Earnings Call: Q4 2015

Feb 4, 2016

Good morning, and welcome to the Occidental Petroleum Corporation 4th Quarter 2015 Earnings Conference Call. All participants will be in listen only mode. Mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead, sir. Thank you, Carrie. Good morning, everyone, and thank you for participating in Occidental Petroleum's Q4 2015 conference call. On the call with us today are Steve Chazen, OXY's President and CEO Vicki Hollub, President and Chief Operating Officer Jody Elliott, President of OXY Domestic Oil and Gas Sandy Lowe, President of Oxy Oil and Gas International and Chris Davros, 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 Q4 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 of our website at www.oxy.com. I'll now turn the call over to Vicki Hollub. Vicki, please go ahead. Thank you, Chris, and good morning, everyone. Despite sharp declines in structure as well as executing our strategic review. I'd like to share highlights of our 2015 achievements. 1st, Permian Resources growth exceeded our expectations as we reached our 2016 growth target of 120,000 BOE per day. This was a year ahead of our original plan. We increased production by 35,000 BOE per day for a year over year growth rate of 47%. Alhosin reached full production capacity and delivered an average of 35,000 BOE per day of production last year. In total, we grew our production by 81 1,000 BOE per day, which was approximately 14% higher than 2014. We reduced our cash operating cost by 14%, achieved SG and A savings of 16% and cut our average drilling and completion cost in Permian Resources by 33%. As a part of our strategic review that we launched at the end of 2013, we sold our Williston Basin properties and made significant progress in our effort to exit noncore areas in the Middle East, including Iraq and Yemen, while also reducing our exposure in Bahrain. This will lead to lower capital spending in the region. Construction of the OxyChem Ethylene Cracker joint venture is on schedule and on budget for start up in early 2017. We reached a settlement with the Republic of Ecuador for approximately $1,000,000,000 of which we've collected $300,000,000 and expect to receive the remaining proceeds in the coming months. And we exited 2015 with $4,400,000,000 of cash on our balance sheet. Now I'd like to reiterate our strategy and cash flow priorities. I want to emphasize these have not changed. Our overall strategy is to invest in projects that generate long term value, achieving returns well above our cost of capital while maintaining a conservative balance sheet. Our assets in Colombia, IS and D in Qatar, Block 9 in Oman, Permian EOR, Dolphin and OxyChem provide significant earnings, require relatively low maintenance capital and provide free cash flow in this low price environment. Our most recent addition to this list is our Alhozan Gas Project, which is a 30 year joint venture with ADNOC in Abu Dhabi. And the role of our Permian Resources business, the role it will play in our strategy is to provide quick production growth as needed to support our cash flow. Our top priority for use of cash flow is and always will be the safety and maintenance of our operations. Our second priority will continue to be funding the dividend. 3rd is allocating capital to our growth projects. The next priority cash would be for potential asset acquisitions and or share repurchases as opportunities arise. Commodity businesses are inherently volatile. We maintain a strong balance sheet to not only survive but to take advantage of potential opportunities. We'll invest our capital prudently and maintain a flexible program as we maneuver through this low price cycle. As I mentioned earlier, we made great progress last year on lowering our operating and SG and A cost. We plan to further reduce these costs during 2016 and expect that the financial impact of executing on initiatives from our strategic review will be evident through lower cost and capital in the coming months. In terms of our capital program for this year, our plan is to carefully reduce our activity levels without harming the strong progress we've made with our growth prospects. We'll fund only those opportunities that exceed our rate of return hurdles. Our 2016 capital program is expected to range from $2,800,000,000 to $3,000,000,000 This represents a nearly 50% reduction compared to the $5,600,000,000 spent during 2015. This capital plan should approximate our expected cash from operations at current commodity prices. The majority of this year's spending program will be allocated to the Permian Basin and to completing long term projects in our chemicals and midstream businesses. Our capital run rate is expected to be higher during the Q1 and falling in subsequent quarters as committed project capital winds down. In Permian Resources, our drilling activity be highly focused on areas in both the Midland and Delaware Basins where we have existing infrastructure, allowing us to achieve higher returns. Our level of activity will help preserve efficiency gains achieved over the past year. In Permian EOR, we'll take advantage of reduced cost for labor and materials to modify and expand existing facilities to increase our capacity to handle and inject greater quantities of CO2. This will enable us to implement additional CO2 projects. These projects will have longer duration and a typical production response time of 1 to 2 years. This will result in a modest increase in capital for our EOR business versus last year. Chris will provide greater detail on this year's capital program in a few moments. Despite the reduction in capital spending, we expect overall company production from our core assets to grow 2% to 4% on average compared to 2015. Our core assets are pro form a for the expected divestments in areas we plan to exit, including the Pianz Basin, Iraq, Yemen and Libya, along with lower exposure in Bahrain. The full year contribution of production from Al Hosn and the start up of Block 62 in Oman should add approximately 35,000 BOE per day of production this year. Overall, domestic production is anticipated to decline slightly through the year, primarily due to declining natural gas and NGL volumes caused by the curtailment of drilling activity in our gas assets in late 2014. We expect a modest increase in production from Permian Resources versus last year and will hold our Permian EOR production flat. Turning to our oil and gas reserves. The good news is that we managed to keep our proved producing reserves essentially flat in 2015 due to our development programs and improved recovery from some of our Permian Resources wells. We continued to see strong performance from our Permian Resources drilling program, which enabled us to replace 2 14% of our resources production, excluding net sales and revisions. Our development programs added 149,000,000 BOE approved reserves. Our year end 2015 proved reserves totaled 2 point $2,000,000,000 BOE consisting of 79% proved developed reserves, up from 71% proved development reserves at the end of 2014. Our liquids reserves comprised 74% of our total proved reserve base. In summary, while the macro environment remains challenging for the industry, we delivered strong production growth during 2015. We lowered our cost structure and continued to execute on our strategic review. Although we expect commodity prices to gradually recover, we've set our plan to be more aligned with the lower price environment. We're fortunate to have a great set of assets with relatively low base decline rates that provide us with enormous flexibility for our capital. We believe our continued focus on returns, improved cost structure and strong balance sheet provide us with the opportunity to emerge from the current cycle as a stronger company relative to our peers. I'll now turn the call to Chris Stavros for a review of our financial results and further details on this year's capital program. Thanks, Vicki, and good morning, everyone. As Vicki indicated, we continue to have 3 main objectives over the long term: generate rates of return on invested capital that are well above our cost of capital, sustainability and growth of our dividend and moderate volume growth of the business. With regard to returns, we need to strike a balance between managing our capital within the very low commodity price environment and also ensuring that our business is properly positioned for recovery. We don't believe that a depleting or shrinking business over the long haul can maintain high rates of return and part of our model is to balance the need for growth and the safety and sustainability of business while maintaining attractive returns. Our focus is generating attractive returns and making investments through the cycle in the long term in long term assets that provide us with stable cash flow to see us through during weaker periods. Despite the low price environment, we've been able to realign our business to focus on our core areas, reduce our overall cost structure through capital efficiencies, lower our total operating costs and SG and A, while significantly increasing production in our Permian Resources operations. In the Middle East, North Africa, the Alhosin gas project was brought to full capacity by mid year and we also move forward with exiting some of our non core assets in the region and eliminating the capital associated with those businesses. In terms of our capital spending, we adjusted our program last year in response to the sharp decline in product prices with our full year 2015 expenditures coming in at $5,600,000,000 a 36% reduction from the prior year. Despite this reduction in our spending, we grew our total oil and gas production volumes by 14% from last year. As we look into 2016, we remain focused on allocating our capital where we have the best returns, including winding down our capital commitments for longer term projects. We estimate our 2016 total capital program to be between $2,800,000,000 to $3,000,000,000 and no higher than $3,000,000,000 This year's capital budget represents a nearly 50% reduction in our overall spending compared to last year and only a third of what we spent in 2014. The Oil and Gas segment is expected to comprise approximately 2 thirds of our overall spending this year compared to nearly 80% last year. We expect the majority of our total 2016 spending will be allocated to our domestic oil and gas business, primarily in the Permian Basin with roughly 21% to be spent in Permian Resources and about 17% going towards Permian EOR. We expect this year spending in our international oil and gas operations to be about half the level of outlays seen in 2015. Capital allocated toward our Middle East, North Africa oil and gas business is expected to be roughly 21% of total spending with the majority going towards Oman. The year over year decline of about 56% in the Middle East is partly the result of our exit from several countries and our plan to run a more focused business targeting our core areas. The remaining third of this year's overall capital spending is expected to be split nearly equally between our chemical and midstream businesses of which $500,000,000 of the total is capital committed for projects that we expect to be completed by the end 2016. Turning to our results, our core financial results for the final quarter of 2015 were a loss of $129,000,000 or $0.17 per diluted share, a decrease from both the year ago quarter and also the Q3 of 2015. The decline in core results is nearly all attributable to weaker commodity prices. Reported results for GAAP purposes for the Q4 were a loss of $5,200,000,000 or $6.78 per diluted share. The reported results include $5,400,000,000 of net after tax charges mostly related to asset impairments. Oxy follows the 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 curve. During the course of the year, the carrying value of our operations in the Middle East, North Africa was reduced by $4,500,000,000 with $3,000,000,000 of this taken in the 4th quarter. This action was due to a combination of our exit from non core areas and the reduction of our exposure to unprofitable projects in the region in an effort to focus the business on improving profitability. Impairments of our domestic properties amounted to $2,200,000,000 for all of 2015 and approximately $870,000,000 for the 4th quarter. Almost half of the total year impairments in the U. S. Were due to the exit of non core assets in the Williston and Ponce Basins. The other half related to the reduction in the futures price curve as well as management's decision not to pursue activity associated with certain non producing acreage. In addition, we took a charge of $520,000,000 in the 4th quarter associated with our Century Gas Processing plant as a result of Sandridge's inability to provide volumes to the plant and in order to meet their contractual obligations to deliver CO2. Oil and Gas Core after tax results for the Q4 of 2015 were a loss of $189,000,000 and down $206,000,000 a sequential quarterly basis. For the Q4 of 2015, total company oil and gas production volumes from ongoing operations averaged 671,000 BOE per day, 75,000 BOE per day higher compared to the prior year period and essentially flat with 3rd quarter volumes. This excludes production from the Williston assets for all periods. Our 4th quarter 2015 worldwide realized oil price of $38.68 per barrel fell by $9.10 a barrel or 19% compared to 3rd quarter realizations of $47.78 a a barrel and down 46% compared to the prior year's 4th quarter. Domestic oil production was 190,000 barrels per day during the 4th quarter, sequential quarterly increase of 2,000 barrels per day and an increase of 19,000 barrels per day from the year ago period. Production in our Permian Resources business grew to 118,000 BOE per day during the Q4, up 40% from the prior year. Volumes were also able to grow sequentially despite weather related outages. Oil and Gas cash operating costs were $9.95 per BOE for the Q4 of $2,026.57 per BOE for the total year 2015 compared to $13.50 per BOE for the prior year. The reduction in costs was seen in both our domestic and international operations and reflects decreased activity in down home maintenance and a lower overall cost structure. The DD and A for full year 2015 was under $16 per BOE compared to $17 per BOE seen during 2014. Taxes other than on income, which related to product prices were $1.32 per BOE for the 12 months of 2015 compared to $2.45 per BOE in the prior year. 4th quarter exploration expense was $13,000,000 Chemicals 4th quarter 2015 pretax core earnings were 116,000,000 dollars compared with 3rd quarter earnings of $174,000,000 $160,000,000 in the year ago quarter. The sequential quarterly decrease primarily reflected weaker chlorovinals demand and lower PVC prices, which negatively impacted margins. This is partially offset by higher caustic soda prices and lower energy costs. Midstream pretax core results were a loss of $45,000,000 for the Q4 of 2015 compared to income of $31,000,000 in the 3rd quarter. The sequential decline in the 4th quarter was mainly attributable to lower oil marketing and power generation margins. The marketing results continue to reflect lower margins due to the narrowing of the Midland and Gulf Coast differentials as the increase in oil supply lowered premiums in the Gulf Coast. The Power Generation business reflected lower seasonal spark spreads and higher maintenance costs in the 4th quarter. Looking at our 12 months cash flow for 2015, we generated $4,800,000,000 of cash flow from continuing operations before working capital. Working capital changes was a use of $880,000,000 the majority of which occurred during the first half of the year. Capital expenditures for 2015 were $5,600,000,000 a 36% decline from the $8,700,000,000 we spent in 2014. We received over $700,000,000 of net proceeds from activity associated with asset divestitures and acquisitions, which included 4th quarter proceeds of approximately $600,000,000 for our Williston assets. In the second quarter, we completed a bond offering issuing senior notes for which we received net proceeds of roughly $1,500,000,000 We indicated at the time of the offering that the proceeds would be used to partially pre fund some of our debt maturing in the first half of twenty sixteen. Earlier this week, we used cash on hand to retire $700,000,000 of our senior point 4,000,000 of our shares for approximately $600,000,000 Our long term debt to capitalization was 22% at year end. The worldwide effective tax rate on our core income was 29% for the Q4 of 2015 and 86% for the total year. Looking into 2016 and as we show on Slide 23 in the handout, we started the year with $4,400,000,000 of cash. During the Q4 at $42 WTI, we generated operating cash flow before working capital of approximately $900,000,000 or roughly $3,600,000,000 on an annualized basis. Every dollar change in the oil price impacts our cash flow by about $100,000,000 annually. We expect to receive an additional $900,000,000 of cash this year from our settlement with Ecuador of which we have collected $300,000,000 to date approximately $300,000,000 of proceeds from asset sales during this quarter. Earlier this week, S and P reaffirmed our A credit rating along with a stable outlook. Turning to our oil and gas production. For purposes of year to year comparison in terms of providing guidance for 2016, volumes are pro form a and exclude assets with either already or plan to divest or exit from this year. These assets would include Williston and Piance in the U. S. And Iraq, Yemen, Bahrain and Libya and the Middle East and North Africa. On this same store sales basis, we expect our full year 2016 production to grow 2% to 4% or in the range of 570,000 to 585,000 BOE per day compared to about 560,000 BOE per day last year. In the U. S, we have ceased all gas drilling activity and will focus our capital in the Permian in an effort to grow our oil volumes and is justified by attractive returns. We expect our total domestic oil and gas production to be in the range of 270,000 BOE to 285,000 BOE per day in 2016, which includes oil production growth of about 4% and partly offset by modest declines in gas production. More than 2 thirds of our domestic production volumes are expected to be oil. Production in Permian Resources is expected to average 123,000 BOE per day during the first half of twenty sixteen, an increase of 8% compared to the same period last year. Permian EOR volume should remain relatively flat at about 145,000 BOE per day while providing stable cash flow. In our core international areas in the Middle East and Colombia, we expect production to increase to roughly 300,000 BOE per day this year compared to 268,000 BOE per day in 2015 as a result of a full year's contribution from Alhosin as well as the startup of gas production from Block 62 in Elmont. In terms of production for the Q1 on a reported basis and unadjusted for pending divestments or exits, we expect our total production to be in the range of 620,000 BOE per day. Permian Resources volume should increase about 3,000 BOE per day sequentially to 121,000 BOE per day. Production in the Middle East is expected to be negatively impacted in the quarter by about 15,000 BOE per day due to scheduled maintenance turnarounds at both Dolphin and Alhosin. Our DD and A expense for oil and gas is expected to be approximately $15 per BOE during 2016. The combined appreciation for the Chemical and Midstream segment should be approximately $675,000,000 for the year. Cash operating costs for the domestic oil and gas business should be about $13 per BOE during 2016, about $1 per BOE lower than last year's level for our ongoing operations. Exploration expense for the year is estimated to be about $75,000,000 pre tax with $25,000,000 of that anticipated in the Q1. The realignment of our business helped us make strong progress in lowering our SG and A costs last year by more than $200,000,000 In the current environment, we expect to reduce these costs by at least another $100,000,000 into 2016. Price changes at current global price affect our annual operating cash flow by about $100,000,000 for every dollar per barrel change in WTI. A swing of $0.50 per 1,000,000 BTUs in domestic natural gas prices affects annual operating cash flow by about $40,000,000 We expect our Q1 20 16 pretax chemical earnings to be about $140,000,000 Our chemical operations are essentially a margin business and so while our costs may decline as a result of lower energy prices, prices for the chemical products we sell continue to be driven by demand. Using current strip prices for oil and gas, we expect our 20 16 domestic tax rate to be at 36% and our international tax rate to be about 55%. I'll now turn the call over to Jody Elliott, who will discuss activity around our Permian operations. Thank you, Chris. Today, I'll review 2015 highlights from Permian Resources and Permian EOR and provide guidance on our program for 2016. 2015 was a very successful year. Permian Resources achieved our 20 16 growth target ahead of schedule by reaching 120,000 BOE per day in November. We achieved this milestone by leveraging our advancements in geoscience, reservoir characterization and integrated planning to deliver better wells in less than half the time and at 2 thirds of the cost versus 2014. Throughout 2015, we reduced our OpEx cost by over 20% by improving field reliability, productivity and optimizing our surface and subsurface engineering. Our Permian EOR segment generated free cash flow in a low price environment and had its best safety metrics of all time. Turning to Permian Resources. In the 4th quarter, we achieved record production of 118,000 BOE per day, a 40% increase versus the prior year. Oil production increased to 76,000 barrels per day, a 2% increase from the previous quarter and a 49% increase from a year ago. Winter storms end of December impacted total quarter production by approximately 1300 BOE per day. For the full year, the business achieved production of 110,000 BOE per day, a 47% increase versus the prior year. Permian Resources continues to drive down capital costs through improved execution and drilling and well completions and reduced time to market. For each of our core development areas, we continue to monitor both our early time well performance and cumulative production to ensure our development approach is providing maximum value. In addition to improving individual well performance, we optimized field development value through pace, well sequencing, flowback designs to reduce clean outs and fluid handling cost, artificial lift designs to maximize long term production and facility plans to ensure maximum utilization over time. Our Delaware Basin well performance continues to be strong. We placed 19 horizontal wells on production in the Wolfcamp A benches in the 4th quarter. We continue to increase well performance by optimizing the density of our completions and proppant loads and drilling longer laterals. For example, the Priest E-1H well achieved a peak rate of 16.59 BOE per day and a 30 day rate of 12.47 BOE per day. The H. B. Morrison B12H achieved a peak rate of 14.87 BOE per day and a 30 day rate of 11.76 BOE per day. In New Mexico, we're delivering more productive wells by increasing our proppant concentration and reducing cluster spacing. For example, the 2nd Bone Spring, Cedar Canyon 27, 6 produced at a peak rate of 24.98 BOE per day and a 30 day rate of 17.50 BOE per day at an 82% oil cut. In the Delaware Basin, our Wolfcamp A 4,500 Foot Well Cost Decreased by About 45 percent from the 2014 cost of $10,900,000 to a current cost of $6,200,000 We reduced our drilling time by 26 days from the 2014 average of 43 days to 17 days. In our new area of the Midland Basin, we brought the Adams 4,231 Wolfcamp A online in the 4th quarter at a peak rate of 2,167 BOE per day and a 30 day rate of 18.41 BOE per day. We also brought online the Merchant 1409A well at a peak rate of 13.45 BOE per day and a 30 day rate of 11.32 BOE per day. Both wells are producing at over 80% oil cut. In the Midland Basin, we made similar improvements in well cost and drilling days in the Wolfcamp A formation. We reduced these costs of the 7,500 foot horizontal wells by 35% from the 2014 cost of $9,200,000 to a current cost of 6,000,000 dollars We reduced our drilling days by 63% from 46 days in 2014 to 17 days in the Q4 of 2015. Across Permian Resources, we're continuing to lower field operating expenses through optimized water handling, lower workover expenses and better downhole performance. Since the Q4 of 2014, we've reduced operating cost per barrel by 26% and expect this trend to continue this year. In our Permian EOR segment, we continue to lower our drilling cost and manage the operations to run our gas processing facilities at full capacity. With resilient base production and low capital requirements, the EOR business continues to generate free cash flow at low product prices. We've lowered our cash operating expenses by 21%, driven mainly by lower downhole maintenance and injection costs. Phase 1 of CO2 injection at South Hobbs has continued and we have a production response sooner than expected. We expect Phase 1 production to peak in 2020. We expect Phase 1 and Phase 2 to develop 28,000,000 BOE at just over $10 per BOE. Additionally, we started a pilot project in South Hobbs testing the residual oil zone. It has the potential to add about 80,000,000 barrels of reserves. These residual oil zone reserves can be added between $3 $7 per barrel of development costs. Given the current oil price, we will focus investment to achieve 4 goals: accelerate geoscience, characterization and modeling programs to enhance recovery, well performance and field economic returns minimize base decline and set up major growth programs in both resources and EOR, focus on game changing technologies and applications and accelerate continued improvement in both execution and cost. 1 of the key drivers of our gains in well performance has been integrating our technical understanding of the subsurface to optimize well completions. Slide 41 illustrates our inventory of Permian Resources well locations by breakeven prices. By improving both well cost and performance, we continue to make more inventory economically viable in a low cost environment. For example, we transferred about 700 locations from above the $60 per barrel hurdle to under $60 per barrel. Furthermore, we moved 3.50 locations under the $40 per barrel hurdle. We expect to continue lowering the hurdle point on our inventory as we move forward. With current oil prices, our activity in 2016 will focus on core locations that require minimal infrastructure investments. In addition, we will gather high priority appraisal data to support future development and initiate seed projects for long term growth in EOR. Over the first half of this year, we will reduce our rig count to between 24 drilling rigs in the Permian. Our technical staff and engineers will focus on long term projects, enhancing base production, preparing full field development plans to ramp up activity when oil prices recover. We're taking appropriate steps to preserve the efficiency gains achieved and are well positioned for growth as prices recover. I'll now turn the call back to Chris Degner. Thank you, Jody. We'll now open it up for questions. Our first question comes from Evan Kallio of Morgan Stanley. Please go ahead. Hey, good morning guys. My first question is one of your key or primary peers you cut the dividend today 2 thirds after repeated defenses. I know your balance sheet is superior yet the macro has changed, it underpins their decision. Can you discuss how you perceive your dividend sustainability through the cycle and are there leverage levels or other metrics that would result in a change in your current priorities? Yes, Evan. To begin, I'd like to refer you to Slide 23. What we've done really is planned our programs over the next few years to, based on actually the strip prices, although we actually believe that prices ultimately will be higher than the strip. We don't expect prices to really recover much until very late this year or maybe early next year and recover only to slightly above the curve. But based on the cash that we have on hand and what we project our situation will be over the next few years, we do expect to be able to make it through this cycle and get back to reasonable oil prices and secure our dividend throughout this entire process. We're organizing our plans and our activities around that. And the good thing about our portfolio is we have the flexibility to ramp up and down as necessary to ensure that, that would meet our priorities. And as we said, the top priority is just the maintenance and safety of our operations. And then we're going to pay the dividend and we've got the cash to do that. And generally, the way we look at it is we can use our cash flow from operations to cover our our cash flow from operations, we'll certainly use the strength of our balance sheet to cover that. So we don't see a threat to our dividend going through this cycle. Thank you. And I have a related follow-up. The irony of a downturn, I think, is opportunities maybe the best when liquidity is the lowest. And so any commentary that you have on the asset market and whether your views in the macro raise the hurdle for acquisition or change your views on what's potentially attractive such for instance, a more longer life longer cycle resource versus a shorter cycle shale resource? Yes. I'd say that we never want to get away from what we truly are as a company. And that's what I stated in here is that we're very much a, on the oil and gas side of the business, an EOR type company and a company that for the longer life reserves like Alhosin that provide cash flow that would be like Alhosin and Dolphin. So what we'll be looking at is are the assets that have the longer life reserves. We're very proud of our shale position and we think that the work we've done over the last few years has certainly proved it up to be an asset that we want to take full advantage of. But currently our shale production is less than 20% of our total company production. And we don't really want it to ever be much higher than that because we feel like to have the asset base we have, that's part of the reason we'll be able to make it through this cycle with our current load declines. So that's the sort of asset we'll be looking for. Appreciate it. Thank you. The next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thanks. Good morning, everybody. Good morning, Vicki. Good morning. Vicki, I wonder if I could follow-up on Evan a little bit there. I'm looking at Slide 7, which is the kind of classic slide you put up about the priority for the use of cash. You've talked about optimism and a rebound in oil prices, but you still have growth capital ranked higher than share buybacks and acquisitions. I guess my question is, you've kind of missed an opportunity here with the separation of California Resources to reduce your dividend burden by buying in your stock, which was the original plan, obviously, extenuating circumstances. But in the event of a rebound in oil prices, why does Growth Capital still rank above reducing the dividend burden? And I've got a follow-up, please. Let me point out, I'm very happy that we did not buy back shares. The $6,000,000,000 is going to really be part of what helps get us through this cycle. And so I think we're fortunate to have what we the cash that we have on the balance sheet now and that's really what's protecting, helping to protect the dividend. But I would view the last two items on the list, the share repurchases and acquisitions to be right now, although we show 1 above the other, those we view as equally important. And what we're going to look for is the opportunities that arise through this cycle. We're not going to immediately go out and buy and repurchase shares. But what we want to do is look at how the cycle evolves over the next quarters, maybe even next year and a half or so and look for opportunities and before we commit to share repurchases. But I would view those as right now both on the same level of priority. Chris, do you have anything to add? Yes, Doug, I'll just follow-up on what Dickie said. I think what you said is right. I think in addition to that, we're going to have to look at it on a return basis. And clearly, the goal over time will be to reduce the share count as it will help us fund the dividend and fund growth of the dividend over time. So I do still view we still view share repurchases as important over time and a reduction of the share base over time. So we'll look at opportunities opportunistically to go ahead and do that. And it's just going to sort of depend on where things are visavis the stock price and other opportunities that may come up for capital. Okay. I appreciate the answer, Chris. My follow-up is also referencing the slide deck on Slide 41, showing the economics of your drilling backlog at different oil prices. I guess my question is that it would seem that a lot of companies are looking to drill their very, very best assets in the worst commodity environment. So I'm just curious as to why does that make sense if you're so optimistic on a recovery because obviously the offset of the alternative would be to allow production to decline, but would also imply you're preserving value, which I think one of your competitors talked about the other day and I'll leave it there. Thanks. I'll start that, but then let Jody add on to it. We actually were fortunate to be in the process of some development programs in key areas where we're kind of into a manufacturing mode. We already have the infrastructure we're kind of into a manufacturing mode. We already have the infrastructure installed. And so that's what's making our current program so economical and what we feel like is the right thing to continue to develop during this cycle. And Jody can add to that. Yes. Building on Vicki's comment there, this is some of our best areas, but we really are leveraging more than just the best rock. It's the infrastructure that we've already invested in. There's good rock in all of those tranches of inventory. It's just the maturity of our development plans in some of those areas aren't quite as far along. So we would not develop those until we get those development plans further matured. And that's one of the focus areas we have this year is to move more of that inventory to the left side of that chart. Okay. I appreciate the answer. Thanks. Our next question comes from Ed Westlake of Credit Suisse. Please go ahead. Yes. Good morning. Just again a follow on, I think, to your answer about the types of assets in shale. So from that, I'm taking that you're more interested in some of the long lived assets. Maybe just give a little bit color as to where you think these opportunities may lie? One of the things that we'd like to continue to consider is adding to our position in Permian EOR. We have the infrastructure there that really can't be duplicated by any other companies. We've got the 12 gas processing plants, 1900 miles of pipeline and operate 2 source CO2 source fields. So we have the infrastructure in place to continue expansion of our EOR operations in the Permian and that would be for us one of our higher priorities. In addition, we see opportunities in Colombia to continue our work there. We, this past year, signed an agreement to develop another couple of waterfloods there. We think that's going to be a good opportunity for us going forward. And in addition, in our 3 core areas in the Middle East, those are the kind of opportunities that we would continue to look for. Okay. And then a totally separate question. At the back of the deck, you've got that great chart on, I should find the slide on Slide 41 that Doug mentioned about the inventory. Obviously, there's a big flip between $50 $60 And then if you look at the colors of the bars, you've got a lot of Bone Spring acreage, Spraberry and then the Wolfcamp B. Maybe just and this is based on 4Q costs. Hopefully, those are the ones that you identified, that $6,000,000,000 in the Wolfcamp and $6,000,000 in East Midland. What are the biggest levers you think about taking that inventory that works at $60,000,000 down to 50? I think one of the biggest levers is multi bench development, ensuring that field development plans allow us to economically develop more than one good bench at a time. And so that's part of the redeployment effort of our technical staff to figure out multi bench to drive better utilization of our infrastructure costs in those areas. That will be the biggest thing to move them to the left. I mean, you mentioned reduced cluster spacing in some of those Bone Springs wells. I mean, is there a lot more technology that you can still apply? I think there is. Good to know. I'll keep in touch. Our next question comes from Phil Gresh of JPMorgan. Please go ahead. Hey, good morning. Good morning. The first question is just on the guidance. There's obviously a lot of moving pieces here in the production side. But Chris, just with respect to the 1Q, the 6 $20,000,000 to $630,000,000 I believe you said that, that would exclude the asset sales, the domestic asset sales, but it does not have anything contemplated in there for the Middle East asset exits. So I want to clarify that and then just generally ask how that's going and how you would expect that 72,000 barrels a day of non core Middle East to roll off as the year progresses? Sure. Thanks, Phil. On the guidance, just to make it comparable for you to reconcile it, I mean, the way I would think about it is that you've got the Piance in the U. S. That will exit or be sold and closed this quarter. So that will come out of the system. And then there's production in there for Bahrain as well. So combined, I would tell you that it probably amounts to about 50,000 to 60,000 BOE per day on a like for like basis that to adjust for sort of our ongoing core production for the guidance that I gave for the full year of 'sixteen. So that would be the reconciliation. Okay. And then just as you think about more broadly all the Middle East assets, how do you see that progressing through this year? Currently, we're continuing with our operations in Bahrain and we are working with our partners there to lower our exposure. But in Iraq, we're progressing with the terms of the exit according to our contract terms. So we should be winding down in Iraq and that's going to be transferred to 1 of the national oil companies. So we will be out of there by, we're hoping, mid year. Yemen, that's pretty much our contracts have expired and we're reducing our exposure in the one area that we currently have and expect to be able to exit that by mid year as well. So everything is progressing. In Libya, we're not quite to the point where we have been able to develop a specific exit strategy and specific steps because of the uncertainties around that process with the government. But we have stopped our capital investment in Libya and we're only spending the funds necessary to maintain the operations safely. Got it. And then Chris, my follow-up is just on the balance sheet. Understand the willingness to protect the dividend. Is there a level of debt, whether it's debt to cap or debt to EBITDA? Obviously, it's always been fairly conservative on the balance sheet and for good reason. Just wondering if there's a level where you get less comfortable? Well, whatever that level is, we don't plan to take it there. So that's one of the reasons that we maintain a strong balance sheet that it allows us to pay the dividend and not overly concerned about it. And I think our view is that we sort of take a measure of offense on this and sort of view ourselves as competitively advantaged as an investment vehicle within the sector. So you keep a strong balance sheet with low debt because you're a dividend payer and having a lot of debt as a company in the sector, just the 2 don't mix. So that's sort of how we view it. Okay, fair enough. Thanks. Our next question comes from Ryan Todd of Deutsche Bank. Please go ahead. Thanks. Good morning. Maybe if I could follow-up a little bit on the capital outlook over the next couple of years. You highlight $500,000,000 of committed capital in 2016 that will roll off year end 2016. Is there any offset to this that's set to ramp into 2017? Or should we expect on an apples to apples budget, does the budget roll by $500,000,000 into 2017? And would this likely be would you likely fill that gap with accelerated activity in the U. S. Onshore? Really, in 2017, our only committed capital is the $100,000,000 And so we do expect the $500,000,000 to be reduced to 100,000,000 dollars And the rest of our capital program will be based on what we see with respect to oil prices, but nothing committed other than the $100,000,000 and the maintenance capital that we'll need to allocate. Okay. And maybe I guess maybe one follow-up to that. As you're going to 2 to 4 rigs in the Permian, you said for the second half of the year. Can you talk a little bit and I guess at a high level you've provided us in the past with what you felt was kind of a maintenance CapEx number for yourself. Do you have an updated view on what your maintenance CapEx is generally as an overall business in terms of holding production flat and maybe a similar number to what you think is a challenge because our teams keep improving so much. The efficiency gains they've made over the last couple of years has just been incredible. And Jody and I were talking about that this morning. And the reason we gave the range of 2 to 4 is we used to think it would take more than 4 rigs to offset our decline, but we're certainly convinced now that with the efficiency gains we're having and particularly the way that Jody and his team are starting to develop the fields, we think it could be less than that. And Jody, I'll let you provide some additional color on that. No, that's clearly correct, Vicki. Every day, our teams amaze us with new drilling records, new production records. So predicting that exact rig count to keep production flat kind of changes month to month. But I guess is roughly the goal to size your activity levels from the middle of this year to kind of the Permian resources flat? Is that roughly what you're trying to target? That level would probably flat to slightly increasing. Great. Thank you. Our next question comes from Roger Read of Wells Fargo. Please go ahead. I guess I'd like to probably go down the path, some of the other guys have as well. On the thinking about the drilling efficiencies and following up on the answer to the last question, 2 to 4 rigs maybe allows you to stay flat. Is it a function of more above ground, below ground or a combination of the 2 that's driving this? And I'm thinking of the Slide 33 where you showed drilling days and best is still significantly better than average. And then the comments earlier about this I think it was specifically the benches being able to develop those as a way to get the cost down. What's the way we should think about it maybe for 2016 and then beyond 2016? It's really about all the things you mentioned. It's drilling performance, it's well completion performance. I think the biggest gains we've had this year is the integration of our subsurface understanding into that execution activity as well, keeping wells in zone, keeping them in the sweet spot, engineering frac designs differently, optimizing cluster spacing, optimizing sand concentrations, all those things I think lead to being lead us to being able to do more with less, not just drilling days and drilling cost. And then as you think out beyond this year, what do you think gives you the greatest upside potential, not just the bench that you mentioned earlier? Is there anything else we should think about? I mentioned multi bench. I think that's one. I think the other is really optimizing infrastructure, both our internal infrastructure and working with others to take advantage of infrastructure in the 2 different basins. Okay, great. And just my follow-up, unrelated, Al Hosn, I was wondering if we could get a little more of an update on just how that's performing relative to your expectations. The turnaround coming in Q1, I assume, is a normal part of the start up process and maybe how we should think about it latter part of this year on forward? Yes. This is Sandy Lowe. We're in the warranty shut shutdown, which is common for all these projects. And we had produced over nameplate for several weeks before the shutdown. We expect the year to give us slightly over nameplate as an average after the shutdown, of course. And it's performing very well. Great. Thank you. Our next question comes from Paul Sankey of Wolfe Research. Please go ahead. Hi, good morning, everybody. Again, going back to the efficiencies, you said fairly clearly that it was reliability, productivity, optimization. Can you first try and strip out how much of the performance improvement has simply been lower oil prices and how much is organic? And secondly, unsustainable. And secondly, could you highlight or contrast how you're differentiated from others in the Permian in any of those themes? Thanks a lot. I think the majority of that improvement is organic. We've gotten price improvements and we work that part of the equation hard, but most of it is boots on the ground, engineering, geoscience work, time to market improvement, integrated project planning, all those things internally, which gives me high confidence that it's sustainable going forward. Right. And you think it can continue as well. I think you've said you've talked about returns that are relatively low, what seems to be a fairly low view of the oil price for the rest of the year and beyond even. Can you talk about what you think the breakeven prices for you guys for your returns in the Permian? And I'm aware that you've got both EOR, which is presumably a different answer from the unconventional. And then could you stop going on, but could you then also talk about how you compare to other companies in your view? Thanks. First of all, Paul, I'd like to address the comparison to other companies. One of the things that we've been able to do in the Permian versus others is we've been there for a long, long time. So we've got a lot more data than other companies and we're doing more with that data. We have a lot of 3 d seismic. We have, in addition to the 3 d seismic, we have more than 20,000 wells from which we have data. So and we have 4,400 outside operated wells and I know you've heard all those numbers from me before, but we're really taking that data and taking it to the next level. We have a team that works with our resources team. Our resources team, I just have to say, is incredibly efficient in what they've been able to do and to drive the drilling cost down the completion optimization and all of the things that Jody has talked about. They've done a great job. It's just been incredible. Takes all that data that we get from every well. And we utilize every bit of data we can, not only applying data analytics to it, but taking a lot more data than other people have access to. I think we still have the only horizontal core in the Permian. We're doing much more modeling around geo modeling and learning more about the thermal maturity of the and the migration of the hydrocarbons. So I think that's really helped here recently to make a big difference in the improvement of the resources wells. And I think to build on Vicki's comments, we recently held, what we called a cost stand down day where we took the entire company and stopped and said, let's get creative, let's get innovative on how we improve our business. We focused on SG and A, we focused on capital costs, we focused on operating expense, we focused on development opportunities. And there's literally thousands of ideas that we have vetted and are currently vetting and that gives me even more confidence that we can move that hurdle breakeven lower for a number of these areas. And what is the hurdle breakeven on a full cycle make a return that's appropriate for Oxy basis? The returns for the Permian EOR business, we have, for Permian EOR, a cash cost right now that's less than $20 and our DD and A is less than $10 We're continuing to drive that down, expect that to go lower this year. So in our Permian EOR business, currently, we can flex that around a bit by developing some of these RAS developments, which Jody mentioned in his presentation, some of those developments get down as low as $3 on the F and D side. So we have a range of opportunities in the Permian OR business that we can develop. Some of the RAS developments that go down to an F and D of $3 those are fairly limited in size. So what we always try to do is blend the bigger projects that maybe have the $8 or $9 or $10 F and D with the smaller projects to get a blend of all of those. And on the resources side, certainly our costs have been coming down there. The operating cost is down much lower than it was. The DD and A for our resources business currently is higher because of the infrastructure To tell you a number of To tell you a number of where that's going to be, I think, I'd hate to prematurely forecast something that I'm sure the teams are about to beat, but we're continuing to lower our cost and resources. Just to press, can you give me a range at least? On the resources side? Yes. I mean, it's just really interesting to everyone because obviously we see it as the marginal arguably the marginal cost of oil. Yes, the resources side, I would say that we're in the total cash cost of range of about $13 to $14 And we're working when we get our full development cost in line, our DD and A on the resources side will be in the $10 range. You basically you've got positive cash margins here at the strip for the Permian Resources and EOR for sure, Paul. I That's the way I would think about it. Appreciate that. Thanks a little bit. Our next question comes from John will you make more of a push towards the Delaware given the relative economics of place like the Bone Spring? And specifically for the sub-forty type inventory you highlighted. Could you give me a better sense and maybe this is redundant, but if you could give me a better sense of the split between the formation itself, the well design and also the infrastructure? Because obviously you're stressing the integrated nature of your approach, but certainly good rock matters. But I was wondering about how important your well design changes have been to lower that threshold? Yes, John, it's a great question. We're really encouraged by the recent results with upsizing our fracs in the Bone Spring in New Mexico. But when you look at field development maturity and our infrastructure maturity, the Wolf Bone's just got a jump start on that over in the Texas side. So early in the year, we'll be in the Wolf Bone where we can take advantage of that infrastructure. As we get the field development plans matured in the Bone Spring area incorporate more of the appraisal data that we've captured over this last year to ensure that we're as efficient as possible when we do put the rig back into Mexico. Okay. That's fine. Last one for me is, you sold a lot of reserves during the year, that 600,000,000 barrels. I was wondering if you could break them down geographically, what you sold? Reserves were very small. I mean, at the end of the day, I mean, we didn't sell. These are sort of I mean, we took down the PUDs basically in the domestic part of the business. Okay. Thanks, Chris. And this concludes our question and answer session. We would like to turn the call back over to Chris Degner for any closing remarks. Thank you. And I'll turn the call over to Vicki for some closing remarks. I just wanted to say, I don't think we fully answered Paul's question. So to get back to the head, we in the EOR business with our cash cost and our DD and A of around $24,000,000 to $25,000,000 And in the resources business, our cash cost and DD and A in the neighborhood of $22,000,000 to $23,000,000 that's basically about half of what we're the price we're seeing on the strip as Chris had said. Generally, that delivers for us about a 50% rate of return. So I just wanted to close with that. Okay. Thank you, Vicki, and thanks to everyone for participating on the call. Have a good day.