Good morning. My name is Sean. I will be your conference facilitator today. Welcome to Chevron's third quarter 2012 earnings conference call. At this time, all participants are in listen-only mode. After the speaker's remarks, there will be a question-and-answer session, and instructions will be given at that time. If anyone should require assistance during the conference, please press star and then zero on your touch-tone telephone. 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. Patricia 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 and 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 statements shown on slide two. Slide three 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 Q2 2012 and to Q3 2011. It is important to note that both comparative periods, Q2 this year and Q3 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 four, 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 a $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 five, I'll compare results of the third quarter 2012 with the second quarter 2012. As a reminder, our earnings release compares Q3 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 Q2 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 six, 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 seven, 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 off-take 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 eight 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 and 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 first of August and lasted approximately six 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's 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. Let's move to downstream. Turning to slide nine. 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 a 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-$400 million.
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 N.Y. 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 and 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 three 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 and Chemical segment is 18.6%, which also ranks number 2 among our peers.
Our relative competitive performance on these two 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 eight countries in the Caribbean Islands. We've also completed several asset divestments, including our interest in the Alberta EnviroFuels isooctane plant in Canada, the fuels terminal and former refinery at Perth Amboy, New Jersey, fuels marketing in Spain, and certain businesses of GS Caltex in Korea. 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. 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. 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 on 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 gasoil 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. 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 lubricant 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 two 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 two-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.
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 blend stocks, like Brazilian ethanol, from relatively small and distant sources, or to blend in non-existent 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 two of the three 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 period of change and uncertainty. That concludes my remarks. 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 well, 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 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 two 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 efforts. We sanctioned the Lianzi project, located in a 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 Cleo 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. 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 position and 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 operations 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 holds 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 this 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 two key deepwater Gulf of Mexico major capital projects, Jack/St. Malo and Bigfoot, 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.
Thank you. Ladies and gentlemen, if you have a question at this time, please press star then one on your touch tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. If you are listening on a speakerphone, we ask that you please lift your handset before asking your question to provide optimum sound quality. Again, if you have a question, please press star one on your touch tone telephone. Our first question comes from Evan Kelly with Morgan Stanley. Please go ahead with your question.
Hey, morning, everybody. Thanks as always for the additional information. It is helpful. Maybe first question is for Pat. I know it may be premature, but I know last year, Chevron made a competitive dividend raise. With CapEx likely higher in 2013, 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? If you can 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 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 the 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. 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 responsibilities 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. 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 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 at places like Salt Lake, where I know there's also a local high paraffinic crude source. Thanks.
Yeah. 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 plus or premium base oils, which are made through a hydroprocessing technology, which Chevron actually is one of the two primary licensors in the world for. We have some distinct technology advantages there.
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. You've got absolute demand growth for lubricants, and within that, you've got Group I, which is a larger portion today shrinking in size. The premium market is growing quite rapidly with the higher margins. 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. 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. 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.
The logistics disadvantage to get it to the large growth markets would be non-trivial. 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? I'll leave it at that. Thanks.
The returns would be well higher than what we typically get out of our refining projects. We expect returns on these kinds of projects to be up in the 20% range.
Wonderful. Thank you guys.
Thanks, Evan.
Our next question comes from Edward Westlake with Credit Suisse. Please go ahead with your question.
Yeah, thanks, everyone. Just I guess while we got Mike on the phone, some downstream questions. Just an update on Richmond?
Yeah. 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're 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 affect 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.
Okay. Thanks for that, Mike. Just switching to chemicals. Obviously, you've got the big ethane cracker, you've got the 1-hexene plant. Global demand for chemicals is still going to grow. 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, 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 that 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 levered to NGL cracking as opposed to naphtha cracking. 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. Some of the feed opportunities are not the same in Asia.
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. We continue to look for those. While they may not be easy in the Middle East or in North America for that matter, I don't think they're impossible. We continue to look for further opportunities. We wouldn't support projects that are not strong in their underlying fundamentals for the sake of growth.
Thanks. Then also just thanks before I sign off to Melody and Roy for everyone for the great trip to Gorgon. Thank you.
Thanks. Thought you'd appreciate seeing the second tank with the roof on it now.
No photos of us around the bottom of it.
We've got those.
Our next question comes from Doug Terreson of ISI. Please go ahead with your question.
Good morning, everybody.
Morning.
Morning, Doug.
I also have a couple of questions for Mike. First, I wanted to see if there was an update on the billion-dollar return enhancement plan for 2012. Meaning what progress has been made on the operating expense and margin improvement categories? Also, you guys have had continuous improvement over the last several years, I think, as you mentioned a minute ago. Are new programs possible for 2013? Then second, the plan to close the Sydney refinery should reduce the losses at Caltex in refining. While I realize that the Brisbane plant's advantaged 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? Are there other strategic reasons to keep that plant open? Two 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 a 2008 baseline, and that was a multi-year program. As we began this year, we were closing in on the billion. I can tell you that we are very close to that, and I fully anticipate that as we close this year out, 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 self-created margin improvements and continued focus on cost.
Okay. The big things that we've done in the portfolio are largely behind us. I mentioned a number of those today, and we're 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 cost very steady and not seeing erosion of those benefits. 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. I think 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.
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 Lytton, 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. 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. They're really the ones that need to address the future of that asset.
Okay. Good answers. Thanks.
Our next question comes from Arjun Murti with Goldman Sachs. Please go ahead with your question.
Thank you. Just another CP Chem 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 at that. As the business shifts towards potentially being more of a growth mode, are you still comfortable with the 50/50 joint venture? 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? Thank you.
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. 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. Now we find a portfolio in North America that's well positioned relative to NGL feedstock. It's been a very successful venture, I think, for both shareholders.
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 chemical sector into that business. 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. CPChem has actually paid down their debt, so we've not asked for cash to come back to the shareholders, but rather asked for them to pay down the debt. They have substantial cash generation capability today, which will self-fund all the projects that we see on the drawing board for them for the foreseeable future.
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. Maybe just a related follow-up. You've obviously got a massive Marcellus position and the 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, 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. The frack plants, 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. 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, there's certainly some of that activity underway.
The Gulf Coast has clearly got that in abundance. To the extent you can transport the gas liquids to Mont Belvieu and into that infrastructure, that is a real advantage. At this point, that's certainly where we've chosen to place our bet on the belief that infrastructure's mature and in place. I think we'll just have to wait and see how the future unfolds for potential investments up in Pennsylvania, West Virginia, et cetera.
That's great. Thank you so much.
Our next question comes from Douglas Leggate of Bank of America Merrill Lynch. Please go ahead with your question.
Thanks. Good morning, everybody.
Hi, Doug.
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. If you look at 2012 and how that pattern has unfolded relative to the pattern in 2011, the pattern in 2010, the pattern in 2009, et cetera, it's exactly per a typical approach for us. Yeah, I think the answer is we will be back-end loaded, it's nothing that is unanticipated or not expected.
Okay, thanks for that. Mike, this one's kind of a double-edged question, I guess. Richmond obviously has had its issues in the past. The commentary you made 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're doing something different with those assets. To go completely 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'm 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. Thanks.
Okay. Well, I'll start out with the fact that it is core. It's where our downstream business began. As I said, we've been here for 110 years. It's one of the largest markets for fuels in the world. 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 a standpoint of market concentration. As I said, we've got two of the three largest refineries 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. 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 operation.
We're pretty circumspect about capital investments into a market that has this overhang of regulatory uncertainty that exists today. 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. 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. They're big, and they're more profitable than 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.
There are benefits that not only accrue in the downstream but also accrue in the upstream. 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. You know 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 will be a negative impact on jobs, on consumers, and by design and by intent, AB 32 and the Low Carbon Fuel Standard will raise fuel prices and further isolate this market from the rest of the world. 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. 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. We think they need to understand what we're headed into.
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. It's not simple or straightforward, and there are some uncertainties. We believe we can compete better than anybody in that environment.
I appreciate the full answer. Thanks, Mike.
Our next question comes from Faisel Khan of Citigroup. Please go ahead with your question.
Thank you. Good morning. I just had a couple, two 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. It looks like last year there may have been some downtime too. 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. The turnaround that we had this time of SGP really was the first time that we have had a significant turnaround over the five-year period of time. 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 five years from now. You can get individual KTL trains that go down per year.
Okay, fair enough. 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. We are still going through the startup process for the plant. We have had some startup problems. We're not anticipating at this point that there'll be any significant production from ALNG in 2012. It's not unusual to have startup problems as you're going through the commissioning effort. Admittedly, we've had a little bit more problems this time than we would have typically expected. We do look for ALNG production, first LNG to be with us in the first quarter of 2013.
Okay. Thanks for the time.
Our next question comes from Paul Cheng with Barclays Capital. Please go ahead with your question.
Thank you. Hi, guys. Good morning.
Good morning.
My two quick question. On slide 10, when you're looking at sequentially to the second quarter saying international refining, the margin is down $125 million. I must be missing something because all the benchmark indicator I track, whether it's in Singapore, Japan, they seems to have sequentially up from the second quarter, and all your competitors seems to have that. Is there any particular market that you affect that has seen a down margin environment? Or are there any particular product is important to you that have seen that?
It is a little counterintuitive, Paul. If you look at the Dubai 3-1-1, which is a pretty good proxy for Asian refining margins, the 3-2-1 is gasoline, diesel, and fuel oil. It doesn't include naphtha or LPG, both of which have been hammered really hard in the marketplace. The realized refining margin that you would expect out of 3-1-1 isn't actually as strong as what you get isn't as strong as what you would expect because you got the naphtha and LPG. Couple of our refineries are 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 3-1-1. 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 as we see in our actuals, are the marketing margins. 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. We've definitely seen some under realization of what we would like to see on marketing margins in Korea. Then we have lagged pricing on a number of our products in marketing. Jet and naphtha both get sold on a prior month basis. In a rising market, those prices were weak anyway, and now you're selling on a prior month, so you're selling even at a lower value relative to current in a rising market.
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 have been looking at using railroad, that maybe is a relatively near-term and effective way to ship the discount crude to their refining operation. Can you maybe help us to understand if there's any active or major initiative that you guys are contemplating or are currently taking to ship those discount crude to your, say, three coastal refineries, or that the opportunity set is not really there for California at all?
Well, it's 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, on this crude disconnect, it's like real estate. It's location, location. Our large coastal refineries are distant from where these advantages really are. 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. You've got transshipment 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-level based receipts of crudes.
The logistics are tough into the coastal refineries. They're very good into a couple of our smaller refineries. Our refinery in British Columbia and our refinery in Salt Lake City have pipeline connections to discounted crudes and have been able to take full advantage of that. 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. You're constantly optimizing the crude slate on your landed cost of crude via rail or versus these other modalities. That's a part of the normal business.
We're certainly doing everything we can to take advantage of the discounted crudes in those refineries. The opportunities get chewed up a lot in the transportation.
Thank you. 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, we can obviously take them offline.
Okay. No problem.
Thanks very much. Actually, before we get to the next call, I just want to make a point. I misspoke before on the turnarounds, got my acronyms mixed up here. The SGP is the unit that goes down once every four years or so. SGI and the KTLs are down typically once a year. I just wanted to make that clarification. Okay, we'll take the next questioner.
Our next question comes from Jason Gammel with Macquarie. Please go ahead with your question.
Thank you. 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? I guess I'm thinking both in terms of any environmental CapEx that you have to put into the business and any uplift in operating expense, although recognizing you might be able to pass that on to the consumer. 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. The reality is our refineries are amongst the most energy efficient refineries in the world. Our stationary source emissions are very low. The opportunity to spend further capital to mitigate stack emissions of CO2 are just about tapped out. Your choices are going to the market to buy credits, and that could be something that we'll see where the market price goes on that. We really don't have a lot of opportunity other than cutting runs and restricting supply. There are some who believe that is the ultimate way that we'll see people comply is just reducing their crude loads, which tightens up the market, which runs the price risk. If you get fuels under the Cap-and-Trade, which is anticipated out towards the middle of this decade, the costs explode.
That's where you go from costs in the $hundreds of millions a year to costs in the $billions a year. 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. The expectation is that as we see $hundreds of millions or billions of increased costs, that translates through into the price of the product. 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. 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.
That's a subject of A discussion with the regulators, and if in fact it were more economic to import than to manufacture here, then that's very well what we could do. That's got real implications for jobs and investment. It's still an evolving and uncertain environment, and frankly, we're trying to help people understand the implications of these things if it stays on the track that it's on right now, and the implications are all bad.
As a former California resident, you've got my sympathies.
Well, thank you.
Okay. I think we're running over our time here. Perhaps one more question, and then we'll have to close it off.
Our next question comes from Iain Reid with Jefferies. Please go ahead with your question.
Hi. Morning, everyone. Mike, can I ask you more of a macro question? I heard one of your competitors saying yesterday they thought we were close to the bottom of the chemical cycle. I'm not sure whether he was talking about the naphtha base or ethane base, could you maybe make a comment on that? 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.
Yeah. 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. That's mostly what CPChem has. Naphtha-based crackers have been in a pretty tough environment. They're the marginal producer, and with high crude oil prices, naphtha-based cracking margins have not been very attractive at all. We do continue to see growth in demand for the derivatives in the polyolefin chain. If there's 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.
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. I'll 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. We watch these trends pretty carefully because those are sales into industrial sectors. Marine transport is a leading indicator of global economic activity. 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. 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 of the world as well.
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. 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.
Mike, thank you very much indeed.
You bet.
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. With that, I'll close it off 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.