Chevron Corp (CVX) — Q2 2015 Earnings Call Transcript

All right. Thank you, Jonathan. Welcome to Chevron's second quarter earnings conference call and webcast. On the call with me today are Jay Johnson, Executive Vice President-Upstream; and Frank Mount, General Manager of Investor Relations. We'll refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. We ask that you review the cautionary statement on slide two. Slide three provides an overview of our financial performance. The company's second quarter earnings were $571 million, or $0.30 per diluted share. Included in the quarter were impairments of $1.96 billion and other charges of approximately $670 million relating to project suspensions and adverse tax effects, all of which were non-cash charges stemming from a downward revision in the company's longer-term crude oil price outlook. Excluding these special items, as well as asset-sale gains and foreign-exchange effects, earnings were $1.8 billion, or $0.97 per diluted share, approximately $400 million higher than the first quarter on that same basis. A detailed reconciliation of the special items is included in the appendix to this presentation. Cash from operations was $7.2 billion, an improvement of $4.9 billion from the prior quarter. Our debt ratio at quarter end was 17%. During the second quarter, we paid $2 billion in dividends. Earlier in the week, we announced a dividend of $1.07 per share payable to shareholders of record as of August 19. We're currently yielding 4.6%. Turning to slide four, cash generated from operations was $7.2 billion during the second quarter and $9.5 billion year-to-date. Upstream cash generation was stronger than in the first quarter, the result of higher crude prices. We also benefited from strong cash generation from our downstream and chemicals business. Temporary working capital effects reduced year-to-date cash flow by approximately $2 billion. We expect this impact to reverse in future quarters. Proceeds from asset sales for the quarter totaled approximately $3.9 billion, the vast majority of which related to our sale in the interest in Caltex, Australia. We are well ahead of pace on our four-year asset divestment program. In the past 18 months, we have recognized asset sale proceeds of nearly $11 billion, compared to our stated $15 billion goal over the 2014 to 2017 timeframe. Cash capital expenditures were $7.6 million for the quarter, essentially flat with the first quarter. Year-to-date cash capital expenditures were $15.2 billion, down $2.2 billion or 13% compared with the same period in 2014. At quarter end, our cash and cash equivalents were approximately $12.2 billion, and our net debt position was $19.4 billion. Slide five compares current quarter earnings with the same period last year. Second quarter 2015 earnings were $5.1 billion lower than second quarter 2014 results. Upstream earnings decreased to $7.5 billion between quarters. The impairments and other charges I noted previously accounted for $2.6 billion of this decline. Significantly lower crude realizations and the absence of second quarter 2014 asset sale gains make up the remaining variance between periods. Downstream results increased by $2.2 billion, primarily driven by higher worldwide margins and gains from asset sales, principally the sale of our interest in Caltex Australia. Operationally, the second quarter continued a positive quarterly pattern of high reliability, strong margins, and good cost management. The variance in the other segment was primarily favorable corporate tax items. Turning now to slide six, I'll compare results for the second quarter 2015 with the first quarter of 2015. Second quarter earnings were $2 billion lower than first quarter results. Upstream earnings decreased by $3.8 billion, primarily reflecting the charges I previously discussed. Unfavorable foreign exchange effects and the absence of first quarter asset sale gains and the positive UK tax adjustment were also large variances between periods. Downstream earnings increased $1.5 billion as gains on asset sales were partially offset by an unfavorable foreign exchange swing between the quarters. Operationally, the quarters were fairly comparable. The variance in the other segment was primarily favorable corporate tax items, partially offset by higher corporate charges, including severance accruals. Frank will now take us through the comparisons by segment.

Thanks, Pat. Turning to slide seven, our U.S. upstream earnings for the second quarter were $578 million lower than the first quarter's results. Asset impairments and project suspensions across multiple assets, primarily as Pat indicated, from a reduced price outlook, decreased earnings by $630 million. Higher realizations, consistent with an increase in domestic crude prices, increased earnings by $190 million. Exploration expenses, mainly associated with the deepwater Gulf of Mexico, decreased earnings by $70 million. The other bar reflects higher production, which was more than offset by higher DD&A rates. Turning to slide eight, international upstream earnings were $3.2 billion lower than last quarter's results. Asset impairments, primarily at Papa Terra in Brazil, project suspensions and adverse tax effects from price changes previously discussed reduced earnings by about $1.9 billion. An unfavorable swing in foreign currency effects decreased earnings between periods by approximately $670 million. The absence of last quarter's gains on asset sales and the deferred tax benefit from the UK tax change decreased earnings by $660 million. Increased exploration expenses resulted in lower earnings of $170 million. Higher realizations increased earnings by $395 million, consistent with the increase in Brent prices between the quarters. The other bar primarily consists of an unfavorable ruling on a decade-old tax issue and severance accruals booked in the second quarter. Slide nine summarizes the change in Chevron's worldwide net oil equivalent production between the second quarter of 2015 and the first quarter of 2015. Net production decreased by 85,000 barrels per day between quarters. Major capital project ramp ups, primarily at Jack/St. Malo in the Gulf of Mexico and from the expansion of the Bibiyana field in Bangladesh increased production by 22,000 barrels per day. Growth from our shale and tight assets, primarily in the Permian, contributed 11,000 barrels per day. As we foreshadowed in our first quarter earnings call, production in the Partitioned Zone was shut down at the end of May based on the inability to secure work and equipment permits. The shutdown decreased production in the second quarter by 38,000 barrels per day. We're still not producing in the Partitioned Zone, and we have no updated guidance as to when production is likely to restart. Planned and unplanned downtime reduced production by 34,000 barrels per day between periods, primarily in Canada and in Australia. Price and cost recovery effects decreased production by 23,000 barrels per day between quarters as high crude prices and reduced spending decreased volumes associated with production share and variable royalty contracts. The remaining variance in the base business and other bar primarily reflects natural field declines and weather-related production limitations at Tengiz. Slide 10 compares the change in Chevron's worldwide net oil equivalent production between the second quarter of 2015 and the second quarter of 2014. Net production increased by 51,000 barrels per day between quarters. Major capital projects increased production by 71,000 barrels per day due to production ramp-ups, primarily in the deepwater Gulf of Mexico and Bangladesh. Shale and tight production increased by 46,000 barrels per day due to the growth in the Midland and Delaware Basins in the Permian, the Marcellus and the Vaca Muerta shale in Argentina. Price and cost recovery effects increased production by 61,000 barrels per day due to the roughly 45% drop in crude prices between periods. The shutting of operations in the Partitioned Zone decreased production by 45,000 barrels per day. Asset sales resulted in lost production of 33,000 barrels per day, principally driven by the divestment of our assets in Chad and the Netherlands. The decrease of 49,000 barrels per day in the base business and other bar primarily reflects normal field declines and the impact of higher external constraints, partially offset by a favorable variance from less planned turnaround activity. Our base business continues to perform well with a managed decline rate within our existing guidance range. Year-to-date net oil equivalent production was 2.638 million barrels per day and within our 0% to 3% guidance for 2015 growth. Looking forward to the remainder of the year, the third quarter is expected to be a comparatively heavy turnaround period, and we believe the full year production guidance remains appropriate.

Thanks, Frank. Turning to slide 13, I'm going to discuss our Upstream business, where we continue to make good progress in delivering the projects that are driving our growth in volume, in value and in cash. Gorgon is a critical part of that growth, and we continue to work towards the first LNG cargo. As you can see from the photo, plant construction has advanced. We're nearing mechanical completion of the first train with over 60% of critical subsystems handed over to commissioning. We've posted new pictures today and I encourage you to look at them on our investor website and chevron.com. Turning to slide 14, the upstream work scope for initial production from the Jansz field is largely complete with the control systems now active. We've established communications from the central control room on Barrow Island to the subsea wells, which enables us to conduct commissioning activity on the upstream and pipeline systems. Final testing is underway for the subsea infrastructure and controls. At the plant, all LNG and condensate tanks required for first LNG are ready and commissioning of completed process systems is underway. Currently the critical path is through the refrigerant compressors and the hydrate prevention system for the subsea wells. We expect to perform the first commissioning run of the compressors and testing of the hydrate prevention system in late September. Once we're satisfied with the operation of these systems, we'll be ready to introduce gas from the Jansz wells into the upstream pipeline and begin the startup of Train 1, which we currently expect late this year. The schedule is dependent on managing commissioning and startup risks, including equipment malfunctions, possible labor and weather disruptions, as well as other unforeseen issues. Our focus is on a safe and incident-free startup that leads to reliable long-term operations. We're working to achieve the first LNG cargo by year-end. However, given these risks, it's likely to occur in early 2016. Now let's talk about Wheatstone, moving to slide 15. Wheatstone is now over 65% complete. On the upstream side of the project, we successfully completed the float-over and installation of the offshore platform in April. Hook up and commissioning is on plan with all subsea structures now installed. The flow line installation is underway and the development drilling program ongoing. All nine wells were previously drilled to the top of the reservoir, and we're now drilling the reservoir sections of each well and running the completions. At the plant site, 11 of 24 major process modules for Train 1 have been delivered. All refrigeration compressors and gas turbine generators have been installed and the domestic gas pipeline has been completed. The focus of activity at the plant has shifted from civil works to mechanical, electrical and instrumentation systems. The work on site is going very well. Our biggest challenge has been the delays in module delivery from a fabrication yard, which is putting pressure on the schedule. To address the delays, we've expanded to an additional yard and provided increased oversight in the yards. We've seen positive results from these actions and are not anticipating any further delays in the module delivery schedule. Additionally, we've increased bed capacity at the plant site and are updating our work plans to mitigate the impact to schedule. Our objective remains first LNG by year-end 2016, and we'll continue to provide updates on our progress over the next 18 months. Turning to slide 16. Performance at the Jack/St. Malo lower tertiary development continues to exceed our plan. The sixth well was brought online ahead of schedule and total production has ramped up to around 80,000 barrels per day. The development drilling program continues and we're seeing some improvements in cycle time, costs, and stimulation effectiveness with the most recent completion 20% better on cost and schedule than previous wells. Work to install the Big Foot Tension Leg Platform was suspended in early June when nine of the 16 tendons lost buoyancy. There were no environmental impacts or injuries, and we are investigating the root cause of the incident. We have secured the site, including the successful recovery of the seven remaining tendons. The tension leg platform was undamaged and is being moved to a safe harbor location. Site surveys and equipment inspections are in progress to determine whether the installed piles and recovered tendons can be reused and what equipment will require replacement in order to complete the project. At this point, we are not expecting any Big Foot production in 2016 or 2017, which is a reduction from our original plan of 10,000 net barrels per day in 2016 and 22,000 net barrels per day in 2017. As we complete the investigation and update our plan, we will advise you accordingly. Appraisal drilling is ongoing at the Anchor discovery and in the Northwest Keathley Canyon area, now named Tigris. Tigris has the potential to offer a multi-field, hub development of the Guadalupe, Gila and Tiber discoveries with the potential addition of the Gibson exploration prospect, which we plan to drill around the end of this year. Appraisal drilling is underway at Guadalupe and recent results from deepening the Gila discovery well are encouraging with further appraisal planned. We continue to progress our opportunity queue in the deepwater and in the second quarter made another lower tertiary discovery at the Sicily prospect in Keathley Canyon Block 814. We're encouraged by the results of the discovery well and follow-up appraisal work is planned.

All right. Turning to slide 19, I'd like to now provide an update on the self-help efforts that we have underway to lower our costs and improve our efficiency. To date, we've identified more than $3 billion of spend reductions with about half coming through organizational reviews and half working through the supply chain. On the organizational side, efficiency reviews have recently concluded that covered our corporate gas and midstream and service company group. Similar reviews are occurring on a rolling basis within our upstream business units. Work activities in these identified groups have been prioritized, streamlined, and right-sized to the current environment. Savings totaled approximately $1.4 billion on a full run rate basis and represent both dollar and workforce reductions off the relevant base of about 20%. These benefits to our cost structure should become increasingly evident as we move through the next several quarters. In future periods, we expect to see additional savings identified as our remaining upstream units complete their reviews. We're also aggressively pursuing savings through the supply chain, particularly in the U.S., where our supplier responsiveness has been high. We have negotiated in excess of $1 billion in immediate savings, achieving product category reductions of typically 15% to 30%. We are also changing the way we work through greater standardization, project re-scoping, refinement of fit-for-purpose designs, and timing optimizations. In combination, we estimate negotiated savings and work changes will lower our future supply chain spend by $1.6 billion. These savings will appear in multiple ways as we move through 2015 into 2016. Impacts will come in the form of lower operating expenses, lower capital, and lower cost of goods sold. And we're not done. We expect more supply chain savings to be identified in future months, particularly as activity continues to flow and as additional spare capacity emerges. We are being aggressive in pursuing these self-help measures in response to a very challenging industry environment.

Thanks, Pat. We made a commitment to our investors in March. We said we would cover the dividend from free cash flow in 2017. We stand by that commitment. We are taking the steps necessary to ensure we are a resilient competitor regardless of the ensuing price environment. Our focus areas are shown on the slide, get our capital projects currently under construction online, rebase and reprioritize our capital outflows, maintain reliability and drive our cost structure lower, and conclude our planned divestment program. If a lower price environment persists for longer, you'll see even more significant cost savings and even greater cuts in capital. As we showed you in March, we have tremendous flexibility in our 2017 C&E spend. We are confident that we can and are committed to scaling our C&E outflows in a manner that will allow us to continue our 27-year record of annual dividend payment increases.

Thank you for your time and attention here this morning. I'll turn it back to you, Jonathan.