Chevron Corporation (CVX) Q3 2012 Earnings Report, Transcript and Summary

Good morning. My name is Sean, and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.

All right. Thank you, Sean. Welcome to Chevron's Third Quarter Earnings Conference Call and Webcast. On the call with me today is Mike Wirth, Executive Vice President, Downstream & Chemicals; and Jeff Gustavson, General Manager, 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 shown on Slide 2. Slide 3 provides an overview of our financial performance. Financially, it was another solid quarter. The company's third quarter earnings were $5.3 billion or $2.69 per diluted share. Current quarter earnings are down about 30%, compared to both second quarter 2012 and to third quarter 2011. It is important to note that both comparative periods, second quarter this year and third quarter last year, are among the strongest quarters we've ever had. It is also important to note, as you will see in the remainder of the presentation, that a number of items negatively affect our third quarter comparisons, including swings in foreign exchange and timing effects in the downstream, as well as timing of asset sale gains and other transactions. Year-to-date, earnings are down about 13% versus 2011, which was a record earnings year. Return on capital employed for the trailing 12 months was 17.4%, and our debt ratio at the end of September was 8.5%. In the third quarter, we repurchased $1.25 billion of our shares. In the fourth quarter, we expect to repurchase the same amount. Turning to Slide 4. Cash generated from operations was almost $8 billion during the quarter, bringing our year-to-date operating cash flow to just over $26 billion, which is net of about $2 billion build in inventory. At quarter end, our cash balances were approximately $21 billion, and our net cash position was approximately $9 billion. We've had the right strategies and executed well against them. This has led to excellent financial performance, strong cash generation and total shareholder returns that lead the peer group. Jeff will now take us through the quarterly comparisons.

Thanks, Pat. Turning to Slide 5. I'll compare results of the third quarter 2012 with the second quarter 2012. As a reminder, our earnings release compares third quarter 2012 with the same quarter a year ago. Third quarter earnings were $5.3 billion, a decrease of approximately $2 billion from second quarter results. Overall, foreign exchange movements accounted for about 25% of this decline. We moved from a net positive foreign exchange position in second quarter of almost $200 million to a net negative position of nearly $300 million in the third quarter. Upstream earnings were down $481 million on unfavorable foreign exchange effects and lower production, partly offset by a gain on an asset sale. Downstream results decreased by approximately $1.2 billion between quarters, driven primarily by unfavorable inventory valuation effects, lower volumes and lower realized margins. The variance in the Other bar reflects higher corporate charges and an unfavorable swing in corporate tax items. On Slide 6. Our U.S. upstream earnings for the third quarter were $196 million lower than second quarter's results. Lower realizations reduced earnings by $140 million. Although key benchmark crude spot prices were roughly flat between quarters, Chevron's average U.S. crude oil realizations decreased 6% due to the monthly lag on pricing for most of our Gulf of Mexico volumes. This was partly offset by a 21% increase in natural gas realizations between periods. Lower production volumes, primarily due to disruptions from Hurricane Isaac in the Gulf of Mexico, decreased earnings by $85 million between periods. The Other bar reflects a number of items, including an increase in operating expenses related to higher maintenance and other production-related activities, as well as lower exploration expenses during the quarter. Turning to Slide 7. International upstream earnings were $285 million lower than the second quarter. An unfavorable swing in foreign currency effects decreased earnings by $470 million. The third quarter had foreign exchange losses of approximately $250 million, compared to gains of $220 million during the second quarter. As a reminder, these are primarily balance sheet translation effects. Lower liftings, primarily due to planned turnarounds in Kazakhstan and the U.K., decreased earnings by $235 million. The gain from the previously announced sale of an equity interest in the Wheatstone LNG Project increased earnings by about $600 million. The sale supports our strategies and growth plans for LNG in the region, expanding our existing partnership with Tokyo Electric, who have committed to total LNG offerings of 4.2 million tons per year from the Wheatstone Project. The Other bar reflects a number of unrelated items, including higher DD&A, as well as higher operating expenses, largely associated with turnaround activities. Slide 8 summarizes the quarterly change in Chevron's worldwide net oil equivalent production. Production decreased 108,000 barrels per day between quarters. We had previously indicated that the third quarter would include higher turnaround in maintenance activity, and it did. Planned turnaround activities, primarily in Kazakhstan and the U.K., decreased production by 78,000 barrels per day. The second generation plant, or SGP, turnaround at Tengizchevroil, or TCO, started the 1st of August and lasted approximately 6 weeks. This was the first-ever turnaround for this facility and was one of the largest turnarounds Chevron has ever executed. Annual maintenance at TCO Sour Gas Injection, or SGI, facility was conducted simultaneously with the SGP turnaround to maximize efficiency and limit production downtime. More than 6,500 employees and contractors were involved and more than 2.6 million man-hours were worked. Gas and crude were reintroduced into the units in mid-September and production was safely restored. TCO's facilities are currently producing at full capacity. While of a smaller impact, turnarounds in the North Sea at Captain, Britannia and Jade also hurt production this quarter. Production has been restored here as well. The next bar relates to weather. Weather impacts, primarily Hurricane Isaac in the Gulf of Mexico, decreased production by 23,000 barrels per day. The Base Business bar is largely related to the change in our normal field decline rate between periods, which was essentially flat between quarters. The last bar shows production from recent major capital project startups, which decreased by 5,000 barrels per day compared to the second quarter. We expect production in the fourth quarter to be higher than in the third quarter, as production is restored following the weather- and maintenance-related downtimes I just described. For the full year, we expect to come in somewhere around 97% of our original target. You will recall, our original target was 2.68 million barrels of oil-equivalent production per day. The shortfall is driven primarily by the precautionary shutdown of the Frade Field earlier in the year and delayed startup at Angola LNG. Next, let's move to downstream. Turning to Slide 9. U.S. downstream earnings decreased $346 million in the third quarter. Lower margins decreased earnings by $20 million, driven by significantly weaker marketing margins, which were only partly offset by stronger refining margins. West Coast marketing margins fell more than 40% during the third quarter, while product tightness in the West Coast and export demand in the Gulf Coast, lifted refining margins modestly. Overall, the August fire at our Richmond Refinery crude unit had little earnings impact for the quarter. The Richmond crude unit is expected to remain offline through the fourth quarter, with restart currently planned for the first quarter of next year. Other units in the refinery continue to operate, although at reduced rates. Lower volumes decreased earnings by $125 million, primarily related to our Richmond Refinery operating at a reduced rate, as well as the slowdown at the Pascagoula Refinery due to Hurricane Isaac. Timing effects represented a $180 million negative earnings variance between quarters, driven by the revaluation of inventory and mark-to-market effects on derivatives tied to underlying physical positions. The swing between quarters was primarily driven by rising crude and product prices during the third quarter, compared to sharply falling prices during the second quarter. The Other bar consists of several unrelated items. On Slide 10. International downstream earnings were $936 million lower this quarter. Lower realized margins contributed $125 million to the decline. Better crack spreads in Asia were more than offset by falling marketing margins and pricing lag effects for sales of naphtha and jet fuel in key markets. An unfavorable swing in timing effects, mostly attributable to inventory revaluation, decreased earnings by $340 million. Falling prices in the second quarter resulted in a $190 million gain, whereas rising prices in the third quarter resulted in a $150 million loss. The net earnings impact for the year related to timing is negligible as compared to year-to-date earnings of approximately $1.7 billion in the international downstream segment. Lower gains on asset transactions, as well as charges associated with portfolio restructuring in Australia, negatively affected the quarter-to-quarter comparison by $245 million and $100 million, respectively. The Other bar reflects a number of unrelated items, including lower shipping results and the impact of unfavorable foreign exchange effects. Slide 11 covers All Other. Third quarter net charges were $575 million, an increase of $284 million between periods. An unfavorable swing in corporate tax items resulted in a $134 million decrease to earnings. Corporate charges were $150 million higher in the third quarter. Year-to-date, corporate charges were $1.4 billion, which is higher than our quarterly guidance range of $300 million to $400 million. However, we currently expect fourth quarter corporate charges to be in line with this guidance. Mike is now going to provide an update on our downstream operations. Mike?

Thanks, Jeff. I know many of you on the line are in New York and have had a pretty tough week, so I hope your families are safe and that things get back to normal as soon as possible for you. Moving to Downstream & Chemicals. Overall, it's been another good year so far. We continue to deliver on the commitments we've made and our results back that up. Turning to Slide 13, I'll start with financial performance. Through 3 quarters, we've earned $3.4 billion. This translates to downstream unit earnings, adjusted to exclude special items, of $3.10 per barrel, which ranks a close second year-to-date, based on competitor earnings announcements earlier this week. Year-to-date adjusted return on capital employed for the full Downstream & Chemicals segment is 18.6%, which also ranks #2 among our peers. Our relative competitive performance on these 2 measures has steadily improved over 2010 and 2011 and continues to remain strong in 2012. We've got the right strategies and are keenly focused on execution. I'm confident we'll continue to further improve in the quarters to come. Moving to Slide 14, here's an update on portfolio actions and the milestones we've achieved this year. We've exited 8 countries in the Caribbean Islands. We've also completed several asset divestments, including our interest in the Alberta Envirofuels iso-octane plant in Canada; the fuels terminal and former refinery at Perth Amboy in New Jersey; fuels marketing in Spain and certain businesses of GS Caltex in Korea. And we've recently begun reviewing bids for our fuels businesses in Egypt and Pakistan. We continue to place emphasis on core markets. We've simplified our model. We've reduced costs, while returning scale where we have competitive positions, all designed to deliver stronger returns. Our focus is on value, not volume. Now let's move to Slide 15. Here's an update on our major capital projects, starting with Chevron Phillips Chemical. Already a leader in the production of normal alpha olefins, CPChem is constructing the world's largest on-purpose 1-hexene plant at Cedar Bayou, Texas, expected to start up in 2014. CPChem continues to make good progress in developing a new world-scale ethylene cracker at Cedar Bayou and new polyethylene units at Sweeny. Startup of these plants is expected in 2017, with attractive NGL supply underpinning this new capacity. And CPChem's Saudi joint venture, Saudi Polymers Company, began commercial production last month at their new olefins and derivatives facility in Al Jubail. With this startup, CPChem becomes the world's largest producer of high-density polyethylene. Moving to lubricants. Construction continues in our Pascagoula base oil plant, which remains on track for planned startup next year. This will leverage surplus hydrogen capacity and make Chevron the largest premium base oil supplier in the world. Our joint venture in Korea, GS Caltex, is building a gas oil cracker which, when completed early next year, will make Yeosu the largest processor of heavy oil in Korea. This will provide greater feedstock flexibility and additional production of high-value products. And our additive company, Oronite, is expanding its manufacturing plant in Singapore. Upon completion of this project, expected in 2014, Oronite will have effectively doubled the original size of what is already the largest additives plant in the region. You can see the focus of our investment here, primarily into the more attractive chemicals and lubricants segments. As these projects are brought online in the coming years, they are positioned to generate good returns and earnings growth. Moving to Slide 16, I'd like to close with a few observations on market dynamics this year. We continue to see a lot of volatility in both crude and product prices as represented here by the WTI Brent spread and the Gulf Coast unleaded gasoline price. This volatility not only impacts margins but also creates other effects related to inventory, derivative, mark-to-market values, et cetera, that move through our books, as Jeff discussed earlier. Interestingly, the peaks and valleys this year have largely coincided with quarter ends, which tends to magnify these effects, even though average pricing across the quarters would suggest much less movement. I realize that these are difficult to anticipate and model, which is why Jeff provided some insight into the direction and magnitude of these effects in the prior 2 quarters. I tend to look at our performance on a year-to-date basis or a rolling multiple quarter basis, where these movements tend to reverse or offset themselves. On Slide 17, I've got data over a 2-month stretch of time for the U.S. West Coast. The West Coast market -- West Coast gasoline market, in particular, is somewhat unique in that it's relatively isolated from the world market by geography, logistics and product specification. When the West Coast refineries are all operating normally, product supply is adequate to meet demand. In fact, given the demand declines of recent years, we even tend to see some capacity to export. However, when supplies move to the low end of their historical range, for whatever reason, the price typically moves up. This reflects the higher cost of resupply, due to both specification and logistical hurdles and the uncertainty on timing of resupply. This happened earlier this year and again last month when some capacity went offline due to power interruptions, at a time when inventories had already been declining. The move up in prices was sharp until the market recognized that the capacity would come back online and supplies would rebuild. I note this because California has embarked on a path of even greater isolation from world fuel markets with its greenhouse gas regulations. The industry is facing requirements to source blendstocks, like Brazilian ethanol, from relatively small and distant sources, or to blend in nonexistent stocks like cellulosic biofuels. The pressure on an already high-cost supply chain and potential for further refinery rationalization is only likely to further increase the price premium California consumers pay and also the likelihood of price spikes like we've seen this year. Chevron has 2 of the 3 largest refineries on the West Coast with good feedstock and product flexibility. We have the leading retail market share. We've been in California for more than 100 years. We understand these markets and are positioned to compete well through a rule period of change and uncertainty. That concludes my remarks and now I'd like to turn it back over to Pat.

All right. Thanks, Mike. Turning now to Slide 18, I'd like to focus on recent upstream developments and strategic progress. On the exploration front, we announced further drilling in the Greater Gorgon area with the Satyr-2 and Satyr-4 wells, our 15th and 16th discoveries in Australia since mid-2009. These new discoveries further highlight the quality of Chevron's exploration capabilities and the continued growth of our vast natural gas resources base -- resource base in the Carnarvon Basin. On a related note, I want to point out that the picture that you see on this slide, we have now successfully raised the roof on the second LNG tank at Gorgon. We also made new additions to our worldwide exploration portfolio, having been awarded participation in 2 deepwater blocks located offshore Sierra Leone. We have a significant presence in this region already and are pleased to have the opportunity to participate in the Republic of Sierra Leone's promising deepwater exploration effort. The Sanctions the Lianzi Project, located in the unitized offshore zone between Angola and the Republic of Congo, it is the first cross-border development in the region and builds on Chevron's strong position in West Africa. We acquired additional interest in the Clio and Acme fields through an exchange which was announced in August. This exchange is strategic and fits nicely with our long-term plans to grow our Australian resource base and create expansion opportunities for the Wheatstone Project. Also of note this quarter, we completed the previously announced sale of an equity interest in the Wheatstone Project to Tokyo Electric. And finally, as recently announced, we acquired an additional 246,000 net acres in the Permian Basin. This new acreage, plus our existing acreage, gives us a net leasehold position of about 1.5 million acres. I'd like to say a bit more about this acquisition and our overall positioning plans in the Permian. Turning to Slide 19. This slide shows our significant acreage position, both within and adjacent to the Permian Basin, shown in dark green on the chart. The map on the chart shows our existing lease positions in yellow, as well as the recently acquired acreage in light blue. The new acreage strategically complements our existing operation and provides us with additional growth potential in the Permian. The Permian extends from West Texas into the Southeast New Mexico and includes several component basins, including the Midland and Delaware Basins. Chevron is one of the largest hydrocarbon producers in the Permian, with approximately 114,000 barrels of oil-equivalent per day production during 2011. We have over 550,000 net acres in the Midland Basin. Our current focus areas include the Wolfcamp, Cline and Atoka shales, and we are on pace to drill, ourselves and with partners, over 300 wells in 2012. In the highly prospective Delaware Basin, where most of the recently acquired acreage resides, our near-term focus will be on the Bone Springs formation, as well as the Avalon and Wolfcamp shales. We are on pace to drill 12 operated wells during 2012, as well as 16 non-operated wells. The acquisition has also provided us access to additional people and resources to execute our base business and growth strategy in the area. While our production in the basin dates back to the 1920s, our existing and recently acquired acreage hold significant future potential as these are early-in-life, liquids-rich unconventional assets in a premier, emerging play. We plan to provide greater detail on our plans in these area at our Security Analyst Meeting this coming March in New York City. Turning now to Slide 20, I'd like to close my prepared remarks with a few key points. 2012 is all about execution, and we're doing well. We continue to progress our major capital projects, both upstream and downstream. We are over 50% complete on Gorgon. Our Wheatstone Project is also progressing well. I encourage you to follow our progress and to view some recent Gorgon and Wheatstone flyover videos and presentations, which are now available on our website. Our 2 key deepwater Gulf of Mexico major capital projects, Jack/St. Malo and Big Foot, continue to be on schedule. We remain confident we are on track to hit our longer-term target of 3.3 million barrels of oil-equivalent production per day by 2017. This volume growth, combined with industry-leading upstream margins, which were $23.88 per barrel year-to-date, is a large part of the Chevron value proposition for investors. Another strong and growing element of value for investors has been our distributions to shareholders. We're currently paying out about $12 billion annually through dividends and share repurchases, and we offer an attractive 3.2% yield. Now this concludes our prepared remarks, and we'd now like to take your questions. We do have a full queue, so please limit yourself to one question and a single follow-up if necessary. We'll do our best to see that we get your questions answered. Sean, please open the lines.

[Operator Instructions] Our first question comes from Evan Calio with Morgan Stanley.

My first question is for Pat. I mean, I know it may be premature, but I know last year, Chevron made a competitive dividend raise and with CapEx likely higher in '13, how do you think about drawing on the large net cash balance to continue to drive a superior and competitive dividend yield as you really bridge to the production growth and harvesting the capital investment that you're making now and in 2014 and beyond? And then I have a follow-up, please.

Okay, Evan, I think it's a good question, but frankly, I think you've sort of outlined our philosophy there just in asking the question. We do pay attention to and want to remain highly competitive on our dividend stream, and that's why you have seen us, over the last several years, grow the dividend rate at a -- very aggressively, 11% compounded per year. As we look forward, we want to continue that pattern. We obviously do see, once we get into the high-growth periods, when major capital projects come online, we do see significant cash generation coming forward there. We take that into account. We take a look at what our investment profile needs to be between now and then. And all of those factors get brought into the mix. Our view of medium-term commodity prices get brought into the mix. And it's based on all of those factors that we then go forward and have a discussion with our board about our dividend policy. I think it's very safe to say that our board takes our dividend responsibility very seriously and our desire to remain competitive and grow that stream of income for our investors is a high-priority item. In fact, it's the single highest priority of cash use.

That's helpful. And if I could have a follow-up to take advantage of Mike being on the call. Mike, I know you've talked about the positive trends in the base oil business in the past and you're increasing your premium base oil capacity at Pascagoula. This is generally a less transparent business, in general, maybe you could give us an overview of just that U.S. market, your returns expectations for this $1.4 billion expansion? And whether or not there's any additional base oil expansion potential in places like Salt Lake, where I know there's also a local high paraffinic crude source?

Yes, so it is a market that is a little less transparent, a little less well understood. In broad terms, the largest portion of the current base oil is a lower technology product called Group I, which is made through a relatively simpler process of solvent dewaxing. That is a lower-performing product. And ultimately, as we see specifications evolve to higher-performance standards and engines evolve to meet more stringent environmental regulations, you're seeing the OEMs migrate to a higher-quality lubricant, which is the Group II+ or premium base oils, which are made through a hydroprocessing technology which Chevron actually is 1 of the 2 primary licensors in the world for, and we have some distinct technology advantages there. So it's -- the Group II or the premium base oil market is a higher-margin market, and it is the rapidly growing market, as the Group I market declines in demand. So you've got absolute demand growth for lubricants. And within that, you've got Group I, which is the larger portion today, shrinking in size. And so you -- the premium market is growing quite rapidly with the higher margins. So that's the broad context for that. We've got a large facility at Richmond right now that manufactures premium base oils with Pascagoula, we'll move past Shell to be the largest in the world. And that product will go not only into the U.S. market, but Europe is a large market and has a very high specification standard. There's growth in Latin America. So Pascagoula will feed markets well beyond North America and actually allow us to rebalance some of the Richmond barrels into the growth markets in Asia. We do have reviews underway for additional investments in that sector. They likely would be in Asia, rather than in Salt Lake City, because of the proximity to the markets and some of our existing refining infrastructure that we have in Asia. While you might have an advantaged feedstock that you could use at Salt Lake City, the volumes there would be relatively small but logistics disadvantage to get it to the large growth markets would be nontrivial. And so I wouldn't expect to see something happen at Salt Lake City, but you certainly could expect to hear more in the future about potential projects in Asia.

Any comment on returns? And I'll leave it at that.

The returns would be well higher than what we typically get out of our refining projects. And we expect returns on these kinds of projects to be up in the 20%-ish range.

Our next question comes from Ed Westlake with Credit Suisse.

Just, I guess while we got Mike on the phone, some downstream questions. Just an update on Richmond?

Yes. So at Richmond, as Jeff mentioned, the crude unit remains offline today and will remain offline through the balance of the fourth quarter, with an expected startup in the first quarter of next year. We are working closely with outside investigators, as well as conducting our own investigation to determine the root cause of the incident and then to share the learnings of that, not only broadly within our own organization, but also across the industry, to try to prevent similar things from happening anywhere. The preliminary results of our investigation have identified a damage mechanism known as high temperature sulfidation corrosion, which led to a general thinning of the piping component that failed. We're waiting for definitive metallurgical testing to confirm that. But it is strongly suspected that, that is the technical mechanism. The questions as to why that corrosion had not been identified and addressed are really still the focus of our investigation. We're working closely with multiple agencies in the city, the county and the regional air quality district, to expedite the permitting process and effect the repairs to the crude unit. That work is well underway. Long lead items have been ordered, and some have already arrived. The work is underway to thoroughly inspect every component within the crude unit and complete the repairs with, as I said, an expected restart in the first quarter of next year.

Mike, and then just switching to chemicals. I mean, obviously, you've got the big ethane cracker. You've got the hexene-1 plant. Global demand for chemicals is still going to grow, but you know the Middle East is maybe a little bit short on low-cost gas. When you're thinking about participating in global growth, just maybe a philosophical question, is it -- are there opportunities for you to continue to deploy capital beyond that ethane cracker, or is it better to just sort of hold with what you have and focus on sort of free cash generation for the corporation?

Well, it's a good question. It's one that we spend time on with CPChem and certainly at the board there where our partner participates. We are, I think, pretty well aligned, but we would look for other attractive opportunities. CPChem's real strengths have been in the olefins and polyolefins chain. It's underpinned by attractive feedstock in the Middle East, as you mentioned, and also the position they have in the U.S., which is highly leveraged to NGL cracking as opposed to naphtha cracking. So the keys in that business are scale, cost efficiency and good feedstock pricing. I think the big opportunities continue to be in the Middle East and North America, although you can't ignore Asia, given the size of the market and the demand growth that you see over there. But some of the feed opportunities are not the same in Asia. So we are supportive of growth beyond the ethane cracker, if we can find a project that has the characteristics that have underpinned the success of CPChem's investments here in recent years. And we continue to look for those. And while they may not be easy in the Middle East or North America, for that matter, they're -- I don't think they're impossible. So we continue to look for further opportunities. But we wouldn't support projects that are not strong in their underlying fundamentals for the sake of growth.

Our next question comes from Doug Terreson of ISI.

I also have a couple of questions for Mike. First, I wanted to see if there was an update on the $1 billion return enhancement plan for 2012, meaning, what progress has been made on the operating expense and margin improvement categories? And also, you guys have been -- had continuous improvement over the last several years, I think as you mentioned a minute ago. Are new programs possible for '13? And then second, the plan to close the Sydney Refinery should reduce the losses at Caltex in refining, and while I realize that the Brisbane plant's advantage from a yield perspective, is it clear that it's advantaged enough given the scale of some of the new plants that are coming up in the region, or were there other strategic reasons to keep that plant open? So, 2 questions.

Okay. On the $1 billion improvement target that we had set for our refining system, I will tell you that we are well on our way to meeting that. In fact, that was measured against an '08 baseline and that was a multiyear program. And as we began this year, we were closing in on the billion. I can tell you that we are very, very close to that. And I fully anticipate that as we close this year, we will have more than met the commitment there. The extension of the improvement efforts that we've seen over the recent years, I would tell you, are really going to be in the area of continual improvement on margin, self-created margin improvements and continued focus on cost. The big things that we've done in the portfolio are largely behind us. I mentioned a number of those today, and we are closing out some pieces of that. The large restructuring of our organization is behind us. We're managing to hold that in terms of headcount and costs very steady and not see erosion of those benefits. And now I think the future improvements will come in the form of steady, regular expectations for continual improvement, on both the margin and the cost side within the business, as opposed to the big transformational effort that you saw over the last few years. And I think that we have every reason to believe that we can continue to grind out further improvements in that arena. The other thing that will drive financial performance will be some of the investments I talked about, which will add strong returns and good earnings growth. So we intend to continue to improve the financial performance of the business. On Australia, the Kurnell closure was announced, and you mentioned the plant at Litton, which is in Brisbane. The decisions on those assets are made by the board of Caltex Australia, which is 50% owned by Chevron and 50% publicly traded. And so, really, comments on the future of that particular asset are best addressed to them through their IR group. I think they've made some public statements about Brisbane. And the fact that it is of similar scale to Kurnell, and it faces similar to competitors, as you mentioned, regionally, is not something that I think is lost on the board or the management of that company. But they're really the ones that need to address the future of that.

Our next question comes from Arjun Murti with Goldman Sachs.

Just another CPChem question. When that joint venture was formed, I think it was originally with Phillips Petroleum over 10 years ago, I mean, the outlook for U.S. chemicals and chemicals itself was very different. It was more about cost cutting, rationalization, and you've been very successful with that. As the business shifts towards potentially being more of a growth mode, are you still comfortable with the 50-50 joint venture? And I know you've been very aligned with all the successor companies, ConocoPhillips and Phillips 66, but is that still the right structure for this asset? Are there other or better ways to optimize value? Is there a requirement for it to generate free cash flow, or would you be willing for this asset to take in cash if there were more attractive investment opportunities?

Well, you're a good student of the history there, Arjun. It really did start out in a pretty tough environment, particularly in North America. The first decade, or a large part of it, was characterized by cost reductions and essentially, a fix-it-or-exit approach to a number of the businesses that had been struggling to perform. And that's been a very successful strategy. The latter part of the last decade, we began to see some of these new projects, particularly in the Middle East, come on and those have been quite successful. And now we find a portfolio in North America that's well positioned relative to NGL feedstock. So it's been a very successful venture, I think, for both shareholders. And as you mentioned, we've stayed quite well aligned with our partners even as they've gone through some changes in ownership, from Phillips to ConocoPhillips and now Phillips 66. Both companies injected not only their assets, but really their human capability in the chemicals sector into that business. And I think we've been well served by that. I don't have any particular reason to believe that the structure we've got right now won't continue to be successful for us. We have -- CPChem has actually paid down their debt, and so we've not asked for cash to come back to the shareholders, but rather asked for them to pay down the debt. And they have substantial cash generation capability today, which will sell-fund all the projects that we see on the drawing board for them for the foreseeable future. And I think we would deal with -- if there were attractive opportunities to invest in that business that required us to bring cash into the entity, there's no reason why we wouldn't do that.

That's very helpful, Mike. And maybe just a related follow-up. You've obviously got a massive Marcellus position in Utica potentially as well. Do the economics of a cracker in that area make sense to you, or is it more logical for the gas to get shipped to the Gulf Coast and get processed there into a potential cracker?

Well, it's a really interesting question. And I think there are some different opinions out there on that, Arjun. The plus on the Marcellus and potentially the Utica is, obviously, the high volumes of gas liquids that we could see in that area. What is lacking is the infrastructure, so the frac plans, the logistics and the ability to support a cracker with the midstream assets that are so plentiful and well developed down in the Gulf Coast. And so I think it remains an open question as to whether or not enough of that midstream supporting infrastructure will really emerge, that would give you the reliable supply and the ability to operate a world-scale cracker on a highly competitive and reliable basis or not. Somebody's going to have to build out some of that infrastructure, and there's certainly some of that activity underway. But the Gulf Coast has clearly got that in abundance. And to the extent you can transport the gas liquids to Mont Belvieu and into that infrastructure, that is a real advantage. And so at this point, that's certainly where we've chosen to place our bet on the belief that, that infrastructure is mature and in place. And I think we'll just have to wait and see how the future unfolds for potential investments up in Pennsylvania, West Virginia, et cetera.

Our next question comes from Doug Leggate of Bank of America Merrill Lynch.

I have one for Pat and one for Mike, please. Pat, just quickly on the CapEx. It looks like we're running a little bit light versus the budget for the year. Can you just give us an update, do you expect things to be back-end loaded, or are we actually going to come in a little bit less than we thought?

Doug, if you look at our pattern over the last several years, first quarter, second quarter, third quarter and then fourth quarter, we typically are back-end loaded in terms of the expenditure profile. But if you look at 2012 and how that pattern has unfolded relative to the pattern in '11, the pattern in '10, the pattern in '09, et cetera, it's exactly per a typical approach for us. So, yes, I think the answer is, we will be back-end loaded, but it's nothing that is unanticipated or not expected.

Okay. Mike, this one is kind of a double-edged question, I guess. Richmond, obviously, has had its issues in the past and the commentary you made in the -- in your prepared remarks regarding California, we've seen a couple of your competitors talk about whether strategically California makes sense for them going forward given the amount of capital it could be required or cost basis and so on. I'm just curious as to whether you would ever consider either, exiting, I guess, is unlikely, but you doing something different with those assets, or to go completely in the other direction, if there were opportunities to maybe consolidate the West Coast and maybe reap some synergies that could offset some of those additional costs? I was just wondering strategically how you view your position on downstream on the West Coast, whether it's core or not? And I'll leave it at that.

Okay. Well, I'll start out with the fact that it is core. I mean, it has been the -- it's where our downstream business began. It's where -- as I said, we've been here for 110 years. It's one of the largest markets for fuels in the world. And we've weathered the good times and the difficult times here and we've seen the cycles. The second part of your question, would we consider some sort of a consolidation, I'll tell you, that's pretty difficult to do from the standpoint of market concentration. We've got -- as I said, we've got 2 of the 3 largest refiners on the West Coast today. And I'm not sure it's practical that we would be able to acquire another refining asset and get that through all the approval processes. So unless something changes externally, I'm not sure that's a realistic scenario. We do look at alternate configurations. We look at alternate modes of operations. We're pretty circumspect about capital investment into a market that has this overhang of regulatory uncertainty that exists today. But it has been a very good business for us. A couple of key attributes. Our refineries sit very high in the competitive stack on complexity and net cash margin. So they're not only large, but they are able to take in a variety of feedstocks. They make a good slate of high-value products and relative to our competition, they generate margins that sit at the very top. So they're big, and they're more profitable than the competition. El Segundo, in particular, also is well integrated into our upstream business. We run a lot of San Joaquin Valley heavy crude at El Segundo. And in fact, a number of projects in recent years have allowed us to bring more of that into El Segundo. And so there are benefits that not only accrue in the downstream but also accrue in the upstream. So it's a core position. It's a highly competitive position. We have weathered the cycles here and would believe that we can make a go of it here, if anybody can, because we know these markets and we've been through the cycles. The uncertainty that you refer to, and I know -- I've heard some of the others in the industry talk about it, California has a go-it-alone plan on greenhouse gas emissions. And it will further deteriorate what is already a weak economy, and it will make no meaningful impact on global greenhouse gas emissions. There'll be a negative impact on jobs, on consumers and by design and by intent, AB32 and the Low Carbon Fuel Standard, will raise fuel prices and further isolate this market from the rest of the world. So it runs the risk of disadvantaging California businesses by imposing higher costs that aren't borne by out-of-state competitors, and the policy is one that we have real questions about. So we're working with a variety of stakeholders to make sure that the additional costs and market risks are well understood and transparent, not only understood by the government and regulators, but also consumers and businesses. And we think they need to understand what we're headed into. And at the same time, we're working on our own plans for how to operate and compete in a world where those regulations come into effect and how we can continue to be the strongest competitor in that market. So it's not simple or straightforward, and there are some uncertainties. But we believe we can compete better than anybody in that environment.

Our next question comes from Faisel Khan of Citigroup.

I just had a couple, 2 upstream questions. On Kazakhstan and specifically TCO, can you just give us an idea of where we are in the cycle of the turnarounds, because I know this year was a significant turnaround, one of the largest, you said, in the history of the plant. And it looks like last year, there may have been some downtime, too. So I'm struggling to understand a little bit the cycle of these turnarounds and how large they can be, because it has a very large impact on production?

Right. I mean, this -- the turnaround that we had this time of SGI really was the first time that we have had a significant turnaround in over the 5-year period of time. But there can be intermittent, once-a-year KTL Train downtimes that are just a normal part of the maintenance program. This was a very significant turnaround. It's not expected to have this kind of an impact in successive years here until there's the next big turnaround, 5 years from now. But you can get individual KTL Trains that go down per year.

Okay, fair enough. And then can you give us an update on Angola LNG? I may have missed your prepared remarks on that, but just trying to figure out where we are with the gas to the plant and also with the LNG production?

Sure. I mean, we are still going through kind of the startup process for the plant. We have had some startup problems, and we're not anticipating at this point that there'll be any significant production from A LNG in 2012. It's not unusual to have startup problems as you're going through the commissioning efforts. Admittedly, we've had a little bit more problems this time than we would have typically expected. But we do look for A LNG production, first LNG to be with us in the first quarter of 2013.

Our next question comes from Paul Cheng with Barclays Capital.

Mike, 2 quick questions. On Slide 10, when you're looking at sequentially to the second quarter, say in international refining, the margin is down $125 million. Can you say how much -- I must be missing something, because all the benchmark indicator I track, whether it is in Singapore, Japan, they seems to have sequentially up from the second quarter and all your competitors seems to have that. So is there any particular market that you -- that have seen a down margin environment, or were there any particular product that's important to you that have seen that?

Yes, so let me -- it is a little counterintuitive, Paul. If you look at the Dubai 311 [ph] which is a pretty good proxy for Asian refining margins, the 111 is gasoline, diesel and fuel oil. It doesn't include naphtha or LPG, both of which have been hammered really hard in the marketplace. So the realized refining margin that you would expect out of 311 isn't actually a strong as -- what you get isn't a strong as what you would expect, because you get the naphtha and LPG. Couple of our refineries, our GS Caltex and our Singapore refinery, large, and they make a fair amount of both of those products. There's also some crude lags in a couple of those affiliates that can squeeze their margins that you wouldn't see in the 311. So there's a piece of it where the capture on that is not as strong as the indicator. The other thing that's not as transparent, I think, if you're looking at those indicators is, as we see in our actuals, are the marketing margins. And marketing margins are down in general in a rising market. In particular, our large position in Korea has been squeezed by the government and some government intervention in that market and more so than in other markets. And so we've definitely seen some under-realization of what we would like to see in marketing margins in Korea. And then we have lagged pricing on a number of our products in marketing. So jet and naphtha both get sold on a prior month basis. And in a rising market, those prices were weak anyway, and now you're selling at a prior month, so you're selling even at a lower value relative to current in a rising market. So there's a number of components like that, that are not apparent in a headline refining crack indicator, all of which in this market that we've seen in the third quarter, were going in the opposite direction of the stronger refining margin.

Okay. The second question is that on the -- I think a lot of people that has been looking at using railroad, that maybe as a relatively near term and effective way to ship the discount crude to the refining operation. Can you maybe help us to understand if there's any active or major initiative that you guys are contemplating or just currently thinking to ship those discount crude to your, say, 3 coastal refinery or that the opportunities are just not really there for California at all?

Well, it is certainly something that we look at. We've run Bakken crude on the West Coast already. We've run Eagle Ford at Pascagoula, not in large volumes, but we do understand the logistics to get those discounted crudes into our big coastal refineries. As you say, this crude disconnect, it's like real estate. It's location, location, location. And our large coastal refineries are distant from where these advantages really are. And you can get Bakken crude up into the Pacific Northwest via rail. You then have the challenge of how do you get it down to the West Coast. You can do that with barge, you can do it with further rail. And so you've got transhipment costs, and then you've got to have the offloading capability in your refineries. And our refineries really weren't set up for large rail-based receipts of crudes. So the logistics are tough into the coastal refineries. They are very good into a couple of our smaller refineries. So our refinery in British Columbia and our refinery in Salt Lake City have pipeline connections to discounted crudes, and they've been able to take full advantage of that. So we have seen some of our assets that have benefited. The other thing I would just remind you on the big coastal refineries, Paul, is they have other advantages that they've historically had, which they continue to capture relative to our lightering on the West Coast and some advantages we have there. Pascagoula runs some discounted Latin American grades and has a lot of flexibility to bring those in. And so you're constantly optimizing the crude slate on your landed cost of crude via rail or versus these other modalities. And so that's a part of the normal business. And we're certainly doing everything we can to take advantage of the discounted crudes in those refineries. But the opportunities get chewed up a lot in the transportation.

Pat, can I sneak in a quick one for you?

Well, we've got some more folks on the line, Paul. Let's move on, if you don't mind, and we can obviously take them offline. Thanks very much. And actually, before we get to the next call, I just want to make a point out. I misspoke before on the turnarounds, got my acronyms mixed up here. So the SGP is the unit that goes down once every 4 years or so. SGI and the KTLs are down typically once a year. So I just wanted to make that clarification.

Our next question comes from Jason Gammel with Macquarie.

At the risk of exasperating Mike on the California issues, Mike, have you done any -- or do you have any estimates on what the potential incremental cost is going to be from complying with the greenhouse emissions? And, I guess, I'm thinking both in terms of any environmental CapEx that you have to put into the business and any uplift in the operating expense, although recognizing you might be able to pass that on to the consumer. And then I guess really what I'm leading to, do you get to a situation where you may be better off sourcing CARBOB outside of California and then just shipping it to your refineries?

Well, there's a wide range of potential incremental costs, Jason. And the reality is, our refineries are amongst the most energy-efficient refineries in the world. And our stationary source emissions are very, very low. The opportunity to spend further capital to mitigate stack emissions of CO2 are -- they're just about tapped out. And so your choices are go into the market to buy credits, and that could be something that we'll see where the market price goes on that. But we really don't have a lot of opportunity, other than cutting runs and restricting supply. And there are some who believe that is the ultimate way that we'll see people comply, is just reducing their coupons, which tightens up the market, which runs the price risk. When you get -- if you get fuels under the cap and trade, which is anticipated out towards the middle of this decade, the costs explode. And that's where you go from costs in the hundreds of millions of dollars a year to costs in the billions of dollars a year. And frankly, all of this stuff has got to go through to the market. We cannot absorb it, and I don't intend to absorb it. And so the expectation is that as we see hundreds of millions or billions of dollars of increased costs, that translates through into the price of the product and that was the basis for my comment earlier that California's consumers will continue to pay a higher premium than the rest of the country. And that is the policy path that we are on. The issue of CARBOB imports is one that we're very sensitive to because if those imports are not subject to some of the same obligations that manufacturers are, then you've got a competitive disadvantage. And that's a subject of discussion with the regulators. And if in fact it were more economic to import than to manufacture, and that's very well what we could do, that's got real implications for jobs and investment. So it's still an evolving and uncertain environment and frankly, we're trying to help people understand that the implications of these things, if it stays on the track that it's on right now, the implications are all bad.

As a former California resident, you've got my sympathies.

Okay. I think we're running over our time here, so perhaps one more question and then we'll have to close it off.

Our next question comes from Iain Reid with Jefferies.

Mike, I'll ask you more of a macro question. I heard one of your competitors say yesterday they thought we are close to the bottom of a chemical cycle. I'm not sure whether they're talking about the naphtha base or ethane base, but can you maybe make a comment that? And then also from your perspective, where you think the downstream product market is in terms of demand, growth or decline in your areas of focus, Asia and the U.S.?

Yes, I don't know exactly what you heard yesterday. What I would tell you is that the chemicals business has been good for those that have gas liquids based feeds. And so -- and that's mostly what CPChem has. Naphtha-based crackers have been in a pretty tough environment. They are the marginal producer, and with high crude oil prices, naphtha-based cracking margins have not been very attractive at all. And so we do continue to see growth in demand for the derivatives in the polyolefin chain. So if there is a belief we're at the bottom of the cycle because you see market demand growth and perhaps some improvement in naphtha-based cracking margins, that comes on top of what are already pretty good ethane-based cracking margins. And so it very well could be the portfolio differences between what we see in our portfolio and what somebody else may see in theirs, would account for a different view of the cycle. The second question on the broader fuels trends and demand. I am a pessimist, to be honest with you. Europe continues to be a real problem. The recovery in the U.S. is not as, in my view and the things we see through the people we sell to, not as robust as you might believe if you read the headlines. And I'd give you a couple of other specific data points more globally. If I look at our sales of marine lubricants, they have steadily declined for the last several months. If I look at our sales of base oil, they have steadily declined for the last several months. Our sales of lubricants in Asia have steadily declined for the last several months. Our sales of additives in Asia have steadily declined for the last several months. And so we watch these trends pretty carefully because those are sales into industrial sectors and marine transport is a leading indicator of global economic activity. And you can see destocking and sometimes, there's a fake out, where you just see inventories being pulled down, and there really isn't an underlying demand trend. But what we've seen has gone on for enough months that it causes concerns in my mind about the direction of the global economy. I think China has definitely been slower than people anticipated. And you don't have the strength in the other regions in the world as well. So I continue to believe that refining margins, although this year we've seen a little bit of strength, primarily in the distillate part of the barrel, I do not believe the fundamentals for stronger refining margins exist out there. We see more capacity coming online, particularly in China, and I think there are real risks on the demand side of the equation. So we are not building our plans or banking on maintenance of refining margins that we've seen this year and certainly not on improvements. I think we have to be prepared for a tough refining margin market out there for the near to medium term.

All right. Let me close off here. Let me say that we really do appreciate everyone's participation in the call today and your interest in Chevron. I especially want to thank the analysts on behalf of all the participants for their questions during the session. So with that, I'll close it off and with -- and turn it back to you, Sean.

Thank you. Ladies and gentlemen, this concludes Chevron's Third Quarter 2012 Earnings Conference Call. You may now disconnect.