西方石油 (OXY) 2016 Q3 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation third-quarter 2016 earnings conference call. (Operator Instructions). 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 third-quarter 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 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-K. Our third-quarter 2016 earnings press release, the investor relations supplemental schedules, our non-GAAP-to-GAAP reconciliation and the conference call presentation slides can be downloaded off of our website at www.oxy.com. I will now turn the call over to Vicki Hollub. Vicki, please go ahead.

Thank you, Chris and good morning, everyone. I will begin by summarizing our key accomplishments in the third quarter. 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. Second, we again increased year-over-year production in our core areas and we are on target to exceed the higher end of our guidance for 2016.

Third, we remain prudent with our capital allocation as we focus on returns and maintain discipline to stay within our $3 billion capital budget. Fourth, to further increase our low decline production and improve efficiencies, we have acquired additional working interest in enhanced oil recovery projects in unconventional acreage in the Permian. Last, our aggressive appraisal and development efforts in our Permian Resources business have resulted in an improvement in the number and quality of wells in our inventory.

As I have 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, increase 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 per barrel 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 third quarter, total Company production from our ongoing operations was about 605,000 BOE per day, an increase of 5% year-over-year driven by Al Hosn 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 are optimistic that the plant can continue to deliver from 65,000 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 2017.

Permian Resources production this quarter was 121,000 BOE per day representing year-over-year growth of 4%. As per our original development plan, Permian Resources' production will decline slightly in the fourth quarter. 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 Hosn, 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 the variance subject to our activity levels in the Permian. Longer term, we have a deep inventory of well locations in the Permian with the capabilities 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 capability to drive production growth higher than our long-term 5% to 8% target. I have emphasized to our partners in those areas that the returns on any new project or capital investment 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 third quarter 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 billion 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 the plant by mid-January and expect ethylene production in the first quarter of 2017. In addition, the crude oil export terminal at Ingleside has started operations and successfully loaded and dispatched three ships. The terminal has oil storage capacity of 2 million 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 increased 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 fourth quarter, 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 billion in 2016 to a range of $3.3 billion to $3.8 billion in 2017.

The progress this year on multi-year 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 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 have 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 optimize 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 property making the overall acreage investment lower than current market. In fact, all of the assets we just purchased in both resources and EOR are in fields where we currently operate or own a working interest.

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 five prospective benches; three of which have a high level of certainty and two 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 billion and increases our working interest in 59,000 acres. The $2 billion includes a cost of $100 million for the infrastructure on the acquired acreage. From an operating standpoint, this area will become part of what we will call the Greater Barilla Draw Development. This enables us to utilize and control shared infrastructure to reduce development capital and our 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 two 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 subsurface geology and our existing midstream and infrastructure investment. 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 will set our budget accordingly. I will now turn the call over to Chris Stavros.

Thanks, Vicki and good morning, everyone. Today, I will focus on the following items -- our third-quarter 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 fourth quarter.

Third-quarter 2016 reported financial results for GAAP purposes were a loss of $0.32 per diluted share compared to a loss of $0.18 a share in this year's second quarter. Our third-quarter reported results included a net after-tax charge of $129 million related to nonrecurring items in both the oil and gas and midstream segments. Our core financial results for the third quarter of 2016 were a loss of $112 million, or $0.15 per diluted share, a slight improvement from the loss of $136 million or $0.18 a share during the second quarter.

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 third quarter of 2016 were a loss of $49 million compared to a loss of $117 million in the second quarter and income of $162 million in the same year-ago period. The sequential improvement of $68 million was primarily a result of higher product price realizations.

During the third quarter, the oil and gas segment recorded non-core net charges related to the exit from both Libya and Iraq of $61 million and a $38 million after-tax gain on the sale of some non-core non-operated oil and gas properties in South Texas. Third-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 Hosn in the UAE and production growth in Oman from Block 62.

Total domestic production was 294,000 BOE per day during the third quarter, 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 due to better management around our base production. The sequential decline in third-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 million of free cash flow after capital during the third quarter. In a moment, Jody Elliott will discuss our plans for increased drilling activity in Permian Resources for the fourth quarter and as we exit the year.

International production from our ongoing operations was 311,000 BOE per day during the third quarter of 2016, an increase of 4,000 BOE per day compared to the second quarter. 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 million of free cash flow after capital during the third quarter.

Domestic oil and gas cash operating costs of $12.26 per BOE in the third quarter of 2016 were slightly higher on a sequential basis; however, declined by 7% compared to the full-year 2015 cost of $13.13 per BOE. Nine-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 a further sequential decline in the third 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&A for the third quarter 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 third quarter of 2016 compared to $1.32 per BOE during 2015. The third-quarter exploration expense was $9 million.

Chemicals third-quarter 2016 pre-tax core earnings were $117 million compared with second-quarter earnings of $88 million. 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 million of free cash flow before working capital during the third quarter.

Midstream pre-tax core results were a loss of $20 million for the third quarter of 2016 compared to a loss of $58 million in the second quarter. Despite the loss, the results came in at the positive range of our previous guidance with the sequential improvement resulting from better oil and gas marketing margins.

During the third quarter, we renegotiated some of our crude oil supply contracts, which resulted in an after-tax charge of $103 million. The new agreement should mitigate some of the transportation costs and improve overall profitability going forward.

Turning to our cash flows for the third quarter, we generated $860 million 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 million 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 third quarter were $642 million bringing our total year-to-date capital spending to approximately $2 billion. As Vicki mentioned, our capital spending in the fourth quarter is expected to increase modestly as certain project-related expenditures in both chemicals and midstream have 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 fourth quarter, our total 2016 total capital program is expected to come in slightly under our original budget of $3 billion. We paid $575 million in dividends during the third quarter and ended the period with $3.2 billion 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 $4.5 billion in 2017. Incremental cash flow contributions would include $150 million from the startup of the joint venture ethylene cracker; approximately $200 million from improving results in the midstream segment, which would include the Ingleside crude oil terminal and at least $100 million from the announced Permian acquisitions. In addition, every $1 per barrel improvement in oil prices would provide a further $100 million of operating cash flow.

With respect to guidance and as Vicki mentioned, we now expect our full-year 2016 production growth from ongoing operations to be approximately 7% and exceeding the high end of our previous 4% to 6% range. We expect our companywide production volumes to be in a range of 600,000 to 610,000 BOE per day during the fourth quarter. 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 third quarter with full-year 2016 growth estimated to be about 12%. International production is estimated to be in the range of 310,000 to 315,000 BOE per day during the fourth quarter. This incorporates the impact of a planned maintenance turnaround at Al Hosn 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 fourth quarter and 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 fourth quarter to generate a pretax loss of between $20 million and $40 million. 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 pretax earnings of about $100 million for the fourth quarter, or roughly flat with the third quarter.

Our DD&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 $1.4 billion. The combined depreciation for the chemical and midstream segments should be approximately $655 million. Exploration expense is estimated to be about $25 million pretax during the fourth quarter.

Price changes at current global prices affect our annual operating cash flow by about $100 million for every $1 per barrel change in WTI and a swing of $0.50 per million BTUs in domestic natural gas prices affects our annual operating cash flow by about $45 million. 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 will now turn the call over to Jody Elliott who will provide an update on activity around our Permian operations.

Thanks, Chris. Today, I will provide a review of our domestic operations during the third quarter, guidance on our program in the fourth quarter 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 and well productivity and field develop 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 as 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 third quarter, we added a drilling rig in Permian Resources plus another at the beginning of the fourth quarter and have capacity and locations on standby to respond to improved pricing in 2017.

Turning to the performance of Permian Resources. In the third 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 nine wells put online versus 54 wells in the third quarter 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 nonproducing leasehold acreage in the Permian. In Permian Recourses, 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 billion. We plan on allocating approximately $200 million in capital in 2017 to the acquired acreage utilizing one to two drilling rigs.

Turning to our activities in our core development areas, much of the focus of the drilling program in the second and third quarters was to appraise the potential for multi-bench development in Southern Reeves, Eddy, Howard, Glasscock and Northern Reagan County. In South East New Mexico, we drilled and completed two Cedar Canyon third Bone Spring wells and one 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 BO per day.

In Southern Reeves County, we brought the Roan State 24 51H second Bone Spring well online at the peak rate of 944 BOE per day and a 30-day rate of 702 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 are 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 1720 1H, online with a 7,500 foot lateral, which targeted the Spraberry Formation with a 30-day rate of 931 BOE per day.

As cited last quarter, we now compare and benchmark our well costs on a cost per 1,000 feet of lateral basis as we continue to increase our lateral links. 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 in 2015 to 35.4 per rig in the third quarter. We believe that a significant percentage of these improvements in 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 are aggressively appraising new benches while maintaining focus on improving well recoveries in our development benches. In South East New Mexico, we tested a new second Bone Spring slickwater frac design on the Cedar Canyon 27 Fed 5H with 2,000 pounds per foot and 50 foot cluster spacing. Our cumulative production results from the new design have exceeded the first half of 2016 design and we expect to see continued improvement in future results. We are targeting an average well cost of $7.1 million for the second Bone Spring and $8.3 million for the third Bone Spring with 7,500 foot laterals and the increased completion size. Overall, we are 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 one well and turned one 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 fourth quarter. Our upcoming wells in the fourth 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 third quarter, we drilled eight wells, brought four wells online, three 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 in 12.5 days, rig release to rig release. We completed 10 frac stages in one day and we drilled and completed two Wolfcamp A horizontals for $4.6 million and $4.9 million. 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 improved surface operations with optimized water-handling, lower workover expenses and better downhole performance. Since the second quarter of 2015, we've 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 is 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 fourth quarter of 2016 and bring on approximately 20 wells. We expect production to be about 120,000 BOE per day in the fourth quarter 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 the total lateral length drilled in 2016.

Now I would like to shift to our Permian EOR business. We continue to take advantage of lower drilling costs 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 fourth quarter of 2014 and 7% year-over-year driven mainly by lower downhole maintenance and injectant 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 have mentioned in previous calls, the residual oil zone development, or ROZ, is a vertical expansion of the CO2 flooded interval. The ROZ underlies most of our major EOR properties and can be developed between $3 and $7 per barrel. Year-to-date, we've completed 94 well deepenings and recompletions along with 36 new wells in the ROZ developments. We anticipate an additional 50 deepenings and recompletions and 10 new wells and ROZ developments in the fourth quarter 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 are an existing working interest partner. These properties have production of approximately 4,000 barrels equivalent per day at 80% oil with estimated net proved developed producing reserves of approximately 25 million BOE and total proved reserves of approximately 41 million 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 2.4 million acre portfolio.

We plan to exit this year running eight drilling rigs on our operated acreage plus another 1.5 to 2 net rigs on our non-operated development acreage. We are pleased with the strides our teams have made in subsurface characterization, execution and performance thus far in 2016 and look forward to continuing breakthroughs in 2017. Thank you and I will now hand it back to Chris Degner.

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

(Operator Instructions). Doug Leggate, Bank of America Merrill Lynch.

Thanks. Good morning, everybody. I've got two 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've also shown us you've got a fairly deep inventory of existing assets. I'm just trying to understand the rationale as to why $2 billion is the right use of cash versus a stepup in activity on your existing acreage. If you could 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. Just help us understand the numbers a wee bit.

Yes, Doug, we've been looking at this. 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 five 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 two and provide those synergies around that infrastructure to share that.

The five benches, the shared infrastructure and the operational efficiencies that we will 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 fits within the less than $50 per barrel breakeven price for us or the price that generates positive NPV of $10 for us, so that we think is very prospective. We like how it fits. We believe that we can further develop Barilla Draw. It'll help with the economics there, so the combination of the two of them provides us quite a bit of net present value.

Vicki, I don't want to belabor the point, but I think Jody suggested one to two rigs in this area. I guess what I'm really trying to understand is to justify -- I understand the NPV of the incremental wells, but to justify the NPV of the incremental wells plus the $2 billion acquisition costs, 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 -- guide as to where the activity level on this acreage goes to justify the $2 billion price tag.

Yes, the one to two rigs would be the initial starting point for us on this acreage. We expect to spend about $200 million in 2017. But, in 2017, remember now we are 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 are 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 last one for me, a very quick one on chemicals. Given 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? I will leave it there. Thanks.

Okay.

Hi, this is Rob Peterson. So, yes, we will discontinue the spending of capital, carry over a small amount for commissioning and startup into 2017 and then we will stop spending that and start generating cash from it. So it will be a several hundred million dollar flip between spending capital and generating cash out of the cracker depending on rampup time.

Yes, the swing, Doug, is actually about $300 million in terms of spending versus the contribution. So that's the delta, if you will, spending to cash flow.

Yes, just wanted to check order of magnitude. That sounds great, guys. Thanks so much.

Phil Gresh, JPMorgan.

Good morning. I just wanted to follow up on the cash flow side of things. Chris, you mentioned $4.5 billion of CFO at $50 and if we use the CapEx, call it $3.5 billion, that would be $1 billion of free cash flow versus a dividend of $2.3 billion. So I guess what I was wondering is how you planned 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, 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 are going to do at any given moment, what I would say is obviously it's going to depend on commodity prices. 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 certainly within the range depending on commodity prices.

And on the target leverage side of things, post this deal? Vicki, you mentioned maybe even looking at additional bolt-on deals. 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, the leverage amounts, we are comfortable with that within our ratings right now. We will, obviously, depending on what the acquisition looks like, if we do acquisitions, depends on what it looks like in terms of how we are going to look to fund it. And so some acquisitions are better sourced through leverage, some through other means. So we will just have to look at it. It depends on 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 are comfortable with 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 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.

Ryan Todd, Deutsche Bank.

Great. Thanks. Maybe another follow-up on the budget. I know you referenced additional rigs into the fourth quarter in the Permian, but what level of activity is implied in the Permian in the $3.3 billion to $3.8 million budget for 2017 and how much of that budget is allocated to Permian Resources?

Ryan, this is Jody. The activity level currently planned for 2017 would be about six rigs in the Permian Resources area and three 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've said previously, although it's not final yet, that our capital spend would probably be in the range of 1.3 to 1.4 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 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.

Thanks. Maybe as a follow-up to that, 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 activity in terms of the flexibility you that have over the next few years, whether you see yourselves or the basins in general, the industry in general having any sort of bottlenecks? Anything there would be great.

Ryan, I think we are -- 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 play those things in advance and build out ahead of when that need is going to be. So whether it's Southwest 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 million barrels of frac storage, 40 miles of distribution line; it has produced water treatment systems; 15 SWD wells; gas compression. So all those things have been done extremely well in this acquisition are the same things we do on our own assets and maybe Vicki or Chris will want to address the Greater Permian infrastructure takeaway.

Yes, Ryan, I would just say that with respect to our takeaway capacity out of the Permian, we are 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.

Roger Read, Wells Fargo.

Thanks. Good morning. I guess maybe to come back to expectations in the fourth quarter here. How should we think about the acquired volumes coming in as part of the guidance of the 120 million for Permian Resources? Does that imply that Permian Resources is actually declining here in the fourth quarter and that adds on or how should we think about the exit rate you indicated would be higher?

Yes, Roger, the 120 million includes our estimate of the acquisition, so there's some modest decline in the base core business pre-acquisition. Again, the activity level is ramping up. As you know, when you are doing multi-well, multi-pad development with zipper fracking, the production becomes lumpy. So a lot of that activity happens in the fourth quarter and the production will come very early in the first quarter of 2017.

Okay, so potential for a little bit of -- if things go really well, we could 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 did you come to the 700 and what's an idea of how we should think I'd say maybe $60 oil in 2018, where that 700 locations could go?

Roger, the 700 is based on our conservative nature with assessing our development on property, so that's the minimum location count in the Wolfcamp A, the Wolfcamp B, second Bone Spring. We are very optimistic about the two 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 execution results. I mentioned that we have some technology things working in the drilling area, which we believe can be a step change in multi-well, multi-pad development. And so as we test those in the fourth quarter and in the first quarter of 2017, we will 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 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 one to two 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.

Brian Singer, Goldman Sachs.

Thank you, good morning. Wanted to go back to the comments with regard to the CapEx cash flow for 2017. And if we 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 in even having free cash flow of this magnitude in the first place.

I will tell you, Brian, we consider that, covering our dividend with cash flow, to be a high 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 are 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 narrow in 2018, so there are other things that we can do, but we are 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 have 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 that you desire as you are doing with this acquisition here to be competitive to or more competitive with others in the basin that have a contiguous acreage position?

We viewed 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 are looking for those things that provide us a 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 are 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. Can you characterize the sum of the acreage that you believe now is [developful] and to the common [usement]?

We will update the full inventory picture in the fourth quarter, but to give you a little bit of color, with all of the appraisal work and all of the subsurface work we are 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 -- the acquisition asset is really about just taking ownership in an already derisked 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 hit all of those key drivers that lower F&D costs and keep our OpEx costs really low.

Thank you very much. Really appreciate it.

Evan Calio, Morgan Stanley.

Good morning, guys. You significantly beat Permian Resources' volumes guidance for the second time in three 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. It just looks low versus the commentary.

Yes, Evan, that forecast is based on what we know today. 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. We are 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, eight quarters in a row or so?

Any numbers in the high end of that? It looks like 135. Is that right?

It's a little bit higher than that.

Okay. Maybe a second one, if I could, on the acquisition. Could you say how much of the acquisition was allocated to Permian Resources versus EOR? It looks close to $21,000 an acre versus the $43,000 an acre headline for Permian Resources if we back out what you paid for [JCLIA] using that cost basis metric. Is that right? And then the other side of Singer's question is, with a larger tier 1 footprint, will that increase forward high-grading your portfolio or potential asset sales? I will leave it there.

I would say that, on the net value per acre, we were in the upper $20,000s 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 one 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 five benches is going to make the infrastructure cost so minimal on a per BOE basis that I do believe that this is just going to continue to improve.

And drive -- since it would take capital, would there be another high-grading on the back of that?

There could be. It really depends on product prices for 2017. We will continue to balance our capital with our cash flow needs and the balance sheet.

Okay. Appreciate it guys.

Matt Portillo, TPH.

Good morning. Just starting off on the Permian Resources side, I was curious if you could provide any incremental color or commentary around the base design that you are 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 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 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 will average around 5,000 foot laterals. We will 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 will average around 7,800 foot laterals in 2016 and in 2017. That will 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 will 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 costs.

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 where your proppant loading is and where your fluid volumes are and maybe (multiple speakers).

It's in the 1,750 to 2,000 pounds 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've 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 do you have in moving into 2017 in terms of focusing on some incremental zone delineation in the Wolfcamp and [Abalone] horizon.

So New Mexico will be 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 third 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.

Last question from 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 just wanted to 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 works 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 will 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.