Earnings Call: Q3 2015

Oct 28, 2015

Good morning, and welcome to the Occidental Petroleum Corporation Third Quarter 2015 Earnings Conference Call. All participants will be in a listen only mode. 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 Q3 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 Sandy Lowe, Executive Vice President and President of Oxy Oil and Gas International and Chris Stavros, Chief Financial Officer. In just a moment, I will turn the call over to Vicki Hollub. 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 could cause results to differ is available on the company's most recent Form 10 ks. Our Q3 2015 earnings press release, the Investor Relations supplemental schedules, our non GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com. I'll now turn the call over to Vicki Hollub. Vicki, please go ahead. Thank you, Chris. Good morning, everyone. Despite the current environment of low and volatile product prices, our oil and gas segment has been operating well in all of our core assets. Our 3rd quarter average daily production increased to 689 1,000 BOE per day from last year's 595,000 BOE per day, an increase of 16%. Our core assets continue to drive production growth with an increase of 39,000 BOE per day from Permian Resources and 50,000 BOE per day from Alhosin, which reached full capacity in September. We expect Alhosin to produce 60,000 BOE per day in the 4th quarter. Our capital and operating costs have continued to decline as we focused our development program and curtailed activity where current product prices do not support further investment. We continue to make progress to optimize our portfolio as a part of the company's strategic review to focus on our core assets in the Permian Basin and the Middle East. We're selling our assets in the Williston Basin and continue to evaluate our positions in non core assets in the Middle East with the objective of minimizing our activity and exposure. Construction of the ethylene cracker has progressed well and is on schedule to start up in early 2017. Our principal goal this year is to adjust our business to the current environment of low commodity prices. We're targeting our operating cash flow to cover our dividend and capital investment at realized oil prices of $60 per barrel while continuing to grow our production. We'll achieve this goal through deploying our capital and operating cost savings into further production and cash flow growth, driven mostly by our Permian Resources business unit and the start up of Al Hosen. While we don't believe current price levels are sustainable over the long term, we've taken aggressive actions to manage the business for a downturn that may last longer than market participants expect. During the boom period from 2010 to 2014, the industry experienced substantial cost inflation, Royalties and government takes on new projects increased. Service prices, labor costs and overhead all increased as well. There is ample room for us to continue to lower our cost, which will enable us to return the business to profitability at lower prices. These adjustments may be difficult in the short term, but our discipline on reducing costs will lead to a healthier business over the long term. Through our separation of California Resources in 2014, we reduced our annual G and A budget from $1,800,000,000 to 1 point $5,000,000,000 as we move the corporate headquarters to Houston. Over the course of this year and into 2016, we expect to see continued reductions in our corporate overhead with a more focused company and will reduce our total G and A spending to about $1,200,000,000 in 2016. 2 years ago, we began working on strategic initiatives to focus our company and improve its profitability. We've continued to make progress on those initiatives. We reached an agreement to divest our Williston Basin assets and expect the transaction to close in the 4th quarter. To our curtailed spending in the basin and the nature of unconventional assets, our production declined about 25% quarter over quarter when annualized. We expected the production to continue to decline given our limited capital investments in the basin. Over the past several years, our efforts at appraising and delineating our acreage in the Permian have provided a large inventory of future development locations that are economic at oil prices under $60 a barrel. With ample takeaway capacity and an extensive midstream business of gathering lines, storage and gas processing, our economies of scale and deep inventory in the Permian Basin make it our top priority for capital allocation for the foreseeable future. Simply put, acreage in North Dakota, whether it's Tier 1, 2 or 3 cannot compete with our position in the Permian. We continue to pursue strategies to minimize our activities and exposure in our non core operations in the Middle East and North Africa, which include Bahrain, Iraq, Libya and Yemen. As a result of these actions, we took impairment charges in the Q3 for our positions in Iraq and Libya. We will comply with our contract terms as we reduce our exposure through negotiations with our partners and host governments and expect capital investments to decline in 2016. These actions will improve the profitability and cash flow of our Middle East business as we focus on our core assets in Abu Dhabi, Qatar and Oman. Our capital spending in the 3rd quarter declined by about $300,000,000 and will continue to decline. As we capture price savings from suppliers and improve the efficiency of our operations, we're able to do more with less spending. We expect to exit this year at a quarterly spending rate of $1,100,000,000 to 1 point $2,000,000,000 If product prices remain at current levels, our 2016 capital program will be less than the current rate. We're in the midst of our annual budgeting process, and we'll provide more detailed guidance on our 2016 program in January. Over the last few years, we've undertaken multiple long term investments to drive cash flow and earnings growth. These projects include the Alhozan gas project, the ethylene cracker joint venture, our export facilities in Ingleside and gas processing infrastructure in the Permian Basin. Capital spending on these investments declined by about $500,000,000 in 2015. We expect these investments to decline by about $300,000,000 in 2016 $400,000,000 in 2017 as the projects are completed. This decline in capital spending on committed projects gives us a lot of flexibility in setting our capital budget for 2016. Our Permian business continues to execute a focused development program on low cost wells with high oil content. Permian Resources continues to drive down capital cost through improved execution in drilling and well completions. Our production exceeded expectations due to reduced time to market and better than planned well performance. In the Q3, Permian Resources achieved daily production of 100 and 16,000 BOE per day, a 6% increase from the 2nd quarter and a 51% increase versus the prior year. Oil production increased to 74,000 barrels per day, a 4% increase from the previous quarter and a 72% increase from a year ago. In the Q4, we'll drill and complete about 50 horizontal wells. We are currently operating 12 rigs in the basin and evaluating our needs for our 2016 program. In the Delaware Basin, our Wolfcamp A 4,500 foot well cost decreased by about 45% from the 2014 cost of $10,900,000 to a current cost of 6.3 dollars We reduced our drilling time by 24 days from the 2014 average of 43 days to 19 days. We've lowered our completion cost per well and optimized the density of our clusters and proppant loads. We've used some of our cost savings to upsize our frac treatments to drive higher productivity. Our well performance continues to be strong. We placed 21 wells, horizontal wells on production in Wolfcamp A benches in the Q3. The leased eight forty-11H well achieved a peak rate of 17.90 BOE per day and a 30 day rate of 15.28 BOE per day. Additionally, our Betty Lou 1013H well achieved a peak rate of 17.11 BOE per day and a 30 day rate of 13.10 BOE per day. We drilled the Betty Lou horizontal well in only 15 days. Both of these wells produced around 80% oil. In the Midland Basin, we made similar improvements in well cost and drilling days in our Wolfcamp A wells. We reduced the cost of these 7,500 foot horizontal wells by 30% from the 2014 cost of $9,200,000 to a current cost of $6,600,000 We reduced our drilling days by more than 60% from 46 days in 2014 to 18 in the Q3. In Big Spring, which is our new area of the Midland Basin, we brought the Yonge A-two thousand one hundred and twenty four well online in the 3rd quarter at a peak rate of 16.11 BOE per day and 30 day rate of 12.37 BOE per day. We also brought online the Adams 4,201 well at a peak rate of 16.98 BOE per day and 30 day rate of 14.95 BOE per day. Both wells are producing at about 90% oil. These Wolfcamp A well results have been outperforming our initial type curves for this emerging play in Howard County. We're continuing to lower our cost structure. Since the Q4 of 2014, we've reduced our operating cost per barrel by 18% and expect to make further progress in lowering our costs through the end of this year and into 2016. In our Permian EOR business, we continue to lower our drilling cost and manage the operations to run our gas processing facilities at full capacity. With a resilient base production and low capital requirements, the Permian EOR business continues to generate free cash flow at low product prices. In the Q3, we started Phase 1 of CO2 injection at South Hobbs, where we expect to develop low cost oil production at about $10.60 per BOE. In closing, we delivered strong production growth from our core assets in the Q3. We continued to execute on our strategic initiatives to focus our oil and gas business around our core assets in the Permian Basin and the Middle East. We'll continue to execute a focused development strategy in 2015, and we'll pursue additional step changes in well productivity and cost structure. Strong production growth from our Permian Resources business along with a high volume, a low capital 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 businesses. Now I'll turn the call over to Chris Stavros. Thanks, Vicki, and good morning, everyone. Today, I'll cover our Q3 results, discuss the actions we have taken that led to the non core charges we took in the quarter and close by providing some guidance on the remainder of the year while highlighting key initiatives that will improve the company's financial strength going forward. We generated core income of $24,000,000 for the Q3 of 2015, resulting in diluted earnings per share of $0.03 a decrease from $0.21 a share in the Q2 of 2015 and compares to earnings of 1 $0.34 per share in the Q3 of last year. Our net reported results for the Q3 were a loss of $2,600,000,000 or $3.42 per diluted share. Our 3rd quarter reported results includes non cash after tax net charges of approximately $2,600,000,000 Our quarterly core results were negatively impacted by lower worldwide oil and NGL prices, which fell by nearly 7 $3.50 a barrel respectively in Q3 of 2015 compared to the Q2 of this year. U. S. Natural gas prices improved slightly up about $0.15 per Mcf from the 2nd quarter. Our 3rd quarter capital spending was about $1,200,000,000 down 18% from the 1,500,000,000 dollars in the 2nd quarter and down 30% from 1st quarter levels. We continue to ramp down our capital program focusing our development activity primarily in core areas of the Permian Basin with the intent of curtailing or eliminating spending, which is less competitive and imprudent in the current product price environment. Our heightened focus around capital spending is centered on growing our oil production volumes and more importantly our operating cash flow. Despite the reduction in this year's capital program, efficiency gains and our increased focus around our inventory of drilling opportunities continues to drive growth in oil volumes and cash flow at our Permian Resources operations. Permian Resources grew its oil production 72% in the 3rd quarter adding 31,000 barrels per day compared to the year ago period with total production of 116,000 BOE per day representing growth of 51%. Production from Permian Resources improved by 7 1,000 BOE per day sequentially above our previous guidance. As I mentioned earlier, we took after tax impairment and other non cash charges approximately $2,600,000,000 in the Q3. Oxy follows a successful efforts method of accounting where we review our proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of the oil and gas properties may not be adequately recovered, such as when there's a significant drop in the futures price curve. As futures price curve. As of September 30, the futures curve for product prices had declined sharply yet again and we recorded an after tax impairment of $1,300,000,000 related to our domestic gas properties and our oil and gas assets in Libya. As Vicki mentioned, we continue to make progress in our efforts to optimize our portfolio. In the Q3 of 2015, we entered into an agreement to sell our Williston operations, which have been classified as held for sale and resulted in an after tax impairment charge of approximately $500,000,000 The sale is expected to close later this quarter and we expect to receive net proceeds equivalent to approximately 8 times free cash flow after required capital for facilities and safety. Additionally, and as part of our effort to focus our capital on opportunities to generate higher financial returns, we intend to minimize our capital allocated to non core areas. As a result, we recorded an after tax non cash charge of $760,000,000 for operations in Iraq. We expect to continue oil liftings out of the country in the Q4. Our exit from these non core areas will create a more focused domestic oil and gas organization and mitigate our exposure to areas we deem as having higher political risk. In addition, we expect our capital spending levels to decline and our financial returns to improve as we generate savings from associated overhead reductions that have yet to be captured. As Slide 21 shows for the 1st 9 months of 2015, our operations in combined Williston, Iraq and Libya had total production of 45,000 BOE per day and generated an aggregate cash flow after capital deficit of approximately $260,000,000 with Brent oil prices of about $56 a barrel. For the full year of 2014, when Brent prices averaged about $100 a barrel, these assets had an even greater cash flow after capital deficit of $340,000,000 Some of this free cash flow savings could be redirected to our higher return core operations in the Permian Basin. Turning to specific business segments. Oil and Gas after tax earnings for the Q3 2015 were $17,000,000 about $90,000,000 lower than the Q2 of 2015 $880,000,000 lower than last year's Q3. Almost all of the impact of the change in year over year earnings is due to lower product prices. For the Q3, total company oil and gas production volumes averaged 689,000 BOE per day, an increase of 31,000 BOE in daily production from the 2nd quarter and 94,000 BOE per day from last year's Q3. Total company oil volumes were 436,000 barrels per day in the 3rd quarter, 54,000 barrels per day higher than the year ago period for an increase of 14%. Total domestic oil and gas production averaged 332,000 BOE per day during the Q3 of 2015, about flat sequentially and 17,000 BOE higher a year over year basis with all of the increases increase coming from Permian Resources. The increase in Permian Resources was partially offset by lower production from our midcontinent natural gas assets where we have ceased drilling activity. Domestic oil production was 204,000 barrels per day during the Q3 of 20 15, about flat with the Q2 and up 22,000 barrels per day or 12% from the year ago period. We captured approximately 4,000 BOE per day of incremental NGLs and natural gas volumes in the Q3 due to the installation of compressors and gathering lines in the Delaware Basin. International oil and gas production volumes averaged 357,000 BOE per day during the Q3, up 32,000 BOE per day sequentially and 77,000 BOE per day on a year over year basis. Production from Alhosin was 50,000 BOE per day in the 3rd quarter, an increase of 32,000 BOE per day from the per BOE declined 8% from the 2nd quarter level of $12.10 per BOE due to higher production volumes, lower surface and downhole maintenance costs and lower energy costs. DD and A for the 3rd quarter was $15.39 per BOE compared to $16.06 per BOE during the 2nd quarter. Taxes other than on income, which are directly related to product prices were $1.20 per BOE for the 3rd quarter compared to $1.85 for the 2nd quarter and $2.45 per BOE for the full year of 2014. Chemicals generated pre tax core earnings of $174,000,000 in the Q3 of 2015 versus $136,000,000 in the 2nd quarter and $140,000,000 during the year ago period. The most recent quarter results were above our previous guidance and benefited from higher chlorovinal production volumes, lower ethylene costs partially offset by lower vinyl sales prices. Midstream pretax core earnings were $31,000,000 in the 3rd quarter compared to $84,000,000 in the Q2 of 2015 and $115,000,000 for last year's Q3. The most recent quarter results reflected lower marketing margins due to the narrowing of Midland and Gulf Coast differentials and an increase in crude oil supply, lower premiums in the Gulf Coast. The lower marketing margins were primarily were partially offset by higher pipeline income from both domestic and foreign pipelines and higher seasonal margins from power generation operations. Turning to our cash flow. Operating cash flow for the 3rd quarter of 2015 was approximately $1,000,000,000 which was about $200,000,000 higher than the 2nd quarter. Higher oil and gas production volumes combined with better realized oil prices relative to benchmark prices positively impacted our operating cash flows during the Q3. Working capital changes were minor during the Q3 as our drilling activity and capital spending stabilized from higher levels at the end of last year. We continue to ramp down our capital spending with total company expenditures for the Q3 of 2015 of $1,200,000,000 a sequential decline of $300,000,000 from the 2nd quarter. Total company capital expenditures for the 1st 9 months of 2015 were 4,400,000,000 dollars which is running a little lower than our full year 2015 capital budget of $6,800,000,000 during the 1st 9 months of 2015 with Permian Resources expenditures comprising roughly half of the total oil and gas outlays and the remaining $800,000,000 of capital split nearly evenly between chemicals and midstream. We paid cash dividends of $1,700,000,000 during the 1st 9 months of 20 15. Continued growth in our operating cash flow combined with capital reductions and other cash cost savings should allow us to achieve our goal of being cash flow neutral after capital spending and dividends at oil prices of roughly $60 a barrel. Our cash balance at the end of the 3rd quarter was $4,300,000,000 and our long term debt to capitalization ratio was 19% at the end of the period. The worldwide effective tax rate on our core income was 90 percent for the Q3 of 2015. Beyond the efficiency improvements that have lowered our capital spending, we've also started to recognize the benefit of a reduction in our SG and A costs. Reducing our SG and A is an initiative we began working on ahead of the spin off of California assets and operations. Prior to the spin, our SG and A was approximately $1,800,000,000 per year. Upon completion of the spin off late last year, we had reduced our SG and A costs by about $300,000,000 or roughly 17%. While our workforce has come together and made a huge effort to reduce costs, we are still in the early stages of recognizing these benefits. During 2015, we expect to reduce our SG and A by another 10% or roughly $150,000,000 We have taken a number of actions and will continue to pursue other initiatives that will serve to reduce our SG and A costs both this year and next and as highlighted on Slide 30. We expect these initiatives to reduce our SG and A by at least another 10% and expect our total SG and A costs to decline to roughly $1,200,000,000 in 2016. This represents a 1 third reduction in our total SG and A costs compared to levels before the California spend. Looking ahead to the Q4, domestically we expect production from Permian Resources to be about 118,000 BOE per day. Production has been a bit lumpier as we have increasingly moved to pad drilling and we expect total Permian Resources production to exit the year in excess of 120,000 BOE per day. Continued growth in the Permian combined with declines in our Mid Continent natural gas production and adjusting for the sale of the Williston assets should result in total U. S. Production between 310,000, 320,000 BOE per day. We expect our international production to be between 365,000 and 375,000 BOE per day depending on volumes from Iraq and assume 60,000 BOE per day of production from Alhozan. Price changes at current global prices affect our quarterly earnings before income taxes by $30,000,000 for $1 per barrel change in oil prices and $7,000,000 for $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 Q4 2015 exploration expense is anticipated to be about $20,000,000 tax. We expect our Q4 2015 pre tax chemical earnings to be about $130,000,000 Our Q3 midstream earnings will continue to be principally impacted by Midland to Gulf Coast oil price differentials, which have narrowed since the Q3, as well as weak NGL prices. We expect net cash proceeds from asset sales in the 4th quarter, which includes our assets in the Williston Basin to be approximately $650,000,000 The worldwide effective tax rate on our core income was 90% for the Q3 of 2015. This rate reflects the mix of domestic source book losses and foreign sourced income, which is taxed at much higher relative rates. Simply put, it cannot utilize U. S. Tax losses to offset higher foreign taxes. Based on continued volatility in the mix of pre tax income sources, we at environment with $4,300,000,000 of cash on hand, roughly equal to our annualized capital outlays. We continue to grow our production volumes cost efficiently and despite the decline in capital spending. We will continue our disciplined approach towards cost control, improving our capital efficiency, focusing and allocating our capital on only the highest return opportunities. Our capital spending run rate has been cut by more than half compared to year ago levels and we expect to save at least $300,000,000 as a result of initiatives to lower our SG and A costs. I'll now hand the call back over to Chris Degner. Thank you, Chris. And Emily, could you please open up the line for questions? Thank you. We will now begin the question and answer session. Our first question is from Evan Kaleo of Morgan Stanley. Please go ahead. Hi, good morning guys. Your Permian Resources production again beat guidance. You're making progress on cost efficiencies and you highlighted as your top priority in your slides. But it's also one of the pieces of your portfolio where you can dial activity up and down. Talk about how you balance those factors when you're considering 2016 Permian activity levels in the current environment? Yes, Evan. As Chris said that our committed capital is coming down, but we still do have some committed capital in 20 16. So what we'll do is balance our Permian Resources business with the capital requirements elsewhere. As you know, we're trying to reduce our capital requirements the ability to swing it up and down. We're working on several scenarios that we could be ready to implement depending on what market prices are in 2016. Let me follow-up there. I mean, when you mentioned the potential mean and non core asset sales, I mean, does that imply that the larger interest sell down remains back burnered? And on the on your G and A guidance, does that that these announced assets are sold as well? You're talking about the Middle East? Yes, in the MENA, sorry. Currently, we're looking at certainly exiting some of the non core properties in the Middle East and ramping down activities in some of those areas that we're not going to exit. So that will certainly impact some of our SG and A costs. We expect those to go down as well as some of our operating costs. So that will be a benefit to us. And getting back to the resources question that you had previously, we do expect to in all of our the scenarios that we're looking at to continue to grow production from our Permian Resources business. Right. Yes. This is Steve. The answer to your question is no. We really haven't baked in the Middle East situation with the decline. So basically what we see now is this is what we've said for next year's run rate or costs. We expect to continue to work on this as the portfolio changes. Right. And the non core by focusing on the non core sales in MENA, I guess, I was saying that also imply that the larger interest sell down in that piece of the portfolio remains backburner given the current environment. Is that fair? Yes. Well, the countries have gone from being flushed with cash to being cash users just to fund their own situation. So it's not likely that they're in the mood basically they're selling things, they're not buying things right now. Right. And maybe if I could just one more question, Steve. Can you discuss what drove the Bakken asset sales given your ample liquidity position? I mean is that is there a general comment there on your view of prices in the asset market that you see better opportunities to sell versus buy where you've highlighted that you potentially be a buyer in Permian? Yes. We sold the Bakken assets for about $600,000,000 as opposed to reported number, which I don't know where that came from. Anyway, we sold sort of about $600,000,000 We just can't see a situation where we would invest in it, given what we have in the Permian. And so, I mean, it's really a statement that says, okay, we just don't see how it competes for capital inside the company in any reasonable price scenario that we can come up with. We could use generated it's always generated negative cash flow or at best neutral. It's declining about 1,000 barrels a day a quarter. So a year from now, it'd be 13,000 or so a day, just doing the arithmetic. So we don't see how the value increases over time. For us, the $600,000,000 we could run 4 rigs in the Permian Basin for a year and with this money or 5, somewhere in that range and generate more production than we would get out of the Bakken with the 6 $100,000,000 box. So pretty easy decision to say, well, you could hold on till it goes up in price. By the time it goes up in price, you might be making 8,000 barrels a day. So I just don't know when it's going to go up. We believe we received a fair price given the prospects for the for it under our management. Great. I'll leave for somebody else. Thanks. Thanks. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thanks. Good morning, everybody. On the Middle East folks, the non core areas that you're talking about, I'm trying to reconcile the $60 breakeven number with exiting some of these non core areas. And I guess my question is, are these areas currently negative free cash flow? And if so, could you quantify what you think the delta would be in the event of an exit and if that's already assumed in your $60 breakeven assumption? $60 is just a cartoon. This is basically based on our current situation. The businesses are not cash flow positive. Doug, we showed you on the slide that I pointed out, Slide 21, that under various oil pricing oil price scenarios, a higher oil price scenario of last year or lower prices this year, we're still running the combination of those assets are still running a sizable cash deficit after capital. So, yes, you were sort of had higher capital in a higher price environment, but still you weren't generating enough money to really see a free cash flow positive event? So we haven't gone back and recomputed what exactly the breakeven would be. So we don't really know whether it's $55 or $60 Okay. So maybe I could just flip in a macro question there. So what can you update us on what you're doing in Iraq currently? Because obviously your partner understanding is Iraqis are asking folks to kind of slow down investments. So what are you actually seeing on your asset? And I've got a more Oxy specific follow-up, please. Sandy can answer that, I think. The Iraqis have asked us to slow down investment and the infrastructure investment that we need to really take advantage these fields, that is the responsibility of the government has not taken place. So, the production is just trucking along in a fairly stable amount, but not anything that would excite us. Okay. My final one, if I may, is, again, I want to go back to the $60 breakeven, Steve, because if you look at this current quarter, obviously, you're still burning through a fair amount of cash and the oil price clearly is not $60 is substantially below that. Although that's not our base case, what would you do in the event that you have another year of sub $50 oil because that would imply you basically burn through all your cash at this rate? I don't think we burn through all the cash. We must maybe we have a different model. But anyway, basically, if you run through all the numbers, I think we'd look at it at the time. But as we cut back on the non core assets, more cash be generated. And so you could have you could drill fewer wells in the Permian if that were necessary. We're not counting on You'd be getting these residual things done, right. Yes, we just we would bring the capital down lower. There's more savings as we go in this. And so we're not exactly sure where we are in this process. So I think as we go through this next year, the large the cracker basically ends at the end of this next year, the spending on that ends. Some of the stuff in the midstream ends at the end of next year, Al Hosen will be because all the capital will be spent. There's a little bit of capital in the beginning of the year for crew quarters as I recall. And so now all that ends, the capital will naturally decline and the production goes up. So whether it's $60 or $55 we don't really know right now. But we'd expect as we go into 2017 clearly that the capital program would be significantly less than could be significantly less than next year even. Got it. I'll let someone else jump on. Thanks everybody. Thank you. Our next question is from Phil Gresh of JPMorgan. Please go ahead. Yes. Hey, good morning. Just first question just on the CapEx side. How would you think about what sustaining capital requirements there are today given all the productivity that you've been seeing in the Permian? And how would that relate to the $60 breakeven for dividend coverage as you move forward? I would assume that that's generally underlying you're seeing some improvement there, but any color you could provide would be helpful. Yes, Phil, we're continuing to see improvements in the Permian Resources business. And as we've just said and said previously, our Resources business is our swing business with respect to capital. We can we have the ability to ramp up and ramp down. But we do see a scenario if oil prices improve a little bit for us to be able to continue to grow resources and to manage some of the capital spend and international down, so that we can be cash flow neutral and grow resources slightly in 2016. And part of that is due to the fact that we're continuing to see improvements in our drilling and completion operations. And if you look at kind of the targets that if you go back and look at our Q1 targets for our drilling and completion activity in Permian Resources, We've actually adjusted our targets a couple of times because our teams keep outperforming and beating our previous targets and setting new best rates. So currently, 2 of the things that we're dealing with in terms of uncertainties is how much better can we get and also what will prices be. So we're running both of those scenarios and we think we have opportunity to continue to improve. Okay. Follow-up question just on the midstream business. In this lower for longer type of environment, how would you think about the earnings power of that business? I know it's volatile quarter to quarter, but if you think maybe on an annualized basis and you obviously have a couple of different sub businesses within that, but any thoughts you have there would be helpful. It's a difficult business to estimate. There's this it's a hodgepodge of different businesses. It's got a power business. It's got a it's a standard transmission business. It also has holds the capacity to ship oil out of the Permian. And right now, there's more excess capacity in the basin to ship oil because people assume that oil would the production would go up and it's clearly not for the industry. So we're paying demand charges essentially for that. And that's what's eating into the profitability. So it's really a difficult number to quantify because you have to really have an idea about these demand charges and what's going to happen with that. It has a probably underlying earning power in the $300,000,000 or so $1,000,000 area, but there's a lot of volatility on these demand charges. Sure. And is that $300,000,000 including the benefits we'll get from sulfur at Alhosin? Probably not. Probably doesn't include it. Okay. Last question. Sulfur mineral hose and is also makes predicting oil prices easy. I mean, the price of sulfur can move $50 a ton overnight. Sure, understood. And that's a lot of tons. In the Middle East, you had a significant reduction in the cash operating costs in the Q3. Any color on the big drivers and the sustainability of that? We've had a cost improvement program going for a long time. And we have recently been able to make some breakthroughs on that with various vendors. And it's just focusing on it. And same as in the Permian, we've everybody in the company is focused on more profit per barrel, less cost per barrel. But I think to be I mean, the way the accounting works in the Middle East on a production sharing contract, the company always bears all of the costs, all of the operating costs. So when oil prices are high, you get fewer barrels to cover that operating cost. And at higher and lower oil prices, you got a lot more barrels to cover the exact same operating cost even if they don't change. So I mean that's it's a little Combination. Yes, it's a little different than comparing to the U. S. Or something like that, Because you always have all of the 100% of the operating costs essentially there. And so and whether you produce 10,000 barrels a day or 20, net operating cost is the same. Great. Okay. All right. Thanks a lot. Our next question is from Tim Rezvan of Stearney GCRT. Please go ahead. Hi. Good morning, folks. Happened in the Q3 and kind of how we should think about the trajectory of that into happened in the Q3 and kind of how we should think about the trajectory of that into 2016? Yes. We've continued to improve our operating cost and basically we're focusing on the OpEx in Permian Resources and Permian EOR because in Williston, we had some high OpEx there just because of the fact that our production was lower. But in the Permian, what we're doing is, we see the biggest opportunities in our resources business where initially we had difficulty pumping from the deeper unconventional wells. We were trying to use either ESPs or beam pumps. With both of those, there were issues because of the depth of those wells and the initial very high volumes that then becomes lower volumes pretty quickly in the life of the well. So now we've gotten to a point where we understand that better. We're addressing that better. We're actually ensuring that we install the lift that's the right kind of lift for the full life cycle of the well, so that we don't have high initial repair costs. So that's part of what's driving down our OpEx in the U. S. And Permian EOR, those guys are continuing to optimize what they do with respect to well maintenance. They have a lot more wells over there. So they've been able to reduce quarter over quarter the cost per barrel in the EOR business by improving the well service rig performance and improving how they deal with replacement of pumps and things like that, the materials they use and what they're doing there to extend the life of the wells. So we do expect continued improvement in both of those business units. Yes. I think the short answer is that the Williston operating costs went up and it dragged the average up. Okay. Okay. I appreciate that comprehensive answer. Next question, I guess, on the repurchase program, your average shares outstanding were down 3,300,000. You only spent 50,000,000 in the Q3. So I guess that's a factor of the timing of your 2Q activities. Should we expect in a $50 or sub $50 oil environment that you will kind of run it at a much lower pace on the repurchases? Or I guess what's your philosophy on that? Well, if I had more confidence in the oil price, we'd be more aggressive in the share repurchase. At this point, it depends on 2 things, sort of calculation of what's in the stock, which is favorable to repurchase and to calculate and how fearful we are about the volatility in the oil price. So I think the fear overcame analyst reports, so it generates enormous fear. I appreciate that commentary. Thank you. Our next question is from Edward Westlake of Credit Suisse. Please go ahead. You clearly shouldn't read analyst reports. Clearly, I just read the headlines. Okay. No worries. Question on the Middle East. I mean, you talk about ramping down activities, maybe non car asset sales. I mean, of the countries that you list there, Bahrain looks like one which might have a buyer in the sense of the production as opposed to those other countries. I mean, is that what you're talking about? No. Selling assets or just reducing activity? Just reducing activity, I think is a way say it. There's a significant amount of receivables or whatever you want to call it, where we produce the oil and gas, but haven't been paid in some of these places. And basically, you're effectively building up a liability over time. And basically, we can't afford to do that currently. And so we'll reduce the activity until we can catch up with that accrual, if you will. It doesn't show up in a balance sheet. It's simply a difference between production and liftings. And then on Block 9, you said on the last call, we'll look for a contract extension that's at least as good as what we could get back in the Permian. Any progress on how the other side of the table view that? It's a difficult negotiation, I think is the best way to describe it. And ongoing. And ongoing. I think it will go on until all these things go on until there's no more time left. And as a reminder, just in terms of now as we get down to end 2015, what the actual drop dead date is or? It's in December. Okay. And then just moving to the midstream, the Ingleside cracker and the export facility for LPGs should be fairly profitable Right. Okay. Mid to second to third quarter, is that Right. Okay. Mid to second to third quarter as I recall. Okay. Good. So CapEx comes down, cash flow goes up and that helps balance. And the same thing when the cracker is the end of be done the end of next year and then the cash flow really in 'seventeen. Same sort of dynamic except probably larger. Okay. Thanks very much. Our next question is from Jason Gammel of Jefferies. Please go ahead. Yes. Thanks very much. I was hoping to get a little more understanding on what led to the write down in Iraq because my understanding was that it was an acceptable place to invest because you never really had a lot of capital And if you're reducing investment activity even more and you're still lifting oil, does that imply that you got into a situation of big arrears with the government that you don't think you'll actually ever be able to get paid back? There's clearly I really don't want to get into a discussion about the contract terms there, except to say that in theory, you got your money back on a small profit pretty much as you spent the money maybe a quarter or 2 off and that really and that hasn't exactly happened. Okay. I think that's a fair enough explanation. I think I get what's going on there. Now at the risk of picking nets here, the Permian resource production overall in the quarter, obviously very good. But it did seem to be a little more swung towards NGLs in gas and away from oil than what I would have normally expected. Vic, you talked about moving to pad drilling and making it a more manufacturing process, which makes it more lumpy. Is that the explanation for that or is there something else going on? In addition to the pad drilling, we were able to capture some stranded gas in the last quarter and we were able to put that online and through processing and that's what drove some of that. So should we still think about this as 5,000 Permian Resources on a move forward basis with recognizing there could be variation from quarter to quarter? There's going to be lumpy production, so there it could vary from quarter to quarter. But in terms of the differential with the gas with respect to oil this time, it was again, it was due to a one time event to get some gas production on that we didn't previously have on. As you reduce the capital, fewer rigs, the effect of this lumpiness is more obvious Because you got all you got these rigs working in one place and if you have if you're in 5 places, well, it sort of averages out. But if you as you reduce the number of rigs that work, the effect of the lumpiness from a quarter to quarter basis is a lot more obvious. So you might expect some more you'll be able to see it in a normal environment with a somewhat higher rig count, you wouldn't see it really just smooth out. Yes. Okay. That makes sense to me. Okay. Thanks very much, folks. Thanks. Our next question is from John Herrlin of Societe Generale. Please go ahead. Yes, thanks. With respect to the Permian Resources Unit, are you doing can you describe what you're doing in terms of the well completions that are different? Or are you doing anything materially different than your peer group? On the well completions, we continue to try to find the exact mix of when to use slickwater, when to use hybrid fluid systems and also what the cluster spacing should be, what the volume of the proppant should be. So what we've done is we've experimented a little bit trying to ensure that we get all that optimized. And some of that, we have enough data that we can optimize it and we know what to do. For example, in cluster spacing, we can take pressures that we see during the frac jobs and kind of get to a point where we know what that should be for a given area. So it's still really the proppant size and the fluid volumes and fluid types that we're experimenting with. We did some experimentation with using some of the sleeves and things like that versus plug and perf. And we found that while the sleeves are somewhat effective in being able to isolate and frac, they're not as good when we try to flow the wells back because of the sleeves actually cause variations in the flow back, which drops out proppant, causes cleanup issues later. So we're moving more toward now ensuring that what we do is, we'll have an optimum impact on not just recovery, but the life of the well. So I think it's just still experimenting with those things that others do. We're waiting for our seismic. We should be done acquiring that in the Villa Draw area soon, and we'll be processing that, and we hope that will lead to actual more improvements next year. Great. Thanks. With your EOR operations in the Permian, at current prices, how much free cash flow are you generating from that? At current prices, I can tell you I can give you what we were generating. We were generating a couple of $1,000,000,000 when prices were in the $90 environment. Okay. Probably about Probably cash margins of about $20 a barrel or so. Okay, that's great. Last one for me. You took a big impairment on gas. Did you really kitchen sink it in terms of pricing? We hope so. Okay. Thanks, Steve. Our next question is from Jeffrey Campbell of Tuohy Brothers. Please go ahead. Good morning. My first Steve, as you are doing your business in the Middle East, are you seeing any tangible signs of stress or second thoughts regarding OPEC's current production strategy by any of the countries in the region? If they had stress, they wouldn't share it with us. I think that's fair to say. What you do see, of course, is a lot of talk about raising money and that sort of thing. So if you want to view that as stress, you can. But they all say that they're aligned, whatever that means. Okay. Thank you. You provided helpful color on non core asset sales in MENA. As you continue to high grade your portfolio, how do you think about Colombia? Vicky can answer that. In Colombia, we recently signed an agreement with the government to do to implement a couple of more waterfloods in Colombia. We see that as our asset there is the opportunity to continue to maintain our production. We'd like at some point to be able to grow the production a little bit. But currently, we have a great relationship with the government and with Ecopetrol. We have a team down there that's incredibly efficient, knows the area very well and our operating teams are very good there. So we see it as a place that we've been there for over 30 years. We'd like to be there continue to be there another 30 years. The country itself has some opportunities outside of what we currently have. And certainly, any opportunity that comes up in Colombia is something we'd want to take a look at. Okay, great. And my last question is thinking about Permian capital allocation, with the results that you showed in East Midland, is it possible that capital in the Midland Basin can increase relative to the Delaware in 2016? Currently, we were thinking that we would move more activity to the Delaware Basin. But you're right, our Midland Basin team has been performing so well and especially with this Big Spring area in Howard County, the performance there and in Merchant is getting to the point where those wells are really becoming very competitive with what we're doing in the Delaware. Okay, great. Thank you. Our next question is from Brian Singer of Goldman Sachs. Please go ahead. Thank you. Good morning. Wanted to dig in a little bit on the broader Delaware and Midland Basin well performance to understand whether the strong wells you highlight here on Slides 1315 are trending relative to your broader acreage and drilling program and whether they're reflective of what we should expect going forward. I'm not sure if it's apples to apples, but if we look at the BOE a day per 1,000 feet of lateral you have for the 2015 averages, they both on slides 1315 appear to be below what was reported for the first half and the second quarter presentation. And so what I'm trying to get to is whether the specific wells you're highlighting here with much better rates are reflective of the wells we should expect going forward for specific portions of your acreage, whether they're good averages, we should assume for your broader acreage or the highlights of your best wells? I think the 2015 average is not exactly representative of what we'll see going forward, but it's indicative of a trend that we'll see. What you're talking about, the trend downward was certainly impacted by the PEC state and the Buzzard state, because initially we had incredible rates from the PEC State. It was about 2,400 BOE per day, 24 hour rate for the PEC State, about over 2,000 barrels a day for the Buzzard state. Those wells were 2 of our best wells in the Delaware Basin. What we're trying to do and the reason we're still in an answer to John's question, the reason I said we're still trying to tweak things and work things is that we feel like we should have the ability to continue to increase our performance per well. And we're still we think that with the seismic, we'll be able to figure out what made the PEC state and the Buzzard state so good. And then we'll target trying to hit either the interval that was so good in there or the area or types of areas like that. And so that's exactly the reason for the seismic is to try to determine whether their reservoir, whether there are areas that are driven by reservoir quality or characteristics that we can move toward in our development program toward the end of 2016, because by the time we have the seismic process and evaluated, it would start not start impacting the program till the end of next year. But that's exactly what it's designed to do is look for whether or not those wells were in a particular area that's limited or whether it's broader and we just aren't getting the chemistry of the frac jobs right or the location within the interval. That's not to say we're not having great wells. We're having great wells, but we do want to continue to improve and we'd love to see more of those types. That's very helpful. And my follow-up is also on Slide 13 where you have the nice map of your focus acreage. Can you just refresh us on how many acres that focus area represents and what it would take and any plans to turn some of the other acreage we see there of Oxy into focus acreage? Well, we have, as you know, 1,500,000 net acres, in the unconventional business. And our inventory of wells really the appraisal wells that we've shown you that 8,300 well inventory was really based on an appraisal of about half of that. And then our development areas, we're trying to keep at an even lower acreage percentage than that, because what we're trying to do is ensure that we completely build out as we build our infrastructure. So probably the Barula Draw area represents an acreage, at least what we're really concentrating on developing, probably 2 or 3 pods that would total up to be about 40,000 or 50,000 in the Delaware Basin. Great. Thank you very much. Our next question is from Guy Biver of Simmons. I had a follow-up question on some of the earlier questions around capital spending flexibility into 2016. And I apologize if I missed this earlier, but can you just help us understand the amount of capital spending currently being dedicated to the portion of your MENA program that you deem as non core? Just trying to understand the opportunity set for I think it's $400,000,000 Okay, thanks. And then Al Hosan, ramping up faster than expected on the production front, can you discuss that outperformance? And then also can you address the contributions during the quarter from a cash flow perspective? And really trying to understand the timing of the cash flow contributions there and what the peak cash flow contributions are in this environment? Obviously, it's difficult to predict given the sulfur exposure and the less transparency on some of the pricing. Yes, I think the cash has normal settlement with it. So the production is actually doing pretty much the way it said. I mean the 60,000 is what we've talked about. Cash flow before capital settles like others and so it was a little back end loaded in the Q3. So there was less of it in the Q3 than we'll see in the 4th quarter. There's some capital that needs to be spent in the Q4 and into the Q1 for some things which will use some of the money. The business just depends on really oil prices, the volatility in the business. So I think we're talking about 300 $1,000,000 of free cash and then it could be as much as $1,000,000,000 depending on the on oil prices sort of in the 70s. Okay, great. That's helpful, Steve. And then last one for me. You mentioned exiting 2015 with Permian resource production of around 120,000 barrels a day. So over on over $2,000,000,000 of CapEx this year, you're obviously growing that business very significantly. Do you have an estimate of the level of spending that could hold that 120 flat through next year? Just trying to understand how that compares to the $2,000,000,000 plus you're spending this year that's driving considerable growth? We're not discussing among ourselves as to what that number might be. So yes, so under $1,000,000,000 I think, But I don't know what we don't know whether it's $700,000,000 or $800,000 or $900,000,000 because things keep getting better. That's why we're sort of slow in giving you these answers because we just don't know and we don't want to mislead you. Got it. Understood. Thanks. This concludes the question and answer session today. I would like to turn the conference back over to Chris Degner for any closing remarks. Thank you, Emily, and thanks to everyone for participating. Have a great day. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.