Earnings Call: Q3 2016

Nov 1, 2016

Good morning, and welcome to the Occidental Petroleum Corporation Third Quarter 2016 Earnings Conference Call. All participants will be in listen only mode. 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. Thank you, Kate. Good morning, and thank you for participating in Occidental Petroleum's Q3 2016 conference call. On the call with us today are Vicki Hollub, President and CEO Jody Elliott, President of Oxy Domestic Oil and Gas Sandy Lowe, Group Chairman, Middle East Ken Dillon, President, International Operations Chris Stavros, Chief Financial Officer and Rob Peterson, President of OxyChem. In just a moment, I'll 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 2016 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. I'll begin by summarizing our key accomplishments in the Q3. First, cost reduction efficiencies combined with improvement in new well productivity and better base management have enabled us to further reduce our total spend per barrel of production this year compared to 2015. 2nd, we again increased year over year production in our core areas and we're on target to exceed the higher end of our guidance for 2016. 3rd, we remain prudent with our capital allocation as we focus on returns and maintain discipline to stay within our $3,000,000,000 capital budget. 4th, to further increase our low decline production and improve efficiencies, we have acquired additional working interest in enhanced oil recovery projects and unconventional acreage in the Permian. Last, our aggressive appraisal and development efforts in our Permian Resources business have resulted in improvement in the number and quality of wells in our inventory. As I previously mentioned, our total spend per barrel of production metric includes our overhead, operating and capital cost per barrel of production. This metric is designed to drive cost reductions, increased well productivity and optimize base production. To align employees with this metric, we have linked this to incentive compensation. Our efforts to focus on efficiency and capital discipline are paying off as we continue to lower our total spend per barrel of production. We averaged close to 62 barrels in 2014, about $40 per barrel in 2015 and have targeted $28.50 per barrel in 2016. Year to date, we've beaten our target with average total spend of about $27.50 per barrel. In the Q3, total company production from our ongoing operations was about 605,000 BOE per day, an increase of 5% year over year, driven by Al Hosan Gas in Abu Dhabi, a new gas project in Oman and resilient base production in Permian Resources. The performance of the Al Hosn team continues to exceed our expectations as they optimize deliverability. They have again achieved record production of 74,000 BOE per day for the quarter. It's even more impressive that the plant operated well during the summer months where temperatures can reach 120 degrees. We're optimistic that the plant can continue to deliver from 60 5,000 BOE per day to 75,000 BOE per day depending on seasonal maintenance. We have commenced engineering studies for a potential expansion of the plant and expect to reach an investment decision in the second half of twenty seventeen. Permian Resources production this quarter was 121,000 BOE per day, representing year over year growth of 4%. As per our original development plans, Permian Resources production will decline slightly in the Q4. We are adding rigs now to stabilize production and restart growth in early 2017. We continue to see improvements in well productivity in all of our areas. The increases in production from Al Hosen, Oman's Block 62, along with strong year over year production growth from Permian Resources will help us exceed the higher end of our production growth guidance for 2016. As we look forward to 2017, we expect to deliver 5% to 8% production growth with a variance subject to our activity levels in the Permian. Longer term, we have a deep inventory of well locations in the Permian with the capability to drive production growth above this range. Additionally, we have focused our international business on the core four areas: Abu Dhabi, Qatar, Oman and Colombia, where we have a track record of operational success, free cash flow generation and strong financial returns as well as growth opportunities that could provide the partners in those areas that the returns on any new projects or capital investments must compete with the Permian Basin. I'm pleased to announce that we have formally completed the exit of our contracts in Bahrain and Iraq. We have no meaningful liabilities related to those contracts nor will we incur any material spending on capital or overhead to manage those terminated contracts. We've also made solid progress toward a formal exit from our contract in Libya. Our capital spending in the Q3 declined slightly as we maintained our drilling program in the Permian and shifted timing on spending for certain midstream and chemicals projects. The Permian drilling program is consistent with plans we put in place at the beginning of this year and with our strategy to remain relatively conservative in this price environment. Continued improvements in project design and capital execution have helped us do more than expected with our $3,000,000,000 capital budget. These along with improved production performance in many of our areas are the reasons we will achieve the upper end of our production guidance for the year. The construction of the OxyChem joint venture, ethylene cracker at Ingleside is on budget and on schedule. We have targeted to finish the commissioning of plant by mid January and expect ethylene production in the Q1 of 2017. In addition, the crude oil export terminal at Ingleside has started operations and successfully loaded and dispatched 3 ships. The terminal has oil storage capacity of 2,000,000 barrels and throughput capacity of approximately 300,000 barrels of oil per day. The export facility will have the flexibility to take various gravities of crude oil to both domestic and foreign markets. As the production from the Permian Basin grows in coming years, we would expect to increase demand for access to multiple markets. The ship channel in Corpus Christi has clear advantages to Houston and should allow for shorter transportation times to market. With the completion of long term projects in both our Chemical and Midstream segments, we expect to have increased flexibility with our capital program in 2017. As we enter the Q4, we have increased our activity in the Permian to prepare the business for growth in 2017. While we plan to release a more detailed budget early next year, at this point, it's our expectation that capital will increase modestly from a little under $3,000,000,000 in 2016 to a range of $3,300,000,000 to $3,800,000,000 in 2017. The progress this year on multiyear committed capital will allow for more of our 2017 capital to be devoted to upstream oil and gas development. Our program in the Permian Resources business will receive the largest increase in capital and due to the shorter cycle nature of the asset base, it can be adjusted depending on the extent of commodity price recovery. As we announced yesterday, we have made several strategic acquisitions of producing properties and non producing leasehold in the Permian. As we've said previously, we already have a very large inventory in our resources business. The main reason to acquire additional acreage is to improve the value of the inventory we currently have. The selection criteria we use to evaluate acquisition opportunities are the proximity of the acreage to our existing infrastructure, the quality of the subsurface reservoirs and in most cases, we need to have multi bench development potential and the ability to recovery per well by drilling longer laterals. The acquisition we just made met all of these objectives with the added bonus that we already had a working interest in the properties, making the overall acreage investment lower than current market. In fact, all the assets Resources acquisition is in the Texas Delaware Basin. The Resources acquisition is in the Texas Delaware Basin. Increasing our working interest enabled us to become operator of this area, which we believe to be among the most prospective areas in the Permian. Current production is 7,000 BOE per day. The acreage is mostly contiguous, which will enable us to drill longer laterals. It has high oil content and at least 5 prospective benches, 3 of which have a high level of certainty and 2 that are currently being appraised. The properties also have infrastructure that fits well with the infrastructure and takeaway capacity that we already have built in the area. Including our previous acquisitions, our aggregate investment in this area totals $2,000,000,000 and increases our working interest in 59,000 acres. The $2,000,000,000 includes a cost of $100,000,000 for the infrastructure on the acquired acreage. From an operating standpoint, this area will become part of what we will call the Greater Gorilla Draw development. This enables us to utilize and control shared infrastructure to reduce development capital and operating costs thus increasing our margins as we grow our production. We will leverage this infrastructure along with our knowledge of the subsurface to drive improved financial returns and production growth. We expect to add a rig or 2 to the acreage early next year to accelerate the development of the resource. As with the Resources acquisition, we also acquired additional working interest in enhanced oil recovery projects in Permian, mostly in areas that we operate. This acquisition provides low decline net production of 4,000 BOE per day and has additional development upside. Going forward, we will continue to actively evaluate our acquisition opportunities. Due to the nature of its ownership base and long history of production, ownership throughout the Permian is fragmented. We will target bolt on opportunities with the clear strategic synergies I previously listed to leverage both our understanding of the surface theology and our existing midstream and infrastructure investments. Our approach will be disciplined. We'll also continue to actively swap and trade small blocks of acreage. Year to date, we have swapped approximately 10,000 acres through many small negotiated transactions. These trades will enable longer lateral development and improved returns without material capital outlay. As we have continued to appraise and develop our own acreage in the Permian Resources business, we have seen steady improvement in well productivity and a reduction in our drilling and completion costs. Improved logistical capabilities and integrated planning will ensure the majority of these cost savings are sustainable. Through efforts to core up our acreage to drill longer laterals, we have lowered the breakeven costs on our inventory. Simply put, we can deliver more production with fewer wells. We expect to provide updated disclosure of our inventory and breakeven prices in early 2017 once we have fully integrated recent appraisal efforts and acquisitions. I'm pleased with our progress to date. We have exceeded our production targets for the year with less capital than we had planned to spend, and we've positioned the company for continued profitable production and cash flow growth as we enter 2017. Directionally, we are planning for modestly higher oil prices in 2017 and we'll set our budget accordingly. I'll now turn the call over to Chris Stavros. Thanks, Vicki, and good morning, everyone. Today, I'll focus on the following items, our Q3 segment and overall financial results, Oxy's balance sheet strength, liquidity and cash flow in the context of the Permian acquisitions we just announced and oil and gas production and segment guidance for the 4th quarter. 3rd quarter 2016 reported financial results reported results included a net after tax charge of $129,000,000 related to non recurring items in both the oil and gas and midstream segments. Our core financial results for the Q3 of 2016 were a loss of $112,000,000 or $0.15 per diluted share, a slight improvement from the loss of $136,000,000 or $0.18 a share during the Q2. Importantly, each of our operating segments generated improved quarter to quarter core financial results despite the continued challenging conditions for product prices. Oil and Gas pre tax core results for the Q3 of 2016 were a loss of 16 were a loss of $49,000,000 compared to a loss of $117,000,000 in the 2nd quarter, an income of $162,000,000 in the same year ago period. The sequential improvement of $68,000,000 was primarily a result of higher product price realizations. During the Q3, the oil and gas segment recorded a non core net charges related to the exit from both Libya and Iraq of $61,000,000 and a $38,000,000 after tax gain on the sale of some non core, non operated oil and gas properties in South Texas. 3rd quarter total company production volumes of 605,000 BOE per day were at the high end of our previous guidance range with better than expected production results coming from Permian Resources, improved performance at Al Hosen in the UAE and production growth in Oman from Block 60 production was 294,000 BOE per day during the Q3, down sequentially from 302,000 BOE per day in the second quarter. Despite the overall decline in domestic volumes, production in Permian Resources of 121,000 BOE per day exceeded our earlier guidance by 5,000 BOE per day, largely to better management around our base production. The sequential decline in 3rd quarter domestic volumes was also partially due to a drop in production from the absence of gas directed drilling activity in South Texas. Our domestic oil and gas operations generated $67,000,000 of free cash flow after capital during the quarter. In a moment, Jody Elliott will discuss our plans for increased drilling activity in Permian Resources for the Q4 and as we exit the year. International production from our ongoing operations was 311,000 BOE per day during the Q3 of 20 16, an increase of 4,000 BOE per day compared to the Q2. Higher volumes from Al Hosn and Oman contributed to the overall sequential increase, partially offset by a decline in Colombia as a result of pipeline disruptions. The international oil and gas operations comprised of our core four areas generated nearly $300,000,000 of free cash flow after capital during the Q3. Domestic oil and gas cash operating costs of $12.26 per BOE in the Q3 of 2016 were slightly higher on a sequential basis, however declined by 7% compared to the full year 2015 costs of $13.13 per BOE. 9 month year to date costs are down nearly 10% compared with full year 2015 with the decline mainly the result of improved efficiencies and logistics management around our surface operations including water handling as well as lower downhole maintenance and energy related costs. Cash operating costs in Permian Resources saw further sequential decline in the 3rd quarter and for the year to date have fallen to $8.43 per BOE, an improvement of 25% compared to 2015 full year costs. Overall oil and gas DD and A for the Q3 of 2016 was $15.58 per BOE compared to $15.81 per BOE during 2015. Taxes other than on income were $0.97 per BOE for the Q3 of 2016 compared to $1.32 per BOE during 2015. The 3rd quarter exploration expense was $9,000,000 Chemicals' 3rd quarter 2016 pretax core earnings were $117,000,000 compared with 2nd quarter earnings of $88,000,000 The sequential quarterly increase in core earnings resulted from higher chloro vinyls production volumes and higher realized caustic soda prices. These improvements were partially offset by higher energy costs combined with lower vinyls margins. Vinyl prices remain largely unchanged despite significantly higher ethylene prices resulting from both meaningful planned and unplanned industry ethylene cracker outages. Our chemicals business generated $100,000,000 of free cash flow before working capital during the Q3. Midstream pre tax core results were a loss of $20,000,000 for the Q3 of 2016 compared to a loss of $58,000,000 in the 2nd quarter. Despite the loss, the results came in at a positive at the positive range of our previous guidance with the sequential improvement resulting from better oil and gas marketing margins. During the Q3, we renegotiated some of our crude oil supply contracts, which resulted in an after tax charge of $103,000,000 The new agreement should mitigate some of the transportation costs and improve overall profitability going forward. Turning to our cash flows for the Q3, we generated $860,000,000 of cash flow from continuing operations before working capital and other changes and adjusted for a one time payment for the renegotiation of a crude oil supply contract as well as some tax related items. Net working capital changes provided $50,000,000 of cash during the period. We expect that this trend on working capital will continue as we exit the year at a slightly higher run rate for capital expenditures compared to the current pace of spending and activity. Capital expenditures for the 3rd quarter were $642,000,000 bringing our total year to date capital spending to approximately $2,000,000,000 As Vicki mentioned, our capital spending in the 4th quarter is expected to increase modestly as certain project related expenditures in both chemicals and midstream had been deferred into the latter part of the year. In addition, we plan to recycle some of the efficiencies and savings generated around drilling and completions back into our Permian Resources drilling program in addition to pursuing some project opportunities in Colombia. Despite the higher planned capital spending during the Q4, our total 2016 total capital program is expected to come in slightly under our original budget of $3,000,000,000 We paid $575,000,000 in dividends during the quarter and ended the period with $3,200,000,000 of cash. As Vicki mentioned, yesterday we announced several acquisitions of producing properties and non producing leasehold acreage in the Permian as well as interest in several enhanced oil recovery and CO2 properties and related infrastructure. These acquisitions were funded with existing cash on hand and without the use of any equity. The transactions are immediately accretive to cash flow and at current commodity prices. Although our view on product prices remains relatively conservative into next year, we believe we have the balance sheet flexibility to allow us to cover a modest increase in our capital program, which we expect to deliver production growth of 5% to 8% in 2017. Assuming oil prices of approximately $50 per barrel, we expect to generate cash flow from operations of at least $4,500,000,000 in 2017. Incremental cash flow contributions would include $150,000,000 from the start up of the joint venture ethylene cracker, approximately $200,000,000 from improving results in the midstream segment, which would include the Ingleside Crude Oil Terminal and at least $100,000,000 from the announced Permian acquisitions. In addition, every $1 per barrel improvement in oil prices in oil prices would provide a further $100,000,000 of operating cash flow. With respect to guidance and as Vicki mentioned, we now expect our full year 2016 16 production growth from ongoing operations to be approximately 7% and exceeding the high end of our previous 4% to 6% range. We expect our company wide production volumes to be in a range of 600,000 to 610,000 BOE per day during the Q4. We anticipate our overall domestic production to be in the range of 290,000 to 295,000 BOE per day, which includes a partial contribution from the Permian acquisitions during the quarter. Permian Resources production is expected to be roughly flat with volumes seen during the Q3 with full year 2016 growth estimated to be about 12%. International production is estimated to be in the range of 310,000 BOE to 3 100 and 15,000 BOE per day during the Q4. This incorporates the impact of a planned maintenance turnaround at Alhosin and assumes normal operations in Colombia. Our plan is to remain disciplined with our capital within the current price environment and to recycle some of the efficiency and productivity gains realized this year into greater activity during the Q4 early next year. We expect this additional activity to help support our Permian Resources production as we exit this year and provide a platform for growth into 2017. Jody will share some of those specifics during his prepared remarks. In the midstream segment, we expect the 4th quarter to generate a pre tax loss of between $20,000,000 $40,000,000 While quarter to quarter changes are inherently volatile in this segment, we anticipate favorable spreads for our West Texas to Gulf shipments to continue, higher domestic pipeline earnings as well as increased flow of crude to our Ingleside crude terminal in anticipation of full operations beginning early in 2017. In Chemicals, we anticipate pre tax earnings of about $100,000,000 for the 4th quarter or roughly flat with the 3rd quarter. Our DD and A expense for oil and gas is expected to be approximately $15.50 per BOE during 2016 and depreciation for the oil and gas segment is expected to exceed this year's capital investment by more than $1,400,000,000 The combined appreciation for the Chemical and Midstream segments should be approximately $655,000,000 Exploration expense is estimated to be about $25,000,000 pre tax during the Q4. Price changes at current global prices affect our annual operating cash flow by about $100,000,000 for every dollar per barrel per change in WTI and a swing of $0.50 per 1,000,000 BTUs in domestic natural gas prices affects our annual operating cash flow by about $45,000,000 Using current strip prices for oil and gas, we expect our full year 2016 domestic tax rate to be about 36%. Our international tax rate should be about 55%. I'll now turn the call over to Jody Elley to provide an update on activity around our Permian operations. Thank you, Chris. Today, I will provide a review of our domestic operations during the Q3, guidance on our program in the Q4 and an outlook for the start of 2017. For this year, our Permian Resources business achieved significant improvement in well economics across our Permian leading acreage position through step change advancements in well productivity and field development design. We believe this improvement in value starts with our subsurface characterization, where we are leveraging our geology, petrophysics and geochemistry expertise to achieve breakthroughs in our multi bench appraisal, stimulation and other key subsurface design factors. We expect to quickly deliver a new series of breakthroughs in 2017 as we advance our seismic based characterization and second phase of geoscience analytics. On the cost structure front, we continue to lower our capital and operating cost structure through faster drilling, leveraging engineering innovation and integrated planning to optimize execution and logistics. We expect these efforts, when combined in our field development plans, will ensure Oxy is a leader in realizing maximum value per acre by optimizing recovery and capitalization. Our unconventional business is well positioned to provide a competitive return in a low cost environment and achieve significant growth in an improved price environment. As a result, during the Q3, we added a drilling rig in Permian Resources plus another at the beginning of the 4th quarter and had capacity and locations on standby to respond to improved pricing in 2017. Turning to the performance of Permian Resources. In the 3rd quarter, we achieved daily production of 121,000 BOE per day, a 4% increase versus the prior year. Oil production declined modestly due to lower capital spending with 9 wells put online versus 54 wells in the Q3 of 2015. Improved well productivity and our emphasis on base management mitigated some of the base decline on the horizontal wells. In the second and third quarters, we completed gas processing and compression facilities, allowing for the capture and sales of more gas and NGLs. As we announced yesterday, we acquired producing properties and non producing leasehold acreage in the Permian. At Permian Resources, we acquired 35,000 net acres in Southern Reeves and Pecos Counties, where we currently operate and have working interest. The properties will include approximately 7,000 BOE per day of net production with 72% oil from 68 horizontal wells. On key portions of the acreage, we gained operatorship where we had existing non operated interest and most of the acreage is already held by production. Development will initially target the Wolfcamp A, Wolfcamp B and Bone Spring. Simply put, we know the acreage very well. It's very competitive with our existing inventory. We expect to drill longer laterals, execute multi bench development and leverage our existing infrastructure in the area, notably the joint venture gas processing plant completed this summer. This transaction brings our overall position in the leasehold area to 59,000 net acres with an aggregate acquisition cost under 2,000,000,000 dollars We plan on allocating approximately $200,000,000 in capital in 2017 to the acquired acreage, utilizing 1 to 2 drilling rigs. Turning to our activities in our core development areas, much of the focus of the drilling program in the 2nd and third quarters was to appraise the potential for multi bench development in Southern Reeves, Eddy, Howard, Glasscock and Northern Reagan County. In Southeast New Mexico, we drilled and completed 2 Cedar Canyon Third Bone Spring wells and 1 Cedar Canyon Wolfcamp A well in Eddy County. All of the wells had 30 day peak IPs over 1,000 BOE per day excuse me, 1,000 BOE per 1,000 BOE per day. In Southern Reeves County, we brought the Roan State 2,451H Second Bone Spring well online at a peak rate of 9.44 BOE per day and a 30 day rate of 7 0 2 BOE per day at a 90% oil cut. The well had a 4,500 foot lateral and increases our confidence in the potential for multi bench development for our acreage in the area. We're on the learning curve in developing this bench and expect well productivity to improve as we apply our experience in drilling and completion technology and further integrate our subsurface analysis. In Glasscock County, we brought the appraisal well Powell 1721H online with a 7,500 foot lateral, which targeted the Spraberry formation with a 30 day rate of 9.31 BOE per day. As cited last quarter, we now compare and benchmark our well cost on a cost per 1,000 feet of lateral basis as we continue to increase our lateral lengths. Slide 23 illustrates our demonstrated improvement in well cost, which has declined roughly 38% from 2015. Similarly, our 1,000 foot of lateral per rig per quarter has also improved from 25.2 per rig per rig in 2015 to 35.4 per rig in the 3rd quarter. We believe that a significant percentage of these improvements and efficiency are driven by structural changes in how we drill and complete wells and expect to continue to improve these efficiencies as we add drilling rigs. In the Delaware Basin, we're aggressively appraising new benches while maintaining focus on improving well recoveries in our development benches. In Southeast New Mexico, we tested a new second Bone Spring slickwater frac design on the Cedar Canyon 27 Fed 5H with £2,000 per foot 50 foot cluster spacing. The cumulative production results from the new design have exceeded the first half twenty sixteen design, and we expect to see continued improvement in future results. We're targeting an average well cost of $7,100,000 for the 2nd Bone Spring and $8,300,000 for the 3rd Bone Spring with 7,500 foot laterals and the increased completion size. Overall, we're very encouraged by the development and appraisal results in Southeast New Mexico, and we expect to increase activity in Q4 and throughout 2017. In the Texas Delaware, we drilled 1 well and turned 1 appraisal well to production. The reduction in activity in the area is consistent with the overall balance of activity shift between Texas and New Mexico, and we plan to increase activity in this area in the 4th quarter. Our upcoming wells in the 4th quarter will test new completion designs and drilling technology that we believe will drive step change value addition across all of our development areas. We expect to increase our average lateral length from approximately 5,200 feet in 2016 to over 9,000 feet in 2017. Shifting our results to the East Midland Basin. In the Q3, we drilled 8 wells, brought 4 wells online, 3 of which have not reached peak production rates. We had multiple record drilling and completion achievements during the quarter. For example, we drilled a Wolfcamp B 7,500 Foot Lateral and 12.5 days rig release to rig release. We completed 10 frac stages in one day and we drilled and completed 2 Wolfcamp A horizontals for $4,600,000 $4,900,000 Well productivity measured by the initial production rates per 1,000 foot of lateral continues to improve. In the Permian Resources as a whole, we achieved another quarter of lower quarter over quarter field operating expenses due mainly to improve surface operations with optimized water handling, lower workover expenses and better downhole performance. Since the Q2 of 2015, we reduced our operating cost per barrel by 28%, continue to work additional cost reduction and efficiency improvements. As stated earlier, our focus on maximizing production from existing wells has been central to reducing declines in the business. We expect that our annual average uplift for our investment will be approximately 6,000 net BOE per day. This another example of leveraging our decades of base management expertise in the EOR business to our Resources business. As previously stated, we expect to increase our drilling activity in the Q4 of 2016 and bring on approximately 20 wells. We expect production to be about 120,000 BOE per day in the Q4 and be growing as we exit the year. With over 115 wells planned for 2017, we expect to achieve double digit production growth in Permian Resources. In addition to the recent acreage acquisition, we've been actively trading and swapping acreage in order to core up our position. We've traded approximately 10,000 acres, which will enable longer lateral development. So for 2017, we expect to drill more wells with more than double total lateral length drilled in 2016. Now I'd like to shift to our Permian EOR business. We continue to take advantage of lower drilling cost and manage the operations to run our gas processing facilities at full capacity. Permian EOR had another quarter of free cash flow generation. Drilling costs are running 22% below our benchmark target and we've lowered our cash operating expenses by 20% since the Q4 of 2014 and 7% year over year, driven mainly by lower downhole maintenance and injectment costs. In similar fashion to our resources business, the capital savings achieved by the EOR team will be reinvested into additional wells and CO2 flood expansions. As we've mentioned in previous calls, the residual oil zone development or RAS is a vertical expansion of the CO2 floated interval. The RAS lies underlies most of our major EOR properties and can be developed between $3 $7 per barrel. Year to date, we've completed 94 well deepenings and recompletions along with 36 wells new wells in the Ross developments. We anticipate an additional 50 deepenings and recompletions and 10 new wells in Ross developments in the Q4 of 2016. Yesterday, we announced acquisitions of working interest in 11 producing oil and gas properties and related infrastructure. The acquisition increases our ownership in several properties where we currently operate or an existing working interest partner. These properties have production of approximately 4,000 barrels of equivalent per day at 80% oil with estimated net proved developed producing reserves of approximately 25,000,000 BOE and total proved reserves of approximately 41,000,000 BOE. To summarize, our domestic business will provide competitive returns in a low cost environment and achieve significant growth in an improved price environment. We believe our Permian business is uniquely positioned to leverage our subsurface innovation in unconventional and leadership in enhanced oil recovery to maximize the value per acre across our entire 2,400,000 acre portfolio. We plan to exit this year running 8 drilling rigs on our operated acreage plus another 1.5 to 2 net rigs on our non operated development acreage. We're pleased with the strides our teams have made in sub service characterization, execution and performance thus far in 2016 and look forward to continuing breakthroughs in 2017. Thank you, and I'll now hand it back to Chris Degner. Thank you, Jody. We'll now open up the call for questions. We will now begin the question and answer session. The first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thanks. Good morning, everybody. I've got 2 questions. Vicki, I wonder if I could kick off with the acquisition last night. You've shown before the relative priority for the use of cash. And you also shown us that you've got a fairly deep inventory of existing assets. I'm just trying to understand the rationale as to why $2,000,000,000 is the right use of cash versus a step up in activity on your existing acreage. If you just help us understand the rationale a little better and maybe some of the nuances about working interest changes, what it brings to you by way of operating capability and so on. Help us understand the numbers of EBIT. Yes, Doug, we've been looking at this. We've been we've had ownership in this area for a while now. And what made us very attracted to this is the fact that it has the potential for 5 bench development and the fact that it's so close to our Barilla Draw area where we've already installed infrastructure. We believe that the infrastructure in Barilla Draw combined with the infrastructure that was installed by a very prudent and efficient operator will enable us to combine the 2 and provide those synergies around that infrastructure to share that. The 5 benches, the shared infrastructure and the operational efficiencies that we'll gain by combining these two areas and becoming operator of it where we can manage the development to maximize the net present value, we believe was the best use of our cash at this point. This inventory is fits within the less than $50 per barrel breakeven price for us and or the price that generates positive NPV of 10 for us. So that we think it's very perspective. We like how it fits. We believe that it's we can further develop a Brilla Draw. It will help with the economics there. So the combination of the 2 of them provides us quite a bit of net present value. Vicki, I don't want to waiver the point, but I think Jody suggested 1 to 2 rigs in this area. I guess what I'm really trying to understand is to justify the NPV I understand the NPV of the incremental wells, but to justify the NPV of the incremental wells plus the $2,000,000,000 acquisition cost, one would imagine you have to run at a pretty healthy pace above what you were going to do on your existing portfolio. So again, can you help us what guide us to where the activity level on this acreage goes to justify the $2,000,000,000 price tag? Yes, the 1 to 2 rigs would be the initial starting point for us on this acreage. We expect to spend about 200,000,000 dollars in 2017. But in 2017, remember now we're still trying to balance cash with what our expectations are around oil prices. We do expect improving prices in 2018, which is where we expect to really launch into a much more aggressive development of both Barilla Draw and this new area. So we expect that we're going to be very aggressive with the development on this once we get into 2018 where at that point, we expect the supply gap to narrow such that the prices will warrant a much higher level of activity. Okay. Very, very last one for me, a very quick one on chemicals. Given that the cracker starts up at the beginning of next year, can you just give us some guide on the free cash flow delta on that project as you move from 2016 into 2017? And I'll leave it there. Thanks. Okay. Hi, this is Rob Peterson. So yes, we'll continue we'll discontinue the spending of capital, carry over a small amount for commissioning and start up into 2017 and then we'll stop spending that and start generating cash from it. So it will be a several $100,000,000 flip between spending capital and generating cash out of the cracker depending on ramp up time. Yes, the swing Doug is actually about $300,000,000 in terms of spending versus the contribution. So that's the delta, if you will, spending to cash the contribution. So that's the delta, if you will, spending to cash flow. Yes. I just wanted to check order of magnitude. That's great, guys. Thanks so much. The next question is from Phil Gresh of JPMorgan. Please go ahead. Hey, good morning. I just want to follow-up on kind of the cash flow side of things. Chris, you mentioned $4,500,000,000 of CFO at $50 And if we use the CapEx, call it $3,500,000,000 that would be $1,000,000,000 of free cash flow versus a dividend of $2,300,000,000 So I guess what I was wondering is how you plan on funding that gap if oil is $50 or even if it's $55 would you be looking to add debt to the balance sheet? Would you be looking to sell assets? And generally, Chris, just how are you thinking about target leverage following this acquisition? Yes, Phil, it's a good question. It's going to come from a combination of a number of different sources for the cash. Without being completely or terribly specific about any given thing that we're going to do at any given moment, what I would say is, obviously, it's going to depend on commodity prices. As I mentioned, the sensitivity around our cash flow to commodity prices. But should the need arise, we would expect to monetize some non core, non strategic assets that would more than we believe cover our needs. And when including our expectations for next year's cash from operations. So I don't anticipate or expect us to fall short or have any issue with that. We've got multiple levers that we can pull on in terms of filling any gap, certainly to the extent that you just did the arithmetic around and more should need be. And the capital remains very flexible within certainly within the range depending on commodity prices. And on the target leverage side of things, I mean post this deal, Vicki, you mentioned maybe even looking at additional bolt on deals. I mean, how do you think about target leverage and the size of what bolt on would mean relative to the acquisitions you've just done? Yes. I mean the leverage amounts are we're comfortable with that within our sort of within our ratings right now. We'll obviously depending on what the acquisition looks like, if we do acquisitions, depends on what it looks like in terms of how, we're going to look to fund it. And so some acquisitions are better sourced through leverage, some other through other means. So we'll just have to look at it. It depends on how what the acquisition looks like the composition of the cash flows around the acquisition, the composition of the production in terms of determining how much leverage you're comfortable with on for any given type of activity or specific acquisition. So the answer is it really depends. And Phil, with respect to the bolt on acquisitions, we look at a lot of things in the Permian and this is the first thing that we've seen in a while that really fit well with our current operations and really made sense from a long term development standpoint. You may have heard our name associated with some things in here recently that those are things we didn't bid on. We look at a lot of things, but what we always want to do is make sure that it's a good fit and that as Doug had alluded to that our net present value of what we expect our development to be is going to cover the cost of the acquisition. And so that rules out a lot of things for us. Okay, thanks. The next question is from Ryan Todd of Deutsche Bank. Please go ahead. Great. Thanks. Maybe another follow-up on the budget. I know you referenced the addition of rigs into the 4th quarter in the Permian, but what level of activity is implied in the Permian in the $3,300,000,000 to $3,800,000,000 budget for 2017? And how much of that budget is allocated to Permian Resources? Ryan, this is Jody. The activity level kind of currently planned for 17 would be about 6 rigs in the Permian Resources area and 3 rigs in EOR. And then depending on what that final capital number is, we can scale that up, scale it down, again, depending on commodity prices or where that final direction is on the capital budget. And we said previously, although it's not final yet, that our capital spend would probably be in the range of 1 $300,000,000 to $1,400,000,000 for resources. And Ryan, the other point I want to make is all the work that we've done this year around our characterization, around our field development planning, the upsizing and kind of optimization of our stimulation has created this ability with very low capital intensity to generate a lot of production. So that inventory mix in 2017 will be optimized where we can grow production significantly with a fairly modest rig count. And then maybe as a follow-up to that. I mean, can you talk a little bit about your infrastructure position in the basin? How you feel like you're positioned to be able to ramp actively in terms of the flexibility that you have over the next few years, whether you see yourselves or the basins in general, industry in general having any sort of bottlenecks, anything there would be great? Yes. Ryan, I think we're as far as our field development planning, that's one of the key things is that we try to get ahead of the game, whether it's water disposal, frac water movement, gas takeaway, oil takeaway. We try to plan those things in advance and build out ahead of when that need is going to be. So whether it's Southeast New Mexico, we announced the startup of the joint venture gas plant recently in the Delaware. Those are all things to stay ahead of the infrastructure game. The new acquisition has considerable infrastructure, freshwater, saltwater infrastructure, 4,000,000 barrels of frac storage, 40 miles of distribution line. It has produced water treatment systems, 15 SWD wells, gas compression. So all those things that have been done extremely well in this Yes, Ryan, I would just say that with respect to our takeaway capacity out of the Permian, we're very well positioned there. We have excess capacity above and beyond what we expect our growth to be. That's been a little bit of a drag on our midstream business here recently, but we expect that to be a real benefit to us going forward. Great. Thanks. The next question is from Roger Read of Wells Fargo. Please go ahead. Yes. Thanks. Good morning. I guess maybe to kind of come back to expectations in the Q4 here. How should we think about the acquired volumes coming in as part of the guidance of the $120,000,000 for Permian Resources? Does that include does that imply that Permian Resources is actually declining here in the Q4 and that adds on or how should we think about the exit rate you indicated would be higher? Yes, Roger. The $120,000,000 includes our estimate of the acquisition. So there's some modest decline in the base core business pre acquisition. Again, the activity levels ramping up. As you know, when you're doing multi well, multi pad development with zipper fracking, the production comes lumpy. So a lot of that activity happens in the Q4 and the production will come very early in the Q1 of 2017. Okay. So potential for a little bit of if things go really well, we can see in December, otherwise thinking about it as a 2017 event? That's correct. Okay. And then could you walk us through with the acquisition here a little bit? The 700 locations obviously indicate potential for significant upside, some of which clearly will be price driven and some of which is going to be based on drilling. How do you how did you come to the $700,000,000 and what's an idea of how we should think at say maybe $60 oil in 2018 where that 700 locations could go? Yes, Roger, the 700 is based on kind of our conservative nature with assessing our development on property. So that's kind of the minimum location count in the Wolfcamp A, the Wolfcamp B, 2nd Bone Spring. We're very optimistic about the 2 additional benches in the Bone Spring and in the Wolfcamp debris flow, which sits between the A and the B. At $60 again, that inventory just continues to grow with whether it's tighter spacing. The other aspect is we continue to improve both well performance and our step change in multi well, multi pad development. And so as we test those in the 4th quarter and in the Q1 of 2017, we'll be more able to talk about some of those details, but we think that would generate even more bench activity, not just in the acquisition, but on all of our core areas. Okay, great. And just a final question. You mentioned there was this acreage was fairly HBP. Is there a percentage you can give us that maybe isn't give us an idea of maybe where the 1 to 2 rigs initially have to be focused? I think it's north of 80 and a lot of those are just clock drilling obligations as opposed to expiry issues. Okay, great. Thank you. The next question is from Brian Singer of Goldman Sachs. Please go ahead. Thank you. Good morning. Wanted to go back to the comments with regards to the CapEx cash flow for 2017. And if we kind of take the acquisition side of things away and just look at the strategy with regards to growth versus free cash flow versus dividend, I think in the past you talked about wanting to try to cover that dividend with free cash flow. And perhaps $50 is just the low end of your oil range and will ultimately go higher. But wanted to see if there's any change in your strategic thinking about the importance of covering the dividend with free cash flow, recognizing that Oxy is unique and even having free cash flow of this magnitude in the first place? I'd say, Brian, we consider that covering our dividend with cash flow to be a priority for us. It's very critical. But we do view 2017 as a transition year. We don't expect prices to get to the point where it's reasonable for us to cover cash, our dividend with cash flow until 2018. That's why we're ensuring that all the decisions that we make will enable us to get through the transition year of 2017. We have other levers we need to pull if that supply demand balance doesn't come doesn't narrow in 2018. So there are other things that we can do, but we're certainly expecting an oil price that is certainly closer to our cash flow neutral standpoint. Great. Thanks. And then shifting to the Permian, the acreage position, as you highlighted, is very vast. Can you talk to whether you see your interest and the need for additional acquisitions to achieve the type of scale you desire as you're doing with this acquisition here to be competitive to or more competitive with others in the basin that have contiguous acreage position? We view this acquisition as a very unique opportunity, because of the reasons I've described. We don't see any need to acquire any additional acreage unless it's smaller bolt ons that do provide us the efficiencies to develop what we currently have. And those are the types of things that we would target going forward. Our inventory is huge and we still haven't fully appraised the inventory we have. So what we view this to have done is in the Greater Barilla Draw area, what it's done for us is just in addition to the 59,000 associated with the acquisition, we have in that general area around 100,000 acres. So that gives us a really sizable position that's bigger than most positions. And that's why this was so important to us. It was a special case because as you've noticed, we haven't really acquired anything in the last couple of years. And this is the reason we're looking for those things that provide us the unique opportunity to do something that's what we consider to be really a step change in a given area. Looking at the rest of our acreage, we're spending quite a bit of time and effort to appraise the rest of what we have and to rank it in terms of development. So now we feel very comfortable with the Greater Barilla Draw area. Southeast New Mexico is in prime position for aggressive development and we have some areas in the Midland Basin as well. What we have to do now is we've got our appraisal team working on those parts of our acreage that are outside of those areas. Great. And could you characterize the sum of the acreage that you believe now is developable and to your to the comment you just made? I think the we'll update the full inventory picture in the 4th quarter. To give you a little bit of color, with all the appraisal work and all of the subsurface work we're doing, we've changed the landscape of that inventory. We've doubled the lateral miles of inventory. The NPV on that existing inventory is up over 66%. We have 27 rig years of inventory at less than $40 a barrel. So we've really grown the existing inventory. This asset, it's really the acquisition asset is really about just taking ownership in an already de risked core area with incredible infrastructure. So that's going to allow us when you think about sand, when you think about water, when you think about logistics, people, supply chain leverage, it really allows us to kind of hit all of those key drivers that lower our F and D cost and keep our OpEx cost really low. You very much. I really appreciate it. The next question is from Evan Kallio of Morgan Stanley. Please go ahead. Hey, good morning guys. You significantly beat Permian Resources volumes guidance for the 2nd time in 3 quarters. And if I shift to the guidance, what are the ranges on the 2017 fuzzy bars for Permian Resources on Slide 22? And I'm just trying to square the circle here of whether that range reflects the enhanced completions, longer laterals and increased wells drilled in the presentation or if it's based on the 2015 year end technology as are the location counts? Just looks low versus the commentary. Yes. Evan, that forecast is based on what we know today, right? So it's the latest version of our completion designs and our expansion. The fuzziness is really a function of what's the final capital budget going to be that year. But it's we're not forecasting enhancements or improvements that have not been demonstrated at this point in time. So those are all upside opportunities. And Evan, let me add to that, that Jody and his team along with the support of the subsurface characterization team have beaten their forecast for about what 8 quarters in a row or so. Any numbers on the high end of that? It looks like $135,000,000 Is that right? Yes. It's a little bit higher than that. Okay. Maybe a second one, if I could, on the acquisition. I mean, could you say how much of the acquisition was allocated to Permian Resources versus EUR? I mean, it looks close to 21,000 an acre versus the 43,000 acre headline for Permian Resources. If we back out what you paid for J. Cleo using that cost basis metric, is that right? And then the other side of, I guess, Singer's question is, with a larger Tier 1 footprint, will that increase forward high grading in your portfolio or potential asset sales? I'll leave it there. I would say that on the net value per acre, we were in the upper 20s on what we calculated for that. And with respect to the tiering of the acreage, this certainly gets us what I believe is going to be Tier 1 for us. I believe that this area will certainly be comparable with our best area, which is Southeast New Mexico. The fact is that the opportunity to have 5 benches is going to make the infrastructure costs so minimal on a per BOE basis that I do believe that this is just going to continue to improve. And drive would it since it would take capital, would it would there be other high grading on the back of that? There could be. It really depends on product prices for 2017. We'll continue to balance our capital with our cash flow needs and the balance sheet. Okay. Appreciate it guys. Thanks. And the next question is from Matt Portillo of TPH. Please go ahead. Good morning. Around the base design that you're currently utilizing in the Texas Delaware Basin and what you may be testing on a leading edge basis that may be giving you some incremental excitement in terms of increased productivity on the wells? Matt, it's really basin, I mean it's sub basin specific, almost field specific in those designs. But in general, it is tighter cluster spacing and higher sand concentrations and then doing trials to understand where you've kind of hit diminishing returns. But in general, more sand tighter cluster spacing is generating better results. But combining that with longer laterals has really been the key for us. And as you look at the numbers I talked about on extending lateral length, that's another real benefit for us. In New Mexico, this year we'll average around 5,000 foot laterals. We'll go almost to 7,000 next year. In the Texas, Delaware, a little over 5,000 foot laterals. Next year, it will be closer and this is effective lateral length, over 9,000 feet. And in East Midland Basin, we probably averaged we'll average around 7,800 foot laterals in 2016 and then 2017 that'll be over 9,000 feet. So the combination of extended lateral giving us really better EURs, better decline profiles combined with this continued integration of our geoscience with the stimulation design. The drilling technology piece is something that we'll talk a little bit more about in future quarters, but it's really an innovative way to access multiple benches. And again leveraging your infrastructure across again multiple benches with minimizing your facility cost. And just a quick follow-up there. Is there any color you can provide, I guess, just on what the base design looks like today? Just trying to reference point in the Texas part of the play specifically kind of where your proppant loading is and where your fluid volumes are and maybe what It's in the £17.50 to £2,000 per foot range, but we've trialed and will trial higher. Great. And then just a follow-up question on the New Mexico side of the border. It looks like you started to delineate some of your acreage in Eddy County. Just curious as you guys look at additional resource potential across New Mexico, what interest you have? And I guess moving into 2017 in terms of focusing on some incremental zone delineation in the Wolfcamp and Avalon Horizon? So New Mexico is will be the one of the key places we operate in 2017. This year, we've spent quite a bit of effort in the appraisal mode in New Mexico, testing the 3rd bone, testing the XY, Wolfcamp D. So we will continue as part of our development plans to appraise those other benches. Again, we believe New Mexico has many bench opportunities beyond what we've talked about previously in our inventory. And last question for me. I just wanted to follow-up on a previous question from an infrastructure perspective. So just to clarify there, I think there's some industry concern that as Permian growth accelerates over the next few years that the main infrastructure bottleneck may become the pipe capacity out of the basin. And so I wanted to just make sure that I understood your comments that you guys feel comfortable over the next few years that there are no pipe constraints or you have some solutions in the work that can essentially debottleneck that? Yes, I suspect there are going to be pipeline constraints for others. But I can tell you, we have plenty of capacity tied up and we'll be able to actually still contract and take third party volumes to Houston. We have quite a bit of capacity. So we feel very comfortable with where we are. Thank you very much. Appreciate it. That concludes our question and answer session. I would like to turn the conference back over to Chris Degner for closing remarks. Thank you, Kate, and thank you everyone for joining us on the call today. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.