively more free cash flow. In fact, if we stopped investing in the so called non core group, we'd have more cash flow than we have now. So they're basically users of cash for either overhead or whatever. And so we think we can improve the cash flow out of the Middle East with that. The CO2 businesses and the chemical business. Chemical business will finish the cracker here in a year or so. The cash flow will improve there. We think the dividend will be fairly easy to maintain. However, it will require some shrinkage of the shares. There's no question about that. And so one of our objectives over the next time frame would be to shrink the shares and therefore reduce the dividend especially at the current prices where prices of the stock where the dividend yield is exceptionally high. Appreciate the answer, Steve. Thank you. Our next question is from Ed Westlake of Credit Suisse. Please go ahead. Hi, yes. Good morning, Vicki. Back on to the Permian, if I may. So you've got this $6,200,000 target for well costs. I think that's what Evan was trying to get to see where that could get down to what the limit you think is on that? And then I've got a follow on about recoveries. The $6,200,000 is the target, but we feel like that we still have opportunities to lower beyond that. Actually have achieved that with some of our wells, but we're just not achieving that on the average yet. We're still seeing opportunities. The teams are working on new ideas. I think that there's a good possibility we could get below the 6.2. Not only that target in the Delaware Basin, but our targets in the Midland Basin as well. They're making some really good progress doing some very good work modeling. The other experiments that you spoke about on the last call, obviously, making progress on landing zones, proppant intensity and cluster spacing, all of these things that the industry is using. And we're seeing some individual well results that you flagged out, for example in the Delaware on slide 30 and the average is kind of static. So I'm just kind of wondering if there's a sort of help you can give us in terms of where you think you could get to from these spot wells that could be sweet spots versus the average that you're delivering across the play? Yes. What we're trying to do in the Delaware Basin, I think I mentioned before is that the 3 d seismic that we're acquiring that would be something that could help us identify or actually it's the next step to high grade the locations that we drill. So it's not as we've said before, it's not only about where you place the well within the interval, but where you drill the well to. And our basin modeling, which has recently been updated, that's another tool that we think is going to help us continue to the average up a bit. So we think that those two tools, the basin modeling where we've done a lot of geochem work and we've done upgraded our petrophysical models. The 3 d seismic now, we're in the process of acquiring that. We should be able to have that processed and begin interpretation by the end of the year. So that should help to impact the 2016 program. Okay. Thanks so much. Our next question is from Leo Mariani of RBC. Please go ahead. Hey, guys. Just a question around Al Hosan here. I think you guys previously had a target of 60,000 barrels a day to eventually hit. Do you think that target is still realistic? And is that something we might get to in 2016? The answer is yes, it's realistic. They could in theory do better than that. It's running if you look at the numbers more liquids rich than we had originally forecasted. And we see that continuing. So you're going to wind up with probably more liquids I think. I think you'll with a little luck we'll get to it by year end, but if not certainly by the Q1. Okay. That's helpful. And I guess just with respect to your comments around CapEx, obviously, you guys are seeing CapEx move lower here in the second half of $15,000,000 I know you guys previously had said that you might under spend the $15,000,000,000 budget of the $5,800,000,000 Is that still possible here? Because I know it sounds like you guys maybe have slightly higher Permian drilling activity. Just trying to get a sense of where that spend may go. The driver isn't the Permian Permian is well managed. The question is the part that's not really in our control which is some of the Middle East stuff. And again I think if we effectively if you put just a a it's not totally in our control because you have the issue with the not foreign governments. So if we spend a little more or a little less that really just reflect effect amount of number of barrels we'll get back within 6 months. So that's about the only thing about the capital that I think is what's within our control would be lower effectively than that, but there's a part of it that's really not in our control. Okay. That's helpful. And I guess just to kind of be clear on your intentions for next year if prices stay low at 50, you guys have these 12 rigs in the Permian. Is that likely stay at $12,000,000 or potentially could you cut it back further next year? Well, it just depends on what the price is. 12% is I think a reasonable guess for now. But we would even in a more stable price environment, we would have a hard time at this point of the year in making a sensible outlook for next year. I mean, we could make one up, but I think it's hard to make a sensible outlook for next year even now with the volatility of the prices. We're low to say exactly what we're going to do. The intention is that we'd like to be I think we can make fairly straightforwardly make cash flow neutrality in the $60 environment. Now the question is can we make it in a $55 environment? I just don't know that yet, but we're certainly going to try. Okay. So it sounds like cash flow neutrality would be the overarching theme for next year? You can't just run for the rest of your life outspending your cash flow. I mean you can do it for a year or maybe 2 years, but that can't be a business model for any ongoing enterprise, although obviously there are companies that have been doing it for a decade. Okay. Thanks, Steve. Thanks. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead. Great. Thanks. Good morning. Maybe if I could start in the Permian as well. The addition to the well inventory was great to see and I realize some of that is on the modeling side. But can you talk maybe a little bit of it looks like there were additions across a variety of zones. With the new models and as you continue to drill, is there any zone in particular where you're seeing particular strong improvements or where your view may be changing at all in the basin? Yes. I would say that our view changed a little bit in the Midland Basin where we thought at the beginning of the year that the Spraberry would be the best interval for us in the Midland. But now we're seeing the Wolfcamp A in both the Merchant area and the Big Spring area is looking very, very good. So that was a positive sign for us. So we have now 3 intervals, the Wolfcamp A, Wolfcamp B and Spraberry that are economical to develop in the Midland Basin. And in the Delaware, what we're doing there is we're trying to stay very focused this year on developing what we plan to develop, so that we have the infrastructure in place and that we maximize the use of that infrastructure as quickly as we can before we move on to other intervals in other areas. But one of the things 2 of the things that we're seeing is that the Third Bone Spring and the Avalon are actually starting to look very good for us around our acreage. And so we're modeling that now. And actually we'll certainly we think unless we just have significant improvements in other intervals, both of those intervals will be a part of our 2016 development program. That's great. Are you still increasing lateral lengths in either basin or where are you on that front at this point? Yes. In the actually in the Midland Basin, what we're doing there is we've drilled anywhere from 4,500 feet up to 10,000 in the Delaware Basin. And our current average there is about 6,800, but we're trying to where we can target drilling 7,000 to 7,500 in the Midland Basin. In the Delaware, we've drilled up to about 7,850. And actually, we our average in the Delaware Basin probably is around 4,500 there. We're expecting to in that basin have a minimum of 4,500 going forward in the future and would like to drill maybe in the 5,000 to 5,500 range. Okay, great. And maybe if I could ask one on the overall U. S. Portfolio. You discussed a little bit your views on the Middle East up to this point. But where do you stand at this point on portfolio on the state of the U. S. Portfolio? The dust has settled a bit on some of your 2014 activity. Are there still assets that you would view as non core at this point that you could potentially look to market? The assets that we consider non core in the U. S. Are still Williston and Piance. We have a South Texas asset that when liquids prices are good, it's a great project. And actually, we have a lot of work that we could do at South Texas. The team down there has worked up a lot of potential workovers. We have a lot of drilling prospects on our South Texas acreage. So I'm just going to use this opportunity to say that even though we're not investing growth capital dollars in any of those three assets, those teams have done an incredible job to manage their base production and optimize it. And they're optimizing it with minimal expense of any kind. They're doing a tremendous job. So we still consider there to be a lot of potential in South Texas. Williston, we simply want to monetize because of the fact that we don't have a lot of running room there. We started some larger completions at the end of last year in the Williston Basin that really showed significant improvement in our well productivity there. But because of our running room, because of the differential in the Williston, it just can't compete with our Permian Basin assets and we don't think it ever will. So we do want to monetize it along with Piazza. Okay. Great. Thank you. I'll leave it there. Our next question is from Paul Sankey of Wolfe Research. Please go ahead. Hi, good morning everyone. Can I just jump back to the cash flow neutrality debate? What would the volume outlook be in that situation Steve? Are we just talking about staying flat or some sort of growth? There'd be growth in the volumes. The reason we're investing is to grow the cash flow. So, yes, the volume it isn't going to be a flat volume situation. We have our own outlooks for the end of the year on what the Q4 production will look like volumes and the same thing with some view into the Q1 of next year. So I think generally speaking it isn't just what we have, but also what we see. But I think also I think the capital the cracker expenditures will fall next year. Some of the midstream expenditures will fall. So the amount of capital, which doesn't add to volumes, will decline next year. So I think the time we get through, I think we're fairly close to where we need to be. I mean, we've generated cash from operations in this past quarter about $1,500,000,000 before working capital changes. So you're talking about a $6,000,000,000 sort of run rate. Our capital spending will be well next year would be well below the current 5.8 number. So it's pretty much in sight. We get a little improvement in chemicals and few more dollars really in oil price. What's really held us back more than anything is probably NGL pricing. We weren't as negative as it turned out to be. So that's another area where I think we've been more disappointed frankly in NG hull pricing than we have the oil pricing, which is very similar to our outlook. Sure. What's the you said that you're struggling to think about capital neutrality at 55%. I'm not clear why that would be so much more difficult than thinking about it at 60? It's another $500,000,000 Yeah. Okay. So you just got to and you I guess ultimately you said many times that you're going to you need to grow production if you're going to grow the dividend basically, right, sir? Yes. I need to grow production if I'm going to grow the dividend. I need to grow production if I'm going to track or Vicki is going to attract the kind of employees she'd like to have. I think a stagnant business is generates a stagnant workforce. The alternative would be I guess just to sell Oxy if you can't make it right? Yes. I think that you can ask her about that. That's what I'm asking. All right. Thanks, Leslie. Our next question is from John Herrlin of Societe Generale. Please go ahead. Yes. Hi. Given all of the efficiency savings you're getting in the U. S. And the Permian on drilling and completion and all that, do you have a sense of where you think your DD and A rates will go to on kind of a normalized basis? I think our DD and A rates are you're talking about for the Permian Resources business in particular? Yes. We're certainly headed toward DD and A of less than $15,000,000 and that's with that sort of depends in terms of where it eventually lands, depends on our infrastructure and how we can optimize that. Thus far, we've done a really good job of building water handling infrastructure and gas processing, gas to sales, gathering systems. So we're as we continue to optimize that, part of the reason that we're developing the way we are is to ensure that over time we can develop our reserves and minimize the facilities costs. So we're trying to spend the bulk of our dollars on getting the reserves out of the ground. Ultimately, we're putting together these life of field depletion plans, which help us to do that. And our target is to always make sure that our development facilities and infrastructure. Yes. As we look at DD and A just to give you an accounting sort of answer. As you look at DD and A, you've got the historical cost when oil was $100 that are built up in there. We're adding it basically well below $15 currently. And so the finding cost currently the incremental finding cost is quite low. And so it just will take a while to roll through the old stuff. So it's probably going to take a couple of years or something to sort of get the bulk of it at the bulk of the ads at the low F and D. So I think what you're putting aside product price changes, you'll see finding costs over time. Great. Yes, I was just wondering about the timing of it. It just depends on how fast you DD and A the historic costs because that's what's holding it back. Okay. Great. Next one for me is on Howard County. You said you had some very good performers there. Is and its newly acquired properties. Is that something that you would accelerate? Or it's just part of the program? We actually we're trying to stay disciplined in terms of how much we accelerate. So we will do more drilling there. We do have drilling plan there. It will be at a moderate pace through this year because we have other areas that are pretty good as well. If we see over time that on a consistent basis that tremendously higher than anything else we have in the Permian Basin in the Midland Basin. We'll certainly go over and try to accelerate that, but with minimal incremental cost. Great. Thank you. Our next question is from Scott Portillo of TPH. Please go ahead. Good morning all. Just a quick question on the Permian. I wanted to follow-up in regards to the inventory update. I was curious as we think about both the Wolfcamp A and the Wolfcamp B, what are some of the underlying assumptions from a downspacing perspective? And if you're testing any further downspacing in regards to STACK staggered development in the play? In the Wolfcamp A and the Wolfcamp B, we're being very careful not to down space too much. So we have some pilots in place and we have some reservoir modeling ongoing to ensure that we're spacing those wells appropriately. We're not going to drill wells where we have interference issues. So we're trying to maximize the reserves we get on a per well basis. So down spacing is not something that we've built into our program. However, the staggered completions between the Wolfcamp A and B is something that certainly we're going to do to ensure that we're there's no risk of communication between a Wolfcamp A and a Wolfcamp B well. Great. And then just a follow-up to both the inventory update in the Wolfcamp B and then just potentially some color around well performance. You've provided a lot of detail in the past on the Wolfcamp A 30 day rates and I think you've mentioned a type curve of up to 900,000 MBOE for your short laterals. I was curious how the Wolfcamp B wells looking in comparison to that? And as we think about kind of the inventory added from 650 to 800, was that based on delineation of additional wells on your acreage in the basin? Yes. The incremental wells was additional delineation. And the Wolfcamp B with respect to the Wolfcamp A is while it's the Wolfcamp B is prospective and delivers some better than cost of capital returns. It's not as prolific as the Wolfcamp A in either the Midland Basin or the Delaware. However, we think there opportunities to continue to improve the recovery from the Wolfcamp A. We're doing, as I said, on each of our target intervals more modeling to try to get to the point where we can optimize the Wolfcamp B. Thank you very much. Our last question today comes from Brian Singer of Goldman Sachs. Please go ahead. Thanks. Good morning. If we look at on slides 29 32, you highlight your focus acreage in the context of your broader large Permian position. Can you update us on strategically your plan for the acreage within the Delaware and Midland that are not in the focus acreage either to delineate to sell or to hold whether those priorities change in a low oil environment? And then also your level of interest and realistic opportunity to expand your acreage positions in the Permian proximate to your focus acreage? So we have no intention not to we have no intention to sell any of our acreage that's designated non focus right now. What the difference between our focus areas and not is the fact that our focus areas are those that we feel like we could put in development mode today or are in development mode today. The ones that are not considered focused right now are the ones that are still in appraisal mode. And we consider those areas to be perspective, but in the interest of trying to ensure that the infrastructure dollars that we spend are used and we get the benefit of that quicker, we're being pretty disciplined about where we spend and how we develop. So the non focus areas are ones that we're preparing for development in the future. We at this point today don't have any acreage that we would consider for sale today. We have some acreage that falls way down to the priority list and are things that we would get to years years from now. So that at some point we might take a look at, do we try to trade that to move into areas where it better fits where we're currently operating. In terms of continuing to appraise, we still have the Central Basin platform where we haven't been drilling as of yet, many unconventionals. I think we have a couple drilled, but we still have that to assess. So the good thing is that we have a tremendous inventory. The challenge with that is we are at we're always looking at ways to try to accelerate, but to do it in a way that's not value destructive. And so we're trying to moderate our pace and trying to ensure that we have things fully evaluated before we move to development. Great. Thanks. And my follow-up is on the midstream marketing business. Can you just talk to what you all see as the ongoing cash potential there? And then how you're thinking about that business strategically? Yes. I think that it's still in a heavy and basically it's supportive of the Permian business. I mean that's really what it does. And they're still really spending more money than they're taking in because they continue to build out to support the production business. People talk it doesn't make any sense to us given our financials position to do anything to increase the fixed charges against the Midstream against the rest of the business by selling debt like instruments called MLP units that go against it and increase our fixed charges. A lot of fixed charges are okay in $100 oil, but not so much fun in the $50 environment. And I think that's people miss that that you just like interest. So I think on the cash flow generation right now it basically is neutral to maybe slightly negative as they continue to build out either gas plants or pipelines. At some point I think it will probably generate just $400,000,000 $500,000,000 a year in cash flow free cash flow. But I think we're probably a year or 2 from that. Great. Thank you very much. This concludes today's question and answer session. I'd like to turn the conference back over to Mr. Degner for any closing remarks. Thank you everyone and for joining our call today. And I know it's a busy season. Thanks. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.