Occidental Petroleum Corp

NYSE:OXY

Earnings Call Transcript 2017-Q4

[Operator]

Good day, everyone, and welcome to the Occidental Petroleum Corporation's Fourth Quarter 2017 Earnings Conference Call. After today's presentation, there will be an opportunity to ask questions. Please also note, today's event is being recorded.

And at this time, I'd like to turn the conference call over to Mr. Richard Jackson, VP of Investor Relations. Sir, please go ahead.

[Richard A. Jackson, Occidental Petroleum Corp.]

Okay. Thank you, Jamie. Good morning, everyone, and thank you for participating in Occidental Petroleum's Fourth Quarter 2017 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Jody Elliott, President of Domestic Oil and Gas; Ken Dillon, President of International Oil and Gas Operations; and B.J. Hebert, 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-K.

Our fourth quarter 2017 earnings press release, the Investor Relations supplemental schedules and our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off our website at www.oxy.com.

I will now turn the call over to Vicki Hollub. Vicki, please go ahead.

[Vicki A. Hollub, Occidental Petroleum Corp.]

Thank you, Richard, and good morning, everyone. Before I talk about our business results, I'd like to first thank our employees for their efforts to ensure a safe workplace for our employees, contractors and the public. In 2017 we had the best employee and combined employee contractor injury and illness rate than we've ever had. In addition, OXY Oil & Gas had an industry-leading employee IIR – that's illness and injury rate – of 0.11. This is a result of a long trend of improving safety performance which indicates that safety is not an initiative for us. It's a part of who we are. It's embedded in our culture, which is a reflection of the quality and commitment of our employees. On behalf of the management team and our board, I want to thank our employees for owning safety.

Today, I'll share some highlights from 2017 and then some key items we consider for disciplined reinvestment and what that means for allocating capital. I'll then conclude with details of our 2018 capital program. Cedric will update our progress on our breakeven plan.

In 2017, we focused on improving our cash flow through value-based growth in Permian resources, enhancing our portfolio, increasing the value of our assets and using technology to drive operational performance. We enhanced our portfolio by increasing cash flow from OxyChem in 2017 with the completion of the Ingleside ethylene cracker, which reached full capacity in 2017. OxyChem will provide additional incremental cash flow in 2018 from the 4CPe plant that was commissioned and put on production in December of 2017.

The plant, located in Geismar, Louisiana, uses an OxyChem patented process to produce 4CPe, which is a raw material used in making next generation climate-friendly refrigerants with low global warming and zero ozone depletion potential. The project was completed on time and on budget and it represents another significant accomplishment within our breakeven plan.

We increased the value of our assets through increased productivity, significant reserves replacement, optimum cash flow from our international operations and increased exports from our Ingleside crude export terminal. Our increased productivity came mostly from our Permian Resources business, where we achieved record initial production rates across eight benches and continued to deliver step change well results in Greater Sand Dunes during the fourth quarter. These results have helped drive our capital intensity down while adding to our long-term reserve potential.

For two years in a row, we've achieved all-in reserve replacement ratios of nearly 190% companywide, with F&D costs of less than $10 per BOE. In Permian Resources, our reserve replacement ratio in 2017 was a record-setting 365% with an F&D of $9.77 per BOE. We've provided additional details on our 2017 reserve data in the appendix and earnings release. We'll continue to focus on optimizing recoveries and F&D costs through our value-based development approach.

Equally important were similar improvements in our international businesses where we generated over $1 billion of free cash flow, and I want to take a moment to recognize our Oman team. We've operated in Oman for almost 35 years and recently achieved a significant milestone with a production of our 1 billionth barrel of oil. With the extension of Block 9 and a new contract in Block 30, we're excited about continuing our long history of success and partnership in Oman.

Lastly, I'd like to emphasize how advancing technologies have improved our operations. Our investment in subsurface characterization has driven progress in both our unconventional EOR assets and our unconventional assets, and we're increasingly finding more synergies between them. Four unconventional EOR technical pilots that we began in 2014 have increased our technical understanding of how these two assets will work together in the future and will provide significant option value across our large Permian position.

This innovative work in combination with our petrophysical advancements to improve primary recoveries positions us to lead the industry in full-cycle value and return on capital employed. We're also advancing our use and sequestration of anthropogenic or manmade CO2. One important step was our work with EPA to develop the first monitoring, reporting and verification, or MRV, plan for CO2 injected in our Denver unit asset in 2016.

Our MRV plan provides transparent and formal accounting for permanent geologic sequestration as a part of our EOR process. During 2017, we applied for and received approval for another MRV plan in our South Hobbs asset, the second ever issued by the EPA. We reported volume sequestered at the Denver unit in 2017 and will report our sequestration amounts for both assets in 2018. These two assets represent two of our 34 CO2 EOR floods in the Permian and through our MRV plans, we'll demonstrate the significant potential that exists in our assets to store CO2.

Another important advancement of CO2 sequestration through EOR occurred last week when Congress passed the FUTURE Act. This legislation can help incentivize the development of new carbon capture projects making more anthropogenic CO2 available for sequestration and EOR operations, operations that have MRV plans.

This policy and technical advancements combined with our significant CO2 EOR position and infrastructure could provide emerging opportunities for OXY and the lower carbon future we must all work to achieve. We look forward to continuing to grow our leadership in this space.

To complement our subsurface advancements, our teams have also worked on innovative solutions to manage costs long term. We continue to make progress on the recently developed technologies and operational differentiators that we introduced to you during 2017, such as SL2, our multi-lateral technology; and our logistics and maintenance hub in Southeast New Mexico, this hub which will ramp up operations through the first half of 2018.

To summarize our key progress in 2017, we showed three key metrics on slide 5. Enhancements to our portfolio enabled us to fund our dividend and sustaining capital with our cash flow from operations and to fund our growth capital with a combination of cash on hand, our tax refund and proceeds from net asset sales. This advanced our plan to break even.

The 20% improvement in the six-month cumulative production volumes we achieved in Permian Resources will significantly increase our resources value. This is a result of several years of excellent subsurface work that is beginning to fully mature and be visible in our results. Finally, our ability to replace our production at close to 190% replacement ratio with high quality, low F&D production makes us very confident that this is sustainable for a long period of time, and will deliver top tier return on capital employed and will provide more total returns to our shareholders.

Turning to slide 6, our value proposition has not changed. When others chose to cut or eliminate their dividends, we developed a plan to continue and strengthen ours. We view our value proposition, which is founded on dividend growth, to be a commitment to our shareholders and not an option. We've been able to pursue this strategy consistently for many years as a result of the quality of our assets and the discipline of our management team.

As you can see on slide 30, over the past 16 years, we've given $30 billion back to our shareholders through dividends and share buybacks. Our scale, combined with the free cash flow generation of our international assets, Permian EOR and Chemicals, along with the growth of our premium Permian Resources position creates a truly unique value proposition, in that we can provide strong dividends and meaningful growth as well.

Our cash flow priorities also have not changed. Sustaining capital and dividends are non-discretionary items. Our first priority is to maintain an operationally and environmentally safe business. Our second priority is to grow our dividend as we've done for the past 15 years. As we look beyond our cash flow breakeven plan, we will consider several key factors for disciplined reinvestment that support dividend and production growth long term.

Our investment decisions are focused on maximizing return on capital employed. We will not invest in projects unless they deliver a minimum return of 15% for domestic and 20% for international. The other factors we consider are, one, pacing growth to maximize net present value; two, improving low cost inventory; three, maintaining an industry-leading decline rate; four, sustaining a secure capital structure for downside protection and upside opportunistic value creation through the inevitable commodity cycles; and five, appraising long-term social and environmental opportunities to risk, like potential carbon pricing.

Now I'll update you on what this means for our next steps immediately beyond achieving our breakeven plan, as on slide 6, where we've illustrated what this looks like at various oil prices. Our first priority is to complete our breakeven plan and we expect to achieve this ahead of schedule. Our breakeven plan will secure our sustaining capital, current dividend and 5% to 8% production growth at $50 WTI.

Beyond these milestones, we believe it's important to improve our dividend payout ratio and reduce our net debt. This means that in the short term at $50 WTI, we'll grow the dividend at a nominal rate similar to last year, while investing in both short and long-cycle projects to deliver 5% to 8% growth. Any additional cash flow will be retained to improve our net debt metrics and be prepared for value-adding growth opportunities. We believe this conservative approach will further strengthen the sustainability of our dividend while giving us flexibility to remain opportunistic.

Beyond these initial steps, we'll manage incremental dividend growth and reinvestment opportunities within the framework I've discussed. At greater than $60 WTI, we're able to accelerate our payout ratio improvement and net debt reduction, and will weigh growing towards the higher end of our 5% to 8% range and growing our dividend more meaningfully.

Turning to slide 7, our capital program was designed to achieve our breakeven plan in the third quarter of this year. We expect this program will generate annual growth of 8% to 12%. Chemicals spending has rolled off significantly, which will enhance free cash flow generation. In Midstream, overall capital will increase modestly versus last year to accommodate an expansion of the Ingleside crude export facility. We recently awarded EPC contracts to expand the capacity of the terminal by 2.5 times, up to 750,000 barrels per day.

Total Oil & Gas capital spend will be approximately $3.3 billion. The international capital is primarily for sustaining purposes as we complete our breakeven plan, but we expect higher investment in our international business in 2019 and beyond.

Similar to the international business, the Permian EOR business will spend capital to sustain current production levels. Permian Resources will receive a total of $1.9 billion in capital, of which $1.2 billion is for growth.

I'll now turn the call over to Cedric to review our progress towards the breakeven plan and our financial results.

[Cedric W. Burgher, Occidental Petroleum Corp.]

Thank you, Vicki. I will begin with an update on our breakeven plan and then address financial results and 2018 guidance. On slide 9, we have updated our progress towards our breakeven plan at low oil prices. As the chart shows, we've made substantial progress towards this goal, and our business segments are exceeding targets. As noted in last night's press release, we have further accelerated our timeline and now expect to accomplish the plan by the third quarter of this year. As most of you know, once we achieve our remaining milestones, we will have the cash flow necessary for our $40 oil price business sustainability case or our $50 oil price business growth scenarios.

Slide 10 illustrates our progress towards the breakeven plan. In the Chemical business, the 4CPe plant came online in December and will begin contributing towards the breakeven plan next quarter. In the Midstream business, the Midland-to-Gulf Coast spread remained wider than our breakeven plan assumption of $2.10 per barrel, as it averaged $4.61 per barrel during the fourth quarter. Ken Dillon will tell you about the Al Hosn Gas plant debottlenecking that's beginning in the first quarter, and we have provided additional details on the capacity upgrade to our crude export terminal in the appendix.

In the Permian Resources business, we grew 20,000 BOEs per day sequentially, leaving 50,000 BOEs per day to achieve our goal. Jody will give you additional guidance on the timing of new wells online and production. The Chemical and EOR businesses are making operational gains and experiencing market improvements beyond our initial plan. Caustic soda realizations, a key profitability driver for the Chemicals business, improved further in the fourth quarter and solidified $150 million of market improvement shown in the other improvements category of our slide.

In the EOR business, we have achieved the $5 per BOE of cost savings we expected from the integration of the Seminole-San Andres CO2 unit into our network of floods. We have included a slide in our appendix highlighting this progress. We are excited by the progress we have made and we will continue to communicate incremental progress towards our pathway to breakeven.

My next slide illustrates our liquidity needs for 2018, and it has changed markedly in our favor since last quarter. We have adjusted the chart to reflect a commodity price of $50 WTI and our new capital budget of $3.9 billion. At $50 WTI, the cash required to attain our breakeven plan is more than covered by our cash balance, and, at current prices, we would not need a cash flow deficit – we would not run a cash flow deficit during 2018. At the end of the fourth quarter, we had $1.7 billion of cash and the Plains units with a market value of approximately $600 million. In addition, we expect to evaluate and find opportunity to monetize non-core assets to maximize net present value of our portfolio.

Shifting to our quarterly financial and operational results on slide 13, I'd like to start with our production results. Total reported and ongoing production was 621,000 BOEs per day. Permian Resources came in within guidance at 159,000 BOEs per day. Permian EOR increased by 2,000 BOEs per day to 155,000, a result of a full quarter of acquisition volumes. International came in at 302,000 BOEs per day.

I'd like to take a moment to reconcile our fourth quarter production versus guidance. On the international side, our fourth quarter guidance was based on a Brent pricing assumption of $53 per barrel. Production sharing contracts, or PSCs had approximately a 5,000 BOE per day impact on our production, given that Brent averaged over $61 per barrel or an $8 increase versus our guidance assumption. While higher Brent prices are clearly a net positive overall, it does result in reduced production volumes for us.

On the domestic side, the Permian experienced third-party downtime of approximately 4,000 BOEs per day, outside operator production timing of 2,000 BOEs per day and weather impacts of 1,000 BOEs per day. The international and domestic items totaled approximately 12,000 BOEs per day, which reduced our production below our fourth quarter guidance. However, as Ken and Jody will detail, we are confident with our plan for 2018 and the execution fundamentals of our production growth continue to improve.

Earnings improved across all segments in our fourth quarter. Reported EPS was $0.65 and core EPS was $0.41. Reported earnings included about $575-million benefit from the revaluation of deferred taxes related to federal tax reform, which significantly decreased our fourth quarter effective tax rate.

Improvements in the Oil & Gas business segment were mainly attributed to higher oil and NGL prices. Realized oil prices increased 16% and NGL prices increased by 21% from the prior quarter. Operating cash flow before working capital improved sequentially to nearly $1.5 billion due to higher oil and NGL prices, along with higher Permian Resources production. We spent $950 million in our Oil & Gas capital program during the fourth quarter. Total year Oil & Gas capital was $2.9 billion and we met our total capital budget of $3.6 billion.

Chemicals fourth quarter core earnings of $217 million came in above guidance, primarily as a result of higher realized caustic soda pricing. Midstream fourth quarter core earnings of $129 million also came in well above our guidance due to higher marketing margins from improved spreads and exports through our terminal.

With respect to 2018, we are affirming a capital budget of $3.9 billion, which will generate 8% to 12% annual production growth. This equates to a total company production range of 640,000 to 665,000 BOEs per day. Our guidance assumes $60 WTI and $65 Brent for the first quarter and $55 WTI and $60 Brent for the remaining quarters.

The 2018 Permian Resources budget of $1.9 billion will drive a production range of 195,000 to 209,000 BOEs per day. The midpoint of this range equates to an annual production growth rate of more than 40%. Jody will provide additional color on our 2018 Permian plan.

The 2018 international budget of $800 million will maintain a production range of 286,000 to 297,000 BOEs per day, which is sequentially lower due to the impact of higher oil prices on PSC contracts. Ken will provide additional details on the capacity expansion of the Al Hosn Gas plant.

In the first quarter, we expect total production to range from 592,000 to 603,000 BOEs per day. Jody will give additional detail on the Permian Resources outlook. International production in the first quarter will be impacted by turnarounds at Al Hosn Gas and Dolphin. Al Hosn volumes are expected to average 58,000 to 59,000 BOEs per day during the first quarter and will ramp to 83,000 BOEs per day by the third quarter.

In Midstream, we expect the first quarter to generate pre-tax income between breakeven $10 million and $30 million, assuming a Midland-MEH spread of $3 to $3.25/BOE. The first quarter guidance also accounts for the turnarounds at Al Hosn and Dolphin. On a full year, we expect pre-tax income to range between $200 million and $300 million based on a Gulf Coast spread range of $2.50 to $3/BOE.

In Chemicals, we anticipate first quarter pre-tax earnings of $250 million as the seasonality of sales for certain products improves in the first quarter. On a full year, we expect pre-tax income to approximate $1 billion, assuming caustic soda prices remain at current levels. As a reminder, a $10-per-ton move in caustic soda price equates to a $30 million in pre-tax income.

Our DD&A expense for Oil & Gas is expected to be approximately $13.50 per BOE for 2018 compared to $14.87 last year, largely as a result of lower finding and development costs. Cash operating costs for the domestic Oil & Gas business are expected to average $12.50 during 2018, compared to $11.73 last year. Lower operating costs in the Permian Resources, which are expected to average under $7 per BOE, are expected to be offset by higher costs in the Permian EOR business for oil price-sensitive purchased injectant and higher energy-related costs.

And, finally, on slide 16, we have provided you with key cash flow sensitivities.

I'll now turn the call over to Jody.

[Joseph C. Elliott, Occidental Petroleum Corp.]

Thank you, Cedric, and good morning, everyone. 2017 was an incredible year for our domestic business. Our teams leveraged our subsurface workflows and operating capability to drive improvements that derisked our cash flow breakeven plan and added significant long-term value to our assets. We monetized non-strategic assets with three key results. First, we acquired the CO2 EOR Seminole-San Andres unit to enhance our low decline Permian EOR business.

Second, we invested additional capital into our Permian Resources strategic development plan and third, we cored up a Midland Basin multi-bench area we are now developing. We will continue to review our portfolio in 2018 and look for additional value-adding transactions. Our value-based development approach provided outstanding results across our business. Breakthroughs in geomechanics and petrophysical analysis of flow units drove an approximate 20% improvement in Permian Resources well productivity. Permian Resources lowered fourth quarter operating costs to $7.63 per BOE, a 9% improvement from the fourth quarter of 2016.

In Permian EOR we've made significant progress at the recently acquired Seminole-San Andres unit. In just one quarter, we increased production by 3,600 gross BOE per day, reduced OpEx by over $5 per BOE and reduced flaring by 60%. We've also improved the economics of future development by reducing drilling costs by over 30% or $500,000 a well.

I also want to highlight our progress in advancing new technology. As Vicki mentioned, we've implemented four different unconventional EOR pilots across the Midland and Delaware Basins. The initial results are encouraging and we believe that our position, scale and over 40-year history of operating EOR projects provide OXY with an advantage that will be extremely difficult to replicate. Progressing this technology will allow us to incorporate EOR into our future development plans and realize value with this upside option beyond just primary recovery. We're excited about these pilots and the future opportunity they represent.

Turning to slide 19, the Permian Resources team added 750 locations to our less than $50 breakeven inventory in 2017, almost double the target set at the beginning of the year. This represents an additional four years of development at a 10-rig pace. The additional 325 locations added from lower cost and well performance are based on repeated improvements that are sustainable.

Over 17,000 total net acre trades resulted in an additional 125 locations by enabling us to drill longer laterals and consolidate facilities. We are extremely pleased with the progress made improving our inventory in 2017 and believe that our focus on value-based development and innovative technology will continue to grow our breakeven inventory in excess of our drilling pace.

On slide 20, our Greater Sand Dunes area delivered another quarter of play-leading results across multiple benches. In the fourth quarter, we brought online a total of 17 new development wells and one Avalon appraisal well. Our new wells in the fourth quarter had continued step change productivity results as we had achieved in the third quarter.

Our confidence continues to increase in 2018 as in January, brought the Cedar Canyon 27/28 Fed 44H online that achieved a record 24-hour peak rate of 8,361 BOE per day and a 30-day rate of 6,111 BOE per day. As I mentioned in our last call, our understanding of localized production drivers across our position gives us confidence that we'll continue to deliver high rate of return wells across the more than 2,000 undeveloped locations in Greater Sand Dunes. In 2018, we will further integrate 3-D seismic, data analytics and deploy other emerging technologies for continued improvement.

Beyond Greater Sand Dunes, I also want to highlight a new six section modular development area in New Mexico called Turkey Track. The Turkey Track 9-10 State 32H in the 3rd Bone Spring has produced over 200 MBOE in 90 days, and all five wells online in the fourth quarter are performing above expectations. We expect Turkey Track to deliver over a 40% all-in rate of return at $50 per barrel. While Turkey Track is only six sections, OXY has significant acreage in this region of Northern New Mexico Delaware Basin. This modular development approach allows us to leverage scale across multiple smaller development positions.

Innovative facilities design and development sequencing allows us to reduce costs for operations across several sections while using regional subsurface characterization and operating efficiencies to leverage our basin-wide scale advantages.

On slide 21, I'll walk through Permian Resources production for the fourth quarter and discuss the outlook for 2018. The continued improvements in well productivity and development optimization have put us ahead on our breakeven plan milestone. We now expect to achieve the 80,000 BOE per day of growth in the third quarter of 2018. We're extremely confident in our ability to execute this plan as critical resources were secured in 2017.

Looking at the fourth quarter of 2017, good execution and well performance contributed to growing production by 20,000 BOE per day from the prior quarter, and achieving a December exit rate of 172,000 BOE per day. However, during the fourth quarter, we incurred approximately 6,000 BOE per day of downtime due to third-party pipeline and processing disruptions, OBO delays and weather downtime.

In the first quarter, we changed our development plans to move a rig from Turkey Track, a two-well development area, to a Texas Delaware four-well pad development area. This change was made based on the better-than-expected 3rd Bone Spring results in Turkey Track, so we can now pace this development differently to allow multi-bench development with the 2nd Bone Spring and ensure there's no additional cost incurred for facilities or trucking. This change reduces the number of wells online in the first quarter due to the larger pad activity, but is the right value-based decision and enhances our total-year production delivery.

First quarter production has been impacted by early January freezing weather by approximately 2,000 BOE per day. But again, this does not change our strong outlook for the year. We've provided a quarterly production range for 2018 to help follow our progress as we're set to achieve approximately 45% production growth from 4Q 2017 to 4Q 2018.

On slide 22, we provided details on our 2018 Permian Resource capital program. Consistent with our cash flow breakeven plan, our capital for the year is $1.9 billion. We will operate a total of 11 rigs and fund an additional two net non-operated rigs. We plan to appraise at least six new benches across our development areas that will provide future growth opportunities. We will also start realizing the benefits of Aventine, our maintenance and logistics hub, which is now online with sand delivery and will be fully operational by the end of the second quarter.

The partnerships created as part of project Aventine will provide efficiencies and allow better margins for OXY and our partners. Our initial savings target per well from project Aventine is between $500,000 to $750,000 per well, but we believe the full value implications are much higher as we expect improvement in time-to-market, last mile and well site logistics, safety and future operating costs. We will also continue progressing unconventional EOR pilots and implement new pilots in 2018, and will provide updates and share results as we can.

2017 was an incredible year, and we're even more excited and confident about 2018.

Thank you, and I'll now turn the call over to Ken.

[Kenneth Dillon, Occidental Petroleum Corp.]

Thanks, Jody, and good morning, everyone. We had a strong year in the international business with our achievements summarized on slide 24. The focus of the business during 2017 was twofold. First priority was cash generation which the upstream business delivered to the tune of over $1 billion in free cash flow. Second priority was continuing to develop a pipeline of potential projects in our core countries. This inventory is focused on strong returns for OXY and our partners. It builds upon our operational excellence in our core countries, including the use of the latest 3-D seismic technology and drilling successes in Oman and Colombia.

Our major projects continue to be delivered on-time and on-budget as shown on slide 26. And we did all of this while achieving the best international HES performance in OXY's history. There are a number of topics that I'd like to mention today. First is the debottlenecking of the Al Hosn Gas plant which will begin during the first quarter and be completed in the second quarter 2018. Last year, during our annual turnaround, we were able to optimize the gas plant for no additional capital. This contributed to the increase in production from 64,000 BOE per day in 2016 to 71,000 BOE per day in 2017.

This year during the turnaround, we will debottleneck the plant for an additional 11% in production from fourth quarter 2017 to third quarter 2018 for only $10 million of capital. This debottlenecking will bring the cumulative expansion versus the original plan to approximately 30%, as shown on slide 25.

Production during the first quarter will be approximately 59,000 BOE per day, and we will achieve a peak rate of approximately 83,000 BOE per day in the third quarter. We're able to achieve this by utilizing a new patent-pending process to modify the inlets to the plants absorbers.

Next, I'd like to talk about the continued consolidation of our position in Northern Oman. We successfully renewed our Block 9 contract and we recently signed an exploration and production sharing contract for Block 30, which enhances our position. We see opportunities for gas production in the area and synergies with our adjacent position in Block 62.

I'd like to highlight the performance of several projects in Colombia. In December, we reached a milestone of 45,000 barrels a day at the La Cira-Infantas field. This was achieved just ahead of the 100th anniversary of the discovery well, and we're excited about the continued development of the field. The TECA Steamflood pilot continues to exceed our expectations, and a development project will be moving towards sanction this year. The project exceeds our international economic hurdle rates. Both of these projects are excellent examples of our organization's expertise in enhancing the recoveries of mature and complex fields.

Lastly, we've been successful with our step-out drilling programs in Oman and Colombia, which have added over 50 million barrels of net resource in the two countries. I'd like to thank the team for its disciplined work and commitment to safety. We're very pleased with how the business performed in 2017 and excited about the opportunities in our pipeline.

I will now turn the call back to Vicki.

[Vicki A. Hollub, Occidental Petroleum Corp.]

Thank you, Ken. I'd like to close by commenting on executive compensation since we've been engaging with the investment community on this topic. We have expanded the use of returns-based metrics for executive incentive compensation. The changes will impact both our short and long-term incentives by incorporating cash return on capital employed as a key performance target, with a short-term target of 18% and a long-term target of 20%.

At our 2018 target compensation level, cash return on capital employed-based compensation will comprise about 20% of the total. This policy is consistent with our historical practices at OXY and improves alignment with our shareholders.

We'll now open it up for your questions.

[Operator]

Ladies and gentlemen, at this time we'll begin the question-and-answer session. Our first question today comes from Roger Read from Wells Fargo. Please go ahead with your question.

[Roger D. Read, Wells Fargo Securities LLC]

Yeah. Thanks. Good morning. If we could go to slide 4, the talk about well productivity improvement. And I was curious, is there a way that you could break that out at all between just changes in physical things like lateral length and the number of stages versus – you've mentioned multiple times, the improvement in well productivity, how much of that is a design change or better rock, or you know, all the opportunities that are there?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Yes, Roger. Good morning. This is Jody. It's really a combination of both. If you look at lateral length in 2017, it's about a 10% increase in overall lateral length. But our productivity improvement is on the order of 20%. And you have to remember this is based on a six-month cumulative, so a lot of the good wells that came online in the back half of the year aren't yet included in that improvement number. So it's a little bit lateral length, but a lot about, again, how we land these wells, the flow unit work that we do to optimize where we place them, and then continued completion design changes to increase stimulated rock volume. But it's a combination of both, but more performance-driven than lateral length-driven.

[Roger D. Read, Wells Fargo Securities LLC]

All right. Thanks. Can I get you to hazard a guess on continued improvement on productivity at all or any sort of an internal target?

[Joseph C. Elliott, Occidental Petroleum Corp.]

I don't know if I can throw a number out. I mean, I get surprised every day with the improvements our teams continue to make. And I see some of the technology things we're working, whether it's in the execution side or on the completion side, and I still think there's more ahead. We've got some new frac designs coming out this quarter in Greater Sand Dunes, and I think those are going to lead to even better rates.

And in addition to better rates, I think we're reducing our issues with offset frac hits and having to shut wells in because of doing frac work nearby. So not only are we trying to improve performance, we're trying to minimize the base production that's already online.

[Roger D. Read, Wells Fargo Securities LLC]

Okay. Kind of getting rid of the parent/child issues we've seen elsewhere then.

[Joseph C. Elliott, Occidental Petroleum Corp.]

Exactly.

[Roger D. Read, Wells Fargo Securities LLC]

Okay. And then maybe just changing direction with my follow-up. I don't know for you, Vicki, or for Cedric. With the company now certainly line of sight to the breakeven at $50 or effectively there at current prices, how do you think about the dividend or share repurchases as the company moves out of 2018 and into 2019? What's the preferred method for shareholder returns here?

[Vicki A. Hollub, Occidental Petroleum Corp.]

Well, we prefer dividends, because the dividends are given directly to the shareholders, and it's often hard to predict the impact of the share repurchases. But we have done a lot of share repurchases over time, as we showed you in the graph, but the way we kind of look at it is we do it when we think it makes the most sense and adds the most value. And we sort of do that calculation by looking at the value of the Chemical and Midstream businesses and taking that from the total value of the company, but including debt and cash levels, then you divide that by your total proved reserves. Then when you compare that to your finding and development cost for the projects that you're in and, in that scenario, we would go today investing more in the projects that we're doing.

But with that said, in those scenarios where we have incremental cash, and we don't want to accelerate our pace of development because that would potentially destroy value, in those scenarios, assuming our stock is a little bit lower than normal, those would be scenarios that we buy shares back into the company, and you've seen us do that. So that would be something that we certainly would consider doing.

We never want to talk about it in advance, because we don't want to let others know that we're doing it. We want to make sure that we eliminate the potential of others buying our stock as we've talked about buying it back. So we think this approach, as we consider that limits our natural bias to think that the stock's always undervalued and it makes the calculation pretty straightforward.

[Roger D. Read, Wells Fargo Securities LLC]

All right. Appreciate that. Thank you.

[Operator]

Our next question comes from Brian Singer from Goldman Sachs. Please go ahead with your question.

[Brian Singer, Goldman Sachs & Co. LLC]

Thank you. Good morning.

[Vicki A. Hollub, Occidental Petroleum Corp.]

Good morning.

[Brian Singer, Goldman Sachs & Co. LLC]

As we think about the path to achieving that $50 breakeven, I wanted to just focus a bit more on your expectation to reduce well costs in the Delaware, in particular, which I think you have on slide 53. Based on your contracts, how exposed are you to market inflation risk relative to what you have in the slide? And can you also talk a little bit more about the drivers of the design and efficiency improvements and the risk there to the upside and the downside?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Hey, Brian. This is Jody. The slide 53 is one example of a well type in New Mexico. It's a 2nd Bone Spring 10,000-foot well. It's a three-string design, assumes 2,000 pounds per foot in the completion, includes everything, its hookup, flowback, first artificial lift, capitalized overhead, so it's an all-in capital cost.

We see pressure on inflation, obviously. It's probably in the 5% range in the drilling area and more like 10% to 15% in the completion space. But with securing our resources in 2017, we're separating sand from pumping service and now with the startup of Aventine in 2018, we see our ability to offset and even drive down cost in an inflationary period. This is something we started a couple of years ago when we looked back at what really drove our improvements back then, and anticipating an inflationary cycle, what would we do different.

So we focused on maintaining time to market, securing supply, securing resources, working the things that drive time to market because they're a much bigger part of the equation than just unit cost. And I could talk for a long time about Aventine, but there's a lot of things in place not just sand delivery but oil country tubular goods on rail instead of truck, the OxyChem hydrochloric acid facility, our work with Schlumberger there, a new sand delivery system for the last mile logistics that will drive down trucking and reduce the number of people required on location. So I'm just naming off a few. There's a long list of things that we believe continue to improve the cost structure, the capital intensity of our work in the unconventional business.

[Brian Singer, Goldman Sachs & Co. LLC]

Thanks. And I know this is just one example, but are well cost reductions of this type of magnitude baked into the $1.9 billion capital budget for Permian Resources or would achievement lead to lower capital needs relative to that?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Yes, we've baked in kind of flat from where we are today. So I think there's upside opportunity as we work through this next generation of technology. So some of those are in there that's in our flat assumption, but we're just getting started with Aventine.

[Brian Singer, Goldman Sachs & Co. LLC]

Thanks. And then can you talk a little bit more about the six new benches you're planning to appraise in the Permian in 2018, and how the acreage you plan to evaluate compares to the new acreage that I think you said added 150 locations in 2017?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Yeah, it's 1st Bone Spring, Avalon, 2nd Bone Spring Lower in New Mexico, 2nd Bone, 3rd Bone, Wolfcamp C and Greater Barilla Draw. Greater Barilla Draw is 50,000 net acres, so success in those other benches really gives you a lot of scale to work with.

[Brian Singer, Goldman Sachs & Co. LLC]

Great. Thank you.

[Operator]

Our next question comes from Phil Gresh from JPMorgan. Please go ahead with your question.

[Vicki A. Hollub, Occidental Petroleum Corp.]

Phil, could you hold just a second? We did have another comment from Ken, international.

[Kenneth Dillon, Occidental Petroleum Corp.]

Yes, just to follow on from Jody, on the international side, same drivers for us internationally, market forces and OXY in-house technology, we still see deflation continuing in drilling and completion arena at the moment, mainly because of the discipline of the NOCs and IOCs in this market, but also the entry of some new competition in the various product lines.

We rolled out OXY Drilling Dynamics 3.0 at the start of 2018, we're making modifications to our drilling rig fleets and hardware, software and data analytics. If you look year-on-year in Oman North and in Colombia, we've reduced costs in Oman North by 12% and 26% in Colombia in these product lines. And if you look over the last three years for ourselves and our partners, we've saved over $420 million in the drilling and completion side and we're hoping that, that will continue this year.

[Vicki A. Hollub, Occidental Petroleum Corp.]

Okay. Phil, good morning.

[Phil M. Gresh, JPMorgan Securities LLC]

Good morning. First question coming back to capital spending, this year you're at $3.9 billion, which is towards the upper end of the range you had talked about previously of the $3.6 billion to $3.9 billion. Obviously, there's accelerating production growth that comes with that. But I guess I'm kind of wondering as we look ahead, Vicki, you've talked about a commitment to have a meaningful step down in CapEx in 2019 on the back of hitting the breakeven. So just want to get your latest thoughts on that. And you talked a bit about the various tradeoffs in your opening remarks, but is there a specific commitment you're thinking about or a roll-off of infrastructure spending or anything that will be driving CapEx materially lower next year?

[Vicki A. Hollub, Occidental Petroleum Corp.]

Well, once we get to the breakeven plan, we're still going to go back to our original 5% to 8% growth. We're forecasting 8% to 12% this year but next year in 2019, we'll target the 5% to 8% growth. And targeting that growth with our dividend means that we'll certainly be able to reduce our CapEx below where it is today and back more toward the $3.4 billion to $3.45 billion range.

[Phil M. Gresh, JPMorgan Securities LLC]

Okay. Got it.

[Cedric W. Burgher, Occidental Petroleum Corp.]

Phil, this is Cedric. I would just add, as I said in my prepared remarks, once we complete the plan, we will be able to live within cash flow, including and cover the dividend, even as low as $40. And so part of the answer to your question depends on what the commodity price environment will be going into 2019. But we will have that ability even at low commodity prices to sustain our base and the dividend all within cash flow.

[Phil M. Gresh, JPMorgan Securities LLC]

And if I could just ask maybe a clarification for my second question. There was a comment about higher international spend in 2019, and I heard some of the prepared remarks there, but what's the order of magnitude that would be baked into the $3.4 billion to $3.45 billion?

[Vicki A. Hollub, Occidental Petroleum Corp.]

So it wouldn't be significant, because what we have in Oman and some of the international operations are these shorter cycle projects that actually could – we could vary that. We can almost vary like we do the Permian in terms of picking up rigs and activity levels. Ken, did you have an additional comment on that?

[Kenneth Dillon, Occidental Petroleum Corp.]

Yes. Part of our focus this year is picking up on the exploration wells and step-out wells that we did last year. We've added 50 million barrels of net resource. Our goal is to call these up this year, get them online. So some of the capital in Colombia will go towards that.

[Phil M. Gresh, JPMorgan Securities LLC]

Okay. Got it. And then my second question is around the OpEx for the U.S. The guidance of $12.50 a barrel. It's a little bit higher than my model, not hugely so, but given that the incremental – the resources barrels are coming on I think at $2 to $3 per barrel that you've talked about in the past. And I think 4Q ended sub-$8 a barrel. So I'm just trying to understand maybe some of the moving pieces there, and if you have any color about where the EOR cost is given the higher oil price et cetera?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Yeah, Phil. It's Jody. So in Resources, we exited fourth quarter with OpEx of $7.63. We expect operating expense in 2018 to be below $7, more like $6.75. We'll exit 2018 below $6. So that additional production growth will continue to drive down Resources OpEx.

On the EOR side there's two components. The fundamental – the things we control on rig work and those kind of things is pretty flat. The two things that move with oil price, one is there's some CO2 contracts that are indexed to oil price, or part of the contract is indexed to oil price. So as oil price goes up, the cost of CO2 goes up. The other is we're injecting about almost 3% more CO2 this year in 2018 than we will in 2017. As you know we've started a new flood and we've expanded several others, and so that's consuming the CO2 on the front end, and obviously the production comes as you go through the lifecycle of those projects.

[Phil M. Gresh, JPMorgan Securities LLC]

Got it. So EOR is closer to $20 then per barrel?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Yeah, I don't have the number right here in front of me. We'll get it to you.

[Phil M. Gresh, JPMorgan Securities LLC]

Okay. Thanks a lot.

[Operator]

Our next question comes from John Herrlin from Société Générale. Please go ahead with your question.

[John P. Herrlin, Société Générale]

Yeah. Hi. Thanks. Most everything's been covered. I was just curious about the EOR activity in Permian Resources, what you're expecting to get out of the wells by pursuing that. And then the other one is on the Aventine venture. Will this be your only joint venture? Like Schlumberger mentioned the joint venture on their call with you, or working with you, I was wondering are you going to do more of these corporate things to help manage costs in the future? That's it.

[Joseph C. Elliott, Occidental Petroleum Corp.]

Sure. Be glad to talk about both. So the EOR work in the unconventional space, when you look at primary production, you're recovering 8%, 10% of the production. So there's a tremendous resource there. So the objective or the challenge is how can we increase that materially and do it economically.

And so with either CO2 injection or miscible gas injection, both in the lab and in the trials in the field, we've demonstrated we can recover incremental oil. And it doesn't behave like the traditional conventional CO2 flood where you inject then you push oil to the producers and it's a long cycle project. The oil recovery is actually quite quick, so it has a short cycle nature to it. So the objective is to continue to do pilots and understand how we take it from pilot to full scale, and then how that affects development plans in the unconventional space going forward.

[John P. Herrlin, Société Générale]

So is this fracture or matrix porosity you're dealing with (54:04)?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Your matrix permeability is micro. It's not matrix. It's a function of the unconventional geology and whether you're in a sandstone or whether you're in a shale, so the behavior's different. That's all part of the learning that we'll talk about more as we're ready to disclose more of the details.

[John P. Herrlin, Société Générale]

Great.

[Joseph C. Elliott, Occidental Petroleum Corp.]

With regard to Aventine, Aventine is multiple companies at that site. So Aventine is set up to support Greater New Mexico, all the way from Turkey Track and then our Greater Sand Dunes area. And so it's pumping service, it's oil country tubular goods, it's sand transload, sand delivery. It's a new sand last mile logistics system called SANDSTORM. It's the OxyChem ACL facility, and that's just where we're starting. With Schlumberger, it's frac, it's drilling tools, it's cementing, and it's providing logistics improvements by the location.

In the Texas Delaware – so you treat each area based on what the current infrastructure is. In the Texas Delaware, it's really more about securing transload. And so we don't have the full scale buildout of an Aventine-like facility, but we have transload secured. It's closer to the regional sands in Texas. Our sand provider has a regional sand mine that will be opening shortly, and so we'll take advantage of that in the Texas Delaware. And in the Midland Basin, really, the infrastructure is pretty good; it's just really securing supply of sand.

To give you just a couple of stats on the New Mexico impact, you think about the proximity of that to the well sites. It's a 60% reduction in the number of miles driven. You go from almost 20 million miles to 8 million miles. And then, when you put in the new SANDSTORM system that we're starting up this year, we can haul 27 tons of sand per load versus 22 tons. You do that math, that drives another 1.3 million miles out of the equation.

So it's 33,000 fewer truckloads over a five-year period. It also reduces 9,000 metric tons of CO2. You think about accident statistics. It will improve our safety. And then, the new SANDSTORM system, that's really the last mile part of this, reduces the number of people required on-site, because of the automated nature of the way it works. So that SANDSTORM technology would apply both in New Mexico, Texas Delaware and Midland. And then, the logistics hub design and complexity varies as you move across those three areas as well.

[John P. Herrlin, Société Générale]

Great. Thank you.

[Operator]

Our next question comes from Pavel Molchanov from Raymond James. Please go ahead with your question.

[Pavel S. Molchanov, Raymond James & Associates, Inc.]

Thanks for taking the question. I know you don't generally give guidance by oil versus gas, but as we think about Permian Resources up 40-plus percent this year, is it going to be a broadly parallel increase between liquids and gas? So, in other words, the gas/oil ratio, is it going to remain broadly stable throughout the year?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Yeah. Pavel, this is Jody. In 2017, our oil cuts were kind of on the 60% – right around 60% and it actually increases a little bit to 61% for total of 2018. So your mix stays about the same.

[Pavel S. Molchanov, Raymond James & Associates, Inc.]

Okay. Helpful. And then, a quick one on Colombia. We've seen a lot of headlines, January in particular, about pipeline attacks affecting a number of the major fields in Colombia. To what extent is your Q1 international guidance affected by that?

[Kenneth Dillon, Occidental Petroleum Corp.]

I think the best way to answer is to look at our production last year. In Q1 2017 – since Q1 2017, our production's remained steady quarter-by-quarter. That's thanks to a lot of work in the field and excellent collaboration with our partner Ecopetrol and the full support of the Colombian government, and we're planning to continue with the same approaches in 2018.

[Pavel S. Molchanov, Raymond James & Associates, Inc.]

Okay. But I guess how many BOE a day have you lost year-to-date, for example, in Colombia, if you can share that?

[Kenneth Dillon, Occidental Petroleum Corp.]

I think it's basically a variation on the answer I gave a moment ago. Our production from our areas is basically steady at the moment. And it's mainly as a result of the work that we've done with the government and with Ecopetrol. We're not seeing major impacts on our fields at the moment.

[Pavel S. Molchanov, Raymond James & Associates, Inc.]

Okay. Fair enough. Appreciate it.

[Operator]

Our next question comes from Leo Mariani from NatAlliance Securities. Please go ahead with your question.

[Leo P. Mariani, NatAlliance Securities LLC]

Hey, guys. I was hoping you could talk a little bit about the way you're sort of splitting up capital in the Permian Resources division this year, really between just Midland and Delaware. I don't know if I had this right, but I think I was seeing maybe roughly one rig in the Midland and 10 in the Delaware. Is that something you're going to sustain this year, or is that going to move around? Can you just kind of talk about that broadly in terms of how you're thinking about Permian Resources capital over the next couple years with those two sub basins?

[Joseph C. Elliott, Occidental Petroleum Corp.]

Yeah, you can kind of look at it two different ways, you can look at wells online, you can look at rig count. If you look at wells online, it's about 55% in New Mexico, 30% in the Texas Delaware, and about 15% of the wells in Midland. And that probably stays fairly consistent throughout the next couple of years. From a rig – we're running 11 rigs operated, again, that's about 6 in New Mexico, 4 in Texas Delaware and a rig or 2 in Midland, so I don't see that changing drastically.

But again, we're continuing to develop inventory, learn new things. Turkey Track's a great example. We thought we had a single bench 2nd Bone Spring development there. Turns out we've got two. So as we learn more and we change how we think about our inventory, obviously, that could adjust. And I want to go back to Phil's question, he asked about OpEx and EOR. It's about $19 a barrel.

[Leo P. Mariani, NatAlliance Securities LLC]

All right. And then maybe could you talk a little bit about plans for Oman Block 30? I think you guys recently signed that late last year. Are you starting to see incremental capital there in the budget in 2018? When can we start to see some incremental production? Is it going to be largely oil targets? I think you guys had mentioned gas potential as well in Oman. So kind of what can you say about that as it develops over time?

[Kenneth Dillon, Occidental Petroleum Corp.]

Yeah, I think as you can see from the map on slide 24, Block 30 fits perfectly into the Oman North jigsaw. There's currently three discovery wells on the block and two reservoirs that we're completely familiar with due to the work in the other blocks. We have the same approach internationally as we have domestically. The goal is value, not just driving up production.

So the short-term plans are basically to reprocess the existing seismic on the block, come up with a development plan and start drilling probably towards the end of this year, and have some production next year. So relatively small amounts of capital invested this year, mainly study work and coming up with a value-based development plan.

[Leo P. Mariani, NatAlliance Securities LLC]

All right. That's really helpful. And last thing you mentioned, portfolio management, $0.5 billion to $2 billion. I guess it's kind of an ongoing thing for you guys. Do you see anything on the horizon here in 2018 where you might look to sell down any of your assets or is that just something that's out there and might take several years?

[Vicki A. Hollub, Occidental Petroleum Corp.]

Well, certainly for our core assets, we're satisfied with where we are. The only thing that we're continuing to do is look for things, assets that are way out in the inventory and the Permian. So things that we can't get to any time soon, and when I say soon that's like 10 to 15 years, or that's non-strategic for us, we would certainly consider to sell or monetize, anything that's non-core for us and, of course, we still have the Plains units that we can monetize.

[Leo P. Mariani, NatAlliance Securities LLC]

Thank you very much.

[Vicki A. Hollub, Occidental Petroleum Corp.]

All right. Thank you.

[Vicki A. Hollub, Occidental Petroleum Corp.]

So I want to thank you all for your questions, and I'd like to leave you with three takeaways from our call. First, we're ahead of schedule with our breakeven plan, but we're still focused on optimizing delivery across all of our businesses. And second, we're disciplined in our reinvestment and we'll provide additional security to our dividend through net debt reduction. Lastly, our expanded use of returns-based incentive metrics align our executive comp with shareholder priorities.

So we're looking forward to the rest of 2018. Thank you for joining our call, and have a good day.

[Operator]

Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending. You may now disconnect your lines.