Good morning. My name is Sean, and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 2012 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' remarks, there will be a question and answer session and instructions will be given at that time.
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 Q3 earnings conference call and webcast. On the call with me today is Mike Wirth, Executive Vice President, Downstream and Chemicals and Jeff Gustafson, 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 2. Slide 3 provides an overview of our financial performance. Financially, it was another solid quarter. The company's 3rd quarter earnings were $5,300,000,000 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 3rd 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 Q3, we repurchased $1,250,000,000 of our shares. In the Q4, we expect to repurchase the same amount. Turning to slide 4. Cash generated from operations was almost $8,000,000,000 during the quarter, bringing our year to date operating cash flow to just over $26,000,000,000 which is net of about $2,000,000,000 build in inventory. At quarter end, our cash balances were approximately $21,000,000,000 and our net cash position was approximately 9,000,000,000 dollars 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 Q3 2012 with the Q2 2012. As a reminder, our earnings release compares Q3 2012 with same quarter a year ago. 3rd quarter earnings were $5,300,000,000 a decrease of approximately $2,000,000,000 from 2nd 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 $200,000,000 to a net negative position of nearly $300,000,000 in the 3rd quarter. Upstream earnings were down $481,000,000 on unfavorable foreign exchange effects and lower production, partly offset by a gain on an asset sale. Downstream results decreased by approximately $1,200,000,000 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 Q3 were $196,000,000 lower than 2nd quarter's results. Lower realizations reduced earnings by $140,000,000 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 $85,000,000 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 $285,000,000 lower than the 2nd quarter. An unfavorable swing in foreign currency effects decreased earnings by 470,000,000 The 3rd quarter had foreign exchange losses of approximately $250,000,000 compared to gains of $220,000,000 during the 2nd quarter. As a reminder, these are primarily balance sheet translation effects. Lower liftings, primarily due to planned turnarounds in Kazakhstan and the UK, decreased earnings by $235,000,000 The gain from the previously announced sale of an equity interest in the Wheatstone LNG project increased earnings by about $600,000,000 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 tank of 4,200,000 tons per year from the Wheatstone project.
The other bar reflects a number of unrelated items including higher DD and 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 3rd quarter would include higher turnaround and maintenance activity and it did. Planned turnaround activities primarily in Kazakhstan and the UK decreased production by 78,000 barrels per day.
The 2nd generation plant or SGP turnaround at Tengiz Chevron or TCO started the 1st 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'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 2,600,000 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 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 2nd quarter. We expect production in the 4th quarter to be higher than in the 3rd 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 2,680,000 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 $346,000,000 in
the 3rd
quarter. Lower margins decreased earnings by $20,000,000 dollars driven by significantly weaker marketing margins, which were only partly offset by stronger refining margins. West Coast marketing margins fell more than 40% during Q3, 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 Q4 with restart currently planned for the Q1 of next year.
Other units in the refinery continue to operate, although at reduced rates. Lower volumes decreased earnings by $125,000,000 primarily related to our Richmond refinery operating at a reduced rate as well as a slowdown at Pascagoula refinery due to Hurricane Isaac. Timing effects represented a $180,000,000 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 Q3 compared to sharply falling prices during the Q2. The other bar consists of several unrelated items.
On slide 10, international Downstream earnings were $936,000,000 lower this quarter. Lower realized margins contributed $125,000,000 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 340,000,000 dollars Falling prices in the 2nd quarter resulted in a $190,000,000 gain whereas rising prices in the 3rd quarter resulted in a $150,000,000 loss. The net earnings impact for the year related to timing is negligible as compared to year to date earnings of approximately $1,700,000,000 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 $245,000,000 $100,000,000 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. 3rd quarter net charges were $575,000,000 an increase of $284,000,000 between periods. An unfavorable swing in corporate tax items resulted in a $134,000,000 decrease to earnings.
Corporate charges were $150,000,000 higher in the 3rd quarter. Year to date, corporate charges were 1,400,000,000 dollars which is higher than our quarterly guidance range of $300,000,000 to $400,000,000 However, we currently expect Q4 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 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 3 quarters, we've earned $3,400,000,000 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 Chemicals segment is 18.6%, which also ranks number 2 among our peers. Our relative competitive performance on these two measures has steadily improved over 20 1011 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, 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 Sherwin Phillips Chemical. Already a leader in the production of normal alpha olefins, CPChem is constructing the world's largest on purpose one 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 on our Pascagoula base oil plant, which remains on track for planned start up 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, Orionite 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're 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 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, etcetera 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 realized 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 2 month stretch of time for the U. S. West Coast.
The West Coast market, West Coast gasoline market in particular is somewhat unique and that is 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 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 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 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 Sator II and Sator IV wells, our 15th and 16th discoveries in Australia since mid-two 1009. These new discoveries further highlight the quality of Chevron's exploration capabilities and the continued growth of our vast natural gas resources 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 2nd 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 efforts. We sanctioned the Leonzi project located in a unitized offshore zone between Angola and the Republic of Congo. It is the 1st 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. 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 1,500,000 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, Klein and Atoka Shale 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 reside, our near term focus will be on the Bone Springs formation as well as the Avalon and Wolfcamp Shale.
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 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 3,300,000 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 $12,000,000,000 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.
Our first question comes from Evan Kalia with Morgan Stanley. Please go ahead with your question.
Hey, good morning everybody and thanks as always for the additional information. It is helpful. Just maybe first question for Pat. I mean I know it may be premature, but last year Chevron made a competitive dividend raise. And 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 in 20 14 beyond? If you can I have a follow-up please?
Okay. Evan, I think it's a good question. But frankly, you 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 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. 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 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. And if I could have a follow-up to take advantage of Mike being on the call. Mike, I know you've talked about positive trends in the base oil business in the past and you're increasing your premium base oil capacity at Pascagoula. But 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 $1,400,000,000 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? Thanks.
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 1, which is made through a relatively simpler process of solvent de waxing. 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 lubricants, which is the Group 2 plus or premium base oils, which are made through a hydroprocessing technology, which Chevron actually is one of the 2 primary licensors in the world for.
And we have some distinct technology advantages there. So it's the Group 2 or the premium base oil market is a higher margin market and it is the rapidly growing market as the Group 1 market declines in demand. So you've got absolute demand growth for lubricants. And within that, you've got Group 1, which is a larger portion today shrinking in size. And so you've 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 manufacturers premium base oils with Pascagoula. Will 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. The logistics disadvantage to get it to the large growth markets would be non trivial. 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. Thanks.
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 percent -ish range.
Wonderful. Thank you, guys.
Thanks, Evan.
Our next question comes from Ed Westlake with Credit Suisse. Please go ahead with your question.
Yes. Thanks, everyone. 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 Q4 with an expected start up in the Q1 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 Q1 of next year.
Okay. Thanks for that Mike. And then just switching to chemicals. I mean, obviously, you've got the big ethane cracker. You've got the Hexane 1 plant.
Global demand for chemicals is still going to grow, but 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 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.
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 in North America for that matter, 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.
Thanks. And then also just thanks before I sign off to Melody and Roy and for everyone for the great trip to Gorgon. Thank you.
Thanks. I 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. Good morning. Good morning, Doug. I also have a couple of questions for Mike. First, I wanted to see if there was an update on the $1,000,000,000 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, our new program is possible for 2013. And then second, the plan to close the Sydney refinery should reduce the losses of Caltex and refining. And while I realize that the Brisbane plants 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? Or were there other strategic reasons to keep that plant open? So two questions.
Okay. On the $1,000,000,000 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 8 baseline and that was a multiyear program. And as we began this year, we were closing in on the $1,000,000,000 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 continue to 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'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 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 there we have every reason to believe that we can grind out further improvements in that arena. The other thing that will drive financial performance with 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 planet 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 Cornell 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.
Okay. Okay, good answers. Thanks.
Our next question comes from Arjun Murti with Goldman Sachs. Please go ahead with your question.
Thank you. 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 at that. As the business shifts towards potentially being more of a growth mode, are you still comfortable with the fifty-fifty 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 better ways to optimize value?
Is there a requirement for generating 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 1st 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 Philips to ConocoPhillips and now Philips 66. Both companies injected not only their assets, but really their human capability in the chemical 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 ask for them to pay down the debt. And 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. 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 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. 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 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.
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 is going to have to build out some of that infrastructure and there's certainly some of that activity underway. But the Gulf Coast is 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 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, etcetera.
That's great. Thank you so much.
Our next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead with your question.
Thanks. Good morning, everybody. 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, Q1, Q2, Q3 and then Q4, 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 2011, the pattern in 2010, the in 2010, the pattern in 2009, etcetera, 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. Thanks for that. 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 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 that 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 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'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. 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 where 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 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 on 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 operation. We're pretty circumspect about capital investments 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 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 referred 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 will be a negative impact on jobs, on consumers and by design and by intent, AV32 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.
I appreciate the full answer. Thanks, Mike.
Our next question comes from Faisal Khan of Citigroup. Please go ahead with your question.
Thank you. Good morning. 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. I'm just 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, the turnaround that we had this time of SDI 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 downtime that are just a normal part of the maintenance program. This is 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 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 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.
But we do look for LNG production, 1st LNG to be with us in the Q1 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 questions. On Slide 10, when you're looking at sequentially to the Q2 saying international refining, the margin is down $125,000,000 Can you help us I must be missing something because all the benchmark indicator I track whether it's in Singapore, Japan, they seem to have sequentially up from the Q2 and all your competitors seems to have that. So is there any particular market that you have picked that have seen a down margin environment or that any particular product is important to you that have seen that?
Yes. So let me it is a little counterintuitive, Paul. If you look at the Dubai 311, 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 3.11 isn't actually as strong as what you get isn't as strong as what you would expect because you get the naphtha and LPG.
Couple of our refineries are GSLTEX 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 11. 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 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 on 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 Q3, we're 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 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 is contemplating or is currently taking to ship those discount crude to your say 3 coastal refinery or that the opportunity set is not really there for California at all? 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, location. And 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. And so 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 based receipts of crudes.
So the logistics are tough into the coastal refineries. They're 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 have 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. But 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.
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 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. I misspoke before on the turnaround, 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. 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? And I guess I'm thinking both in terms of any environmental CapEx that you have put into the business and any uplift in 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 car Bob 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 storage 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 going to 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. It's just reducing their throughputs, 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 100 of 1,000,000 of dollars a year to costs in the 1,000,000,000 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 100 of 1,000,000 or 1,000,000,000 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 much higher premium than the rest of the country. And that is the policy path that we are on.
The issue of car Bob 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 the manufacturer here, then 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 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. So perhaps one more question and then we'll have to close it off.
Our next question comes from Ian Read with Jefferies. Please go ahead with your question.
Hi, good 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 you're talking about a naphtha base or ethane base. But can you maybe make a comment on that?
And 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 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. And so we do continue to see growth in demand for the derivatives in the polyolefin chain. So 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. 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'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. And so we watch these trends pretty carefully because those are sales into industrial sectors.
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 of 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.
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. So with that, I'll close it off and turn it back to you, Sean.
Thank you. Ladies and gentlemen, this concludes Chevron's Q3 2012 earnings conference call. You may now disconnect.