Good morning. My name is Jonathan, I will be your conference facilitator today. Welcome to Chevron's third quarter 2013 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's remarks, there will be a question and answer session. Instructions will be given at that time. If anyone should require assistance during the conference call, please press star then zero on your touch-tone telephone. As a reminder, this conference call is being recorded. I would now like to turn the conference call over to Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.
Thank you, Jonathan. Welcome to Chevron's third quarter earnings conference call and webcast. On the call with me today are Joe Geagea, Corporate Vice President and President, Gas and Midstream, and Jeff Gustavson, General Manager, Investor Relations. We'll refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. We ask that you review the cautionary statement on Slide 2. Slide 3 provides an overview of our financial performance. The company's third-quarter earnings were $5 billion, or $2.57 per diluted share. Return on capital employed for the trailing 12 months was 15%. Our debt ratio at the end of September was 11%. In the third quarter, we repurchased $1.25 billion of our shares. In the fourth quarter, we expect to repurchase the same amount.
Though not shown on the slide, I'd like to call attention to our track record on shareholder returns. We're in first place on total shareholder returns for the three-year, five-year, and 10-year periods compared to our peer group of global integrated energy companies. Turning to Slide 4, cash generated from operations was $10 billion during the third quarter and approximately $25 billion year-to-date. The third quarter was the strongest cash generation quarter this year. Adverse working capital effects noted earlier in the year continued to abate. Importantly, third quarter also saw a stronger operating performance in both our upstream and downstream businesses. Capital and exploratory expenditures were $9.6 billion during the quarter and $26.4 billion year-to-date. I'd like to make it clear that major resource acquisitions stemming from our business development activities are not included in our annual budget targets.
We have found the success rate, timing, and pricing for this effort to be too uncertain to effectively include in our annual budgeting and board approval process for C&E. We've been very successful this year in our resource acquisition effort, picking up acreage and project opportunities in Canada, Australia, and the Kurdistan region of Iraq. We anticipate we will close the year with C&E outlays above our planned level. There are still some large uncertainties on timing. We presently anticipate our 2013 C&E investments will be around 10% or so higher than our original target for the year. At quarter end, our cash balances exceeded $18 billion. Total debt balances were identical in size. We ended the quarter in a neutral net cash, net debt position. Confirming what I have said previously, the company continues to move toward a more traditional net debt structure.
Jeff will now take us through the quarterly comparison. Jeff?
Thanks, Pat. Turning to Slide 5, I'll compare results of the third quarter 2013 with the second quarter of 2013. As a reminder, our earnings release compares third quarter 2013 with the same quarter a year ago. Third quarter earnings were $5 billion, about $400 million lower than second quarter results. Foreign exchange movements accounted for more than the overall decrease in earnings, worth almost $600 million of the decline. The strengthening of the U.S. dollar in the second quarter and the weakening of the U.S. dollar in the third quarter caused a significant swing between the two periods. We moved from a net positive foreign exchange position in the second quarter of $300 million to a net negative position of nearly the same amount in the third quarter. Without this element, our earnings performance this quarter would actually be better than the prior quarter.
Upstream earnings were up $143 million, reflecting higher liquids realizations and liftings, mostly offset by unfavorable foreign exchange effects. Downstream results decreased $386 million between quarters. Lower margins and unfavorable foreign exchange effects, partly offset by higher volumes, drove the decrease. The variance in the other bar largely reflects an unfavorable swing in corporate tax items during the quarter. On Slide 6, our U.S. upstream earnings for the third quarter were $57 million lower than second quarter's results. Higher realizations increased earnings by $90 million, driven largely by a rise in crude oil prices, partially offset by the fall in natural gas prices. Lower production volumes decreased earnings by $30 million, mainly due to maintenance activity in the Gulf of Mexico, partly offset by higher production in the Permian. The other bar reflects a number of unrelated items, including higher DD&A and higher exploration expenses. Turning to Slide 7.
International upstream earnings were $200 million higher than the second quarter. Higher realizations increased earnings by $430 million. Average liquids unit realizations increased by 11%, consistent with the increase in average Brent spot prices between quarters. The timing of liftings across multiple countries increased earnings by $90 million. At the end of the quarter, we were in a slightly overlifted position. An unfavorable swing in foreign currency effects decreased earnings by $465 million. The third quarter had a loss of about $190 million compared to a gain of about $275 million in the second quarter. The other bar reflects a number of items. Favorable tax effects, gains on asset transactions, and lower operating expenses were partially offset by higher exploration expenses. Slide eight summarizes the quarterly change in Chevron's worldwide net oil equivalent production. Production increased 3,000 barrels per day between quarters.
New wells at our Agbami and Usan projects in Nigeria, additional production from the Delaware Basin in the Permian, as well as volumes associated with Angola LNG increased net production by about 22,000 barrels per day. Planned maintenance activities decreased production by 14,000 barrels per day during the quarter, most notably in the U.K., Trinidad, and Thailand, with a partial offset from less maintenance activity in Australia. External constraints hurt third-quarter production by 10,000 barrels per day, primarily due to a mid-quarter lightning strike in Thailand, which severely damaged and necessitated the shutdown of a customer's gas processing plant. This, in turn, curtailed our Thai gas production. The base business and other bar includes the impact of normal field declines, cost recoveries, and the impact of price effects on entitlement volumes.
Production for the first three quarters of 2013 averaged just over 2.6 million barrels a day, below our initial full-year production guidance of 2.65 million barrels per day. Several factors have affected our year-to-date production results. First, Angola LNG's ramp-up of production has been slower than anticipated. Second, turnaround activity across various locations has been more extensive than originally planned. A final contributing factor relates to the damage at the gas plant in Thailand. We expect volumes to be higher in the fourth quarter as production is restored following maintenance-related downtime during the third quarter and as new production comes online. For the full year, we expect to come in around 98%-99% of our original production target. Turning to slide nine. U.S. downstream earnings improved by $111 million between periods.
Higher volumes increased earnings by $55 million, primarily due to our Richmond, California refinery running at normal capacity for the full quarter. Lower refining and marketing margins decreased earnings by $95 million, driven by rising crude costs. Reduced industry crack spreads also reflected improved supply conditions and higher plant utilization rates following the end of second-quarter maintenance activity. Lower operating expenses increased earnings by $30 million, primarily due to lower environmental charges. Greater gains on miscellaneous small asset sales improved earnings in the third quarter by $60 million. The chemicals and other variants primarily reflects the absence of planned and unplanned downtime at CP Chem's Port Arthur and Sweeny plants in the second quarter. On slide 10, international downstream earnings decreased by $497 million between quarters. Higher plant utilization rates boosted volumes and increased earnings by $30 million in the third quarter.
Refining and marketing margins were lower by $220 million. Rising crude costs, continued soft product demand, and oversupply in the Far East weakened industry crack spreads, while price lag effects, mainly for jet fuel and naphtha in Asia, impacted marketing margins. Timing effects represented a $140 million negative earnings variance between quarters, driven largely by the revaluation of inventory. The swing between quarters was primarily due to rising crude prices during the third quarter compared to falling crude prices during the second quarter. Foreign currency swings reduced earnings by about $115 million. Third quarter had a loss of approximately $85 million compared to a small gain of $30 million in the second quarter. The other bar includes a number of unrelated items, including various tax items and higher shipping costs. Slide 11 covers all other.
Third quarter net charges were $522 million compared to $350 million in the second quarter, an increase of $172 million between periods. Adverse corporate tax items resulted in a $219 million decrease to earnings between quarters. Our overall year-to-date effective tax rate, at just around 40%, is trending a little lower than in recent years. As you know, in any one period, this overall rate can be influenced by many factors, including jurisdictional mix between upstream and downstream, jurisdictional mix within upstream, foreign exchange, and asset sales transactions. Corporate charges and other items were $47 million lower this quarter. Year-to-date net charges in the all other segment were $1.3 billion at the end of the third quarter. We believe our quarterly guidance range of $400 million-$500 million for the all other segment is still appropriate going forward.
Joe is now going to provide an update on our LNG marketing activities. Joe?
Thank you, Jeff, and good morning, everyone. I'd like to spend a few minutes talking about the LNG market and our LNG portfolio. Turning to slide 13, I'll start by grounding you quickly on the global demand outlook for energy. The world economy is growing, driving increased demand for all forms of energy. Much of this growth is in Asia, where people increasingly aspire for a better quality of life. Achieving this aspiration does require stable, secure, and affordable energy supplies. Total world energy demand is forecast to increase 30% by 2025 from today's level. Natural gas demand is projected to grow even more, by about 40% by 2025, and LNG demand growth is expected to be even greater. Turning to slide 14, LNG demand has already doubled since 2000, and it is predicted to double again by 2025.
Meeting this demand will require three elements: maintaining the reliability of existing supply, delivering current LNG projects under the construction of new LNG capacity. Even if the first two elements are well in hand, this still leaves an opportunity of around 150 million tons per year of new projects to be sanctioned. Now, many buyers are counting on the U.S. to make up the shortfall with pricing linked to Henry Hub. Even if you believe the most optimistic predictions of new U.S. supply available for export, there is still a projected shortfall of more than 50 million tons in 2025. More reasonable predictions of U.S. exports suggest a gap of around 100 million tons in 2025. The U.S. alone will not bridge this forecast demand-supply gap, and thus, we believe new supply needs to come from multiple sources.
Developing these supplies will also take time, whether that's for permitting and construction of U.S. LNG export terminals or for exploration, appraisal, and development of new producing regions such as East Africa. Building and maintaining LNG facilities is technically challenging, capital intensive, and requires significant expertise. The last 35 LNG projects developed globally took on average over 18 years to deliver that LNG to market. Although we do acknowledge that completion times are improving. Additionally, capacity utilization rates for LNG facilities in production have only averaged about 85% in recent years. Geopolitical instability, resource availability, and unplanned turnarounds have resulted, on average, in roughly 35 million metric tons of the existing nameplate capacity being unavailable at any given time. Turning to slide 15.
We have seen growth in global LNG trading and expect that interregional trade of LNG will continue to increase, we believe that global gas markets will remain regionally distinct over the medium to long term. This is mainly due to the high cost and relative lack of infrastructure to transport and store gas globally. While two-thirds of the world's oil is shipped by tanker, only 10% of the world's current natural gas supply is shipped as LNG. This is forecast to increase to 14% by 2025. We believe the majority of this LNG will continue to be delivered under long-term contracts. The traditional LNG importing countries of Japan, Korea, and Taiwan have no interconnecting pipeline infrastructure and virtually no indigenous energy resources, and therefore rely on LNG to meet almost all of their gas demand. Only five years ago, 17 countries were importing LNG.
Today, 26 countries are doing so, this is expected to increase. Let's move to slide 16, where I'd like to focus more specifically on U.S. LNG exports. Many analysts forecast that U.S. LNG exports should reach approximately 50 million tons per year by 2025, equivalent to around 11% of the world LNG demand and about 8% of domestic U.S. gas demand. At these levels, U.S. LNG exports would only represent a small share of the global LNG market. Greenfield LNG projects are unlikely to be developed outside of the United States unless a significant portion of the offtake is committed under long-term contracts with robust pricing that underpins the financial investment required to monetize these resources. A common perception is Henry Hub link pricing will mean landed LNG prices in Asia will be significantly less than other world sources. We think that's not automatically a given.
U.S. liquefaction costs are likely to rise as more projects compete for resources, including engineering contractors, fabrication yard space, and project financing. In addition, growing demand in the United States for new petrochemical projects, power plants, exports to Mexico, and the transportation segment will mean new demand pull on the same supply base. Coupled with weather and storage effects, this could easily lead to increased price strength and volatility for Henry Hub. In order to ensure that sufficient supplies do get developed, there needs to be cooperation, alignment, and understanding between LNG buyers and suppliers. This is helped when buyers diversify their energy mix, maintain a geographically diverse LNG portfolio, recognizing that no one region, including the United States, can meet all expected demand, finally, take equity positions in LNG projects to ensure the right projects are built in the right places for the right price.
We've seen this formula work in Gorgon and Wheatstone, and we're confident the same will be true for Kitimat. Turning to slide 17, I'd like to now talk about our LNG sale commitments. From a portfolio perspective, we believe it's prudent to leave around 25% of volume for placement on the spot market for operational flexibility. However, at the individual project level, this ratio may vary. For example, on Gorgon, we are 65% committed. We are still prepared to increase volumes under contract. However, Gorgon is scheduled to come online at a time when limited new supplies are expected. We are confident in being able to place uncommitted volumes into the market. On Wheatstone, 85% of Chevron's equity LNG is now committed on long-term basis.
In addition to the Gorgon and Wheatstone foundation projects, we have made good progress this year with buyers for LNG from our Indonesia Deepwater Development or IDD. For our unsanctioned projects, including IDD, Kitimat and Gorgon Train 4, we are targeting to have around 70% committed under long-term contracts by the time we'll reach a final investment decision. Once achieved, we will end up with our desired portfolio objective of having 75% of our LNG production sold through long-term contracts. Turning to slide 18. I'd like to close by showing you how Chevron is well positioned to become a major LNG supplier by the end of this decade, based on WoodMac estimates. With the projects under construction at Gorgon and Wheatstone, and with our existing equity shares in Angola LNG and Australia North West Shelf, we will be one of the top 10 LNG suppliers in the world.
If we include Kitimat and Gorgon Train 4, we will potentially move into the top five. In summary, we see strong LNG market fundamentals supporting our growing LNG portfolio, which should allow us to deliver strong future gas generation for many years to come. I'll now turn it back to Pat.
Okay. Thank you, Joe. Let's take a look at the latest updates on our LNG projects. The Gorgon project is over 70% complete. We continue to make good progress on all fronts. In early October, we installed the third of five gas turbine generators. To date, 14 of the 21 LNG Train 1 process modules have been installed, three are in transit, the remaining are scheduled to follow in fairly rapid succession. Work on the jetty is progressing. We now have 43 of the 56 jetty caissons installed, including those needed to support all key structural elements. We have recently reached mechanical completion of the domestic gas pipeline in preparation for operational readiness by year-end. Offshore pipe lays are complete on the Jansz-Io 30-inch pipeline. Finally, three wells at the Jansz-Io field are ready to flow gas, and seven wells are completed at the Gorgon field.
Wheatstone is proceeding per plan and is now over 20% complete. We continue to transform the site with ongoing earthworks and good progress on establishing critical infrastructure. Construction continues on the materials offloading facility, and we completed our first permanent foundation concrete pour in September. Site preparation continues with about 19% of our 23,000 piles driven, including the commencement of the LNG tank pile driving. Platform construction is over 43% complete, and we have received critical platform equipment such as the power transformers and process vessels. We just completed our micro tunnel boring under the shoreline in preparation for the offshore installation of the trunk line. We've posted several updated photos of progress made at both Gorgon and Wheatstone on our investor website, located at Chevron.com, and I invite you to take a look at those. For Kitimat, front-end engineering continues on plan.
We remain focused on early earthworks at the LNG plant site, where construction on the office, camp industrial site, and service road is ongoing. Key activities for the Pacific Trail Pipeline are obtaining necessary permits, building roads, and securing right-of-way access. LNG marketing activities and engagement with potential foundation customers are underway. The timing of the final investment decision will be determined by our ability to secure sufficient LNG offtake agreements with our customers. Turning now to slide 20. I'd like to share some highlights of the strategic progress we've made during the quarter. We signed binding long-term sales and purchase agreements with Tohoku Electric Power Co., Inc. in Japan to supply just under 1 million tons per year of LNG for up to 20 years. As Joe noted, this brings total volumes committed to customers in Asia on a long-term basis to 85% for our Wheatstone project.
Continuing with the Australian theme, we recently announced the acquisition of two deep water exploration interests located in the Bight Basin off the southern Australian coast. These are very large blocks with significant exploration potential and further reinforces the importance of Australia to Chevron's global growth strategy. In Canada, we successfully completed an initial 12-well exploration drilling program in the liquids-rich portion of the Kaybob area of the Duvernay Shale Play. Initial well results were very encouraging, with average initial production rates in excess of 1,200 barrels of oil equivalent per day. Both of these developments are consistent with our focus on early entry opportunities, which have the potential to generate the most value for our shareholders. We also had a major milestone in our downstream and chemicals business. CP Chem announced final investment decision for its U.S. Gulf Coast petrochemicals project.
This project includes construction of a 1.5 million metric ton per year ethane cracker, as well as two new polyethylene facilities, each with an annual capacity of 500,000 metric tons. This is an attractive project, one that takes advantage of existing infrastructure and advantaged feedstocks. Plant startup is planned for 2017. Turning now to slide 21. I'd like to close by highlighting our continued strong performance, particularly in our upstream business. Our 2013 year-to-date upstream earnings margin was $23.33 per barrel. Based on these year-to-date results, we continue to lead our direct peer group by a wide margin. We're almost $5.70 per barrel ahead of our closest competitor. This is a position we have now held for 15 consecutive quarters. We also led on this important metric at the six-month mark by over $4.25 per barrel against a wide range of E&P companies.
These peer-leading financial results are directly related to the quality of our investment decisions and the strength of our portfolio. We appreciate you listening in this morning and your interest in the company. I'd like to now open up the microphones. Joe and I are happy to take your questions. We do have a full queue, so please limit yourself to one question and a single related follow-up if that's necessary. We'll certainly do our very best to see that we get all your questions answered. Jonathan, please open up the lines for questions.
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're 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, then one on your touch-tone telephone. Our first question comes from the line of Ed Westlake from Credit Suisse. Your question please.
Good morning, thanks very much, (Pat), for getting Joe on the call. I'll start with an LNG question. I'm up late at night, and I keep getting these stories from Australia on my iPad which are obviously going around the market. People are very worried about the LNG jetty or whatever it is, something else with the project. Maybe give us a color on how you're feeling about the startup date and maybe if there are any penalties if the date slips back in time, what's the sort of killer date to get Gorgon on stream? Thanks.
Okay. Thanks, Ed, for the question. I think we have been pretty upfront about acknowledging some of the challenges that we've had earlier. We talked previously about logistics challenges, labor productivity, and weather challenges. We have solved, for all practical purposes, the logistics challenges. In fact, we've asked for and have received additional laydown space on the island, so we're able to now build material and inventory on Barrow Island. Productivity, I would say, is improving on all fronts, but there are still some areas that still need to improve. We are still impacted by weather. We had a heavy rainy period back in June. Right now we're in the good weather period and are making very good progress each month. I think we are moving into a critical phase from a schedule standpoint on the project.
We talk about getting all of Train 1 modules onto the island. That's proceeding pretty much as planned. I think largely they will be here by year-end or shortly into the new year. Maybe one that will be mid-quarter next year. What's important next is the mechanical, electrical, and instrumentation work, and contractor work on those activities is ramping up on the island now. There are still uncertainties that exist with a project of our size, and our challenge every day is to find the risks, mitigate the risks as they arise. The jetty, I think we tried to say all the critical elements of the jetty, the main critical elements of the jetty, those that support the structural elements are on plan.
Right now, we are in the process of finalizing our budgets for the year, and should there be any reviews during that suggest a material change other than what we've said previously, we'll certainly bring that to your attention. I don't have anything more to offer.
Thanks.
Ed, let me address your question on the marketing side. I'd like to say that our customers are our partners, so they fully understand the project challenges. I would also say that Gorgon is not coming up all at once. It is one train at a time. That gives us time to work with our partners, with our customers on accommodating their needs. We have those discussions ongoing all the time. I cannot address specifically what's in our contract with respect to penalties. As you can appreciate, these are commercial elements, and I cannot address those.
Thanks very much.
Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley. Your question please.
Yeah. Good morning, everybody. Thanks for the LNG commentary as well as addressing that CapEx question. Staying with Gorgon, Joe, can you update us on how the feed in Train 4 is progressing, and what is the interplay on Trains 1 and 3, their progress, and the ultimate decision upon expansion? Meaning, do your partners need to see more final Gorgon cost estimates before committing to the expansion, and albeit if it's a significantly lower unit cost expansion.
Yeah. Maybe I'll take the question around Train 4. I think we continue to work with our partners. We're all interested certainly in seeing this continue to progress. I think all of the JV partners are interested, though, in seeing Train 1 come up and seeing progress on 2 and 3, et cetera. Everybody wants to get an understanding of the cost structure. I also think that people want to get certainty around the fiscal and regulatory regime. As you know, there's been a change of government in Australia, a little bit of settling down and stability there would be appreciative. Those factors are going to be taken into account. I also think it's fair to say that the cost structure in Australia is different now than it was when Trains 1 through 3 were taken to final investment decision back in 2009.
The cost structure has elevated, I think it's fair to say that has put at risk some of Australia's global competitiveness. From a Chevron standpoint, we're going to look at Train 4, we're going to assess it under those new conditions, we're going to look at that relative to other opportunities that we've got in our portfolio and look for that next investment to compete with other opportunities. Obviously, a Train 4 does have certain brownfield economic advantages to it. We need to take those advantages, lay in the new macro conditions that we see in Australia, take a look at the whole portfolio activity. Having said all that, we are continuing on with environmental approvals for Train 4.
Maybe I'll add a bit of color commentary also because the marketing is essential to Train 4, all the reasons that Pat has mentioned, I would also say that the LNG market has different dynamics as well. Our job is to continue to find customers for Train 4, which we continue to do. We believe the offerings of a Train 4 are different than the offering of our other projects like Kitimat. Train 4 is an expansion. It's a brownfield expansion. Train 4 is exposure to Australia. Train 4, however, does not have equity unlike Kitimat where we're offering equity. It really caters to a different set of customers. In our view, from a marketing perspective, it's truly not competing with Kitimat, and I think that's important for us to say.
Thank you. To follow up, does that mean that the potential debottlenecking of Trains 1 through 3 is something that could potentially precede a Train 4? I mean, I know there are three different tranches of potential expansion. Does it change, I guess, the debottlenecking opportunity to move that forward, or is that still something that would follow if it did in fact follow?
Yeah. I think, Evan, debottlenecking is always something that you would do as an ordinary course of activity, oftentimes it has the very highest economics associated with it. That will be taken into account in our normal planning process.
Okay, great. I'll leave it for somebody else. Thanks.
Thanks, Evan.
Thank you. Our next question comes from the line of John Herrlin from Societe Generale. Your question please?
Yeah. Hi. Just two quick ones. With the Duvernay wells, Pat, about how much were they running? I know it's science time, it's early days, but I was just wondering an approximate cost.
You mean you're talking approximate well cost?
Well cost on the Duvernay.
Yeah, that's not a number that we want to give out at this point in time.
Okay, that's fine. Next one's on LNG. Are you surprised at all that on the demand side in terms of customers that they haven't built more physical gas storage in Asia? Do you think that will change as the LNG market builds up more?
That's a very good question, John. This is Joe here. It's going to take time for them to get there. Clearly there is some capacity with the regas terminals. We're seeing that in Thailand, we're seeing that in Singapore. Remember, that market is huge. Significant amount of storage has to be made available for it to really make a difference. I think we may get there eventually, but I see a slow pace to get to that point.
Okay, great. Thank you.
Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please?
Thanks folks. Joe, good to hear you on the call. If I could try two also please. Joe, first of all, can you remind us what the contract resets look like on your baseload marketing for Gorgon in particular? Maybe when you're addressing the question, if you could talk a little bit about whether the issue around Henry Hub pricing is really more about de-linking in the event oil, for example, went to $150 as opposed to actually depressing the current price. I've got a follow-up, please.
I'll start by saying that most contracts that are of that length, 20-year, for them to be sustainable and to be a win-win for both customer, for buyer and seller, have reopeners on them. Without getting into specifics, these reopeners are meant to really make sure that the pricing formula continue to reflect the market. What I can tell that all of our projects are paced, that we were not going to see major renewal for a big portion of the volume all in one year. We've been very careful in pacing these renewables over time because again, that's in our interest and in the buyer's interest to spread that renewal timing over a longer frame than just having them all occur in the same time. Back to your questions on Henry Hub. There are two elements to it.
We have been public in saying that LNG that comes out of the U.S., made in the U.S., it's perfectly okay for it to be priced off of Henry Hub. LNG that is made in Australia, East Africa, or Canada, it's a harder proposition to see why you would introduce a regional market reference to those markets. That's been very difficult. In terms of breaking the oil linkage, I will tell you that for the last 40 years, the industry has learned to operate within an oil framework that saw oil prices go up to $140 and go down to $20. I submit to you that within these traditional framework, you can introduce S-curves, you can moderate slopes. There's a lot of other levers that actually work to prevent LNG from becoming very unaffordable in the regions where affordability is becoming an issue.
I think we can address those excursions that could be harmful from an affordability point of view within a traditional framework without necessarily going to something unproven that could also be a lot more volatile. We've also said that one way for people to get a better attenuation on price is for them to get into the equity side. That clearly gives them direct exposure to the upstream side for the whole value chain, and effectively, you are getting an attenuation to pricing because you're getting the whole value chain benefits from that. Hopefully that helps.
It does a lot. Thanks, Joe, my follow-up was a bit quicker, but we all watch the unit earnings trends, the very strong unit earnings trends you guys have had for quite some time now. Whether we want to look at earnings or cash flow, the focus is earnings. I guess my question is, your DD&A runs about $6 lower than your peer group, and it appears to be trending higher. When you have all this non-producing capital coming online from these new projects, can you give us some feel as to how the DD&A trend is going to look? I'll leave it at that. Thank you.
Right. Doug, I think you should expect, we have seen, and you should expect the trend to continue, higher charges for DD&A. Certainly, that's the pattern we've seen over the last couple of years. It's the pattern that we see looking at 2013 versus 2012, and it is the expectation that I would have going forward for 2014. It is a direct reflection of the capital investment programs that we have had underway, and as we bring those new projects online, we see rate increases associated with that.
All right. I'll leave it there. Thanks, Pat.
Doug, I guess I would say, it's important even with that, we still have the leading earnings per barrel margin, and we have the leading cash margin.
Yeah, I'm just trying to figure what the future trend's going to look like when these projects come up, Pat.
I appreciate that. Okay.
Thanks very much.
Thank you. Our next question comes from the line of Paul Cheng from Barclays Capital. Your question, please.
Hey, guys. Good morning.
Good morning, Paul.
Two somewhat related questions, one for Joe and I think one for Pat. For Joe, when we look at Kitimat comparing, if you can give us some idea that what is the competitive position relative to building an LNG plant in Kitimat and operate there, which is a pretty remote area, and labor could be an issue comparing to in Australia, where you guys have a lot of operation, or that in the Gulf of Mexico, which you don't have a lot of operation. That's the first one.
Okay.
Pat, do you want me to give you the second one first?
Sure. Go ahead.
If I look at, this is not an issue in the near term, but your current cash flow essentially just barely covered your CapEx. At what point, now of course, when you have zero net debt, it's not an issue today, but theoretically, that from management standpoint, at what point you will start questioning whether you want to continue to borrow money to buy back stock? At what point when that continue, once that you eliminate the share buyback, that you will have to re-look at your CapEx program?
Okay. Good question.
I'll go first.
Okay.
Paul, on the Kitimat question, it's a very good question. I will start by talking a little bit about the resource base. If you look at our acquisition of that resource base, we're very, very pleased with the entry price. We also know that we have a huge resource base in both Liard and the Horn River. That resource base sits right at the gate of North Asia, where we continuously see increased demand. Strategically, it is very well positioned for North Asia buyers. Our buyers see that, and that's the value proposition we've been communicating to them. They also see in Kitimat two partners that have complementary skills, that are very aligned and very committed to the project. They see a federal government and a provincial government that are supportive and understand the opportunity.
They see a country that is very much in favor of exports and tilting toward Asia. They see a project with export permits in hand and a clear line of sight on a pipeline and a transportation solution. You did say something about the labor cost. I will tell you, though, if we're the first out of the gate, we will have an ability to attenuate that versus being the last one coming in to develop the project. Finally, what we tell our buyers, this is a great opportunity for them to participate through equity in the whole value chain. In doing so, they really get direct exposure to North America gas pricing. All of those are good value drivers for any buyer in North Asia. They're getting it.
I think we're getting good reception, and obviously time will tell in our ability to sign contracts, but we're very encouraged by what we see and the value that Kitimat can offer to those buyers. Now I'll go back to Pat for the
Capital question.
Still before that, from a cost standpoint, from what you can, because you know a lot about Australia, and I presume you know quite a lot about Gulf Coast. Is developing costs and operating costs of Kitimat is going to be competitive with Australia, but cheaper than Gulf Coast or any kind of insight that you can provide?
It is too early for us. I remind you that we've signed the transaction in February of this year. We became operator in July of this year. We are really getting on top. There are two things here that we need to be very careful on, is project development and execution, which is really we're focused on, and secondly, the marketing, and they have to go hand in hand. I would tell you, though, the freight advantage that we see in Western Canada clearly is something in favor of Canada compared to Gulf Coast exports. Okay. Paul, just going back to your question, I want to start with the priorities that we've always put out there in terms of uses of cash, dividends first, reinvesting in the business, taking care of our balance sheet, and then share repurchases really come at the very tail end of that.
You're right, we are in a period right now where our capital requirements are high. Just to remind you, we've got five LNG trains under construction. That's a very significant component. We do not see in the forward look that we will have anything as lumpy as that or as sized as that. We know 2013 is a high C&E year. We have said in the past that 2014 will be a high C&E year. George referenced last time on the call about a flattening that will occur. We do see that the uniqueness of our capital spend period right now is not something that we see coming forward in future years. At the same time, though, we do fundamentally believe our greatest value proposition for our shareholders is finding and investing in the right resources and developing the right projects.
We will continue to invest in the business. You see us doing that in terms of resource acquisitions that I talked about earlier. We try very hard to balance this returns and growth equation here, and we've been very successful. The decisions that we have made, and we believe the new resource acquisitions that we have made for the future for Growth 2020 and beyond, are excellent projects. We believe we're putting that equation together quite nicely. I guess the other thing that I would say is when you bring in new resource acquisitions like we've done with Kurdistan or Cooper Basin or Kitimat, et cetera, when you're adding those elements to your portfolio, it does mean that you reprioritize your portfolio, and certain things probably fall towards the bottom.
These would be more mature assets, less competitive in our portfolio, believe that they have potentially a spot in someone else's portfolio. That's where your asset sale or your portfolio optimization component increases. We've been very good at doing that in downstream. You've seen us do all that restructuring in downstream. Joe has overseen a fair amount of restructuring occurring in our midstream area, and I think you can expect some additional asset sales now coming forward from upstream.
Pat, is there some form of matrix that you look at from a financial net debt to capital or net debt to EBITDA, you will look at, say, once you reach a certain level, the share buyback will say maybe that comes to an halt?
We obviously are interested in maintaining our double A status, credit rating status. We're not interested in infringing upon that at all. We look at that as kind of a limiting factor. Frankly, Paul, we are such a long way away from that at this point. It's not a limiting component.
Thank you.
Thank you.
Thank you. Our next question comes from the line of Faisel Khan from Citigroup. Your question, please.
Good morning. Two questions. First on the LNG facility in Canada, or potential LNG facility in Canada. Can you discuss the merits of owning the entire integrated asset, and why not moving to a more asset-light model where a utility company owns the liquefaction facility, you own the resource, and you market the gas and charter the ships? It seems like it's a very large piece of invested capital. There's a lot of companies out there, especially in Canada and the U.S., that have the ability to finance this stuff at a much lower cost of capital. My follow-up is that it seems like building a pipeline from Liard and Horn River to Prince Rupert or even to the Kitimat is very expensive. There's a lot of depreciated pipe all the way from there down to the Gulf Coast that has a lower invested capital base.
Why not just ship the gas down there and sign up along these other facilities that are sort of ramping up? That's a little bit out of left field, but if you can help me answer those.
It's not a left field at all, Faisel. Good question. Let me tell you that we are not building a pipeline from the field to the LNG facility. We are clearly leveraging existing trunk lines that currently run, and they are operated and owned by others. The piece that we are building is the link from the trunk line to our facility. I call that our umbilical, and that's very essential for us to actually control that, to control the feed going into the LNG facility. Where we can, we are leveraging other facilities, infrastructures. Processing plants could be another place where we leverage as well. We are adopting some of what you're suggesting.
When we do this, we always look at the strategic fit of the asset. Is it essential for us to control it from a commercial point of view? Is it essential for flow assurance to our facility? Those are normally governing criteria for us to decide whether we want to own the interconnecting framework. Same thing by ships. We can sell FOB as well, and we don't have to build ships. Sometimes we have to build ships to ensure flow assurance on the back end of the LNG facility. The name of the game is really to get the molecules that we just acquired at a very attractive price in the Horn and Liard to the market and maximize our returns. We look through that whole thing in details.
The other options also we're looking at from lowering the capital investment, we're asking other equity partners to come in. By farming in for buyers, clearly we are lowering the capital exposure. We're looking at all of that to basically address the element of the question that you brought up, Faisel.
The pipeline gas, if you could pipeline all this gas down to the Gulf Coast on what's basically all this depreciated pipeline, whether it's Alliance or Northern Border, and then down NGPL to the Gulf Coast. The invested capital of those assets is far lower than these pipelines that TransCanada and Spectra are talking about building to supply that gas to the Canadian West Coast. Is that an opportunity where you can move that resource down to the Gulf Coast and export it out of the Gulf Coast and with the Panama Canal sort of opening up? It seems sort of like an asset-light sort of model, but I don't know.
Food for thought. Thank you, Faisel.
Fair enough. Thanks.
Thank you. Our next question comes from the line of Pavel Molchanov from Raymond James. Your question please.
Thanks very much. Two questions on your unconventional gas exposure. U.S. gas production was up almost 5% year-over-year. Is that primarily legacy Atlas acreage?
I think there's both an Atlas component as well as a kind of newer Permian Delaware Basin component to that.
Okay, fair enough. On to Europe, lots of headlines recently involving countries where you guys are operating or thought about operating in, Lithuania, Romania, et cetera. Any status update you guys want to provide on how you're thinking about that?
I think we tried to say right from the get-go that this would be a long-term development opportunity. It would take several years really to understand how the overall play could develop. We do think if it works and if it's proven up, then there's enough here to potentially build a business. We're just in the very early stages of exploration, I don't want us leaping too far, too soon with implications here. We're active in Poland. We've drilled four wells there. We've got 3D seismic underway as well there. In Romania, we're picking up seismic activity. Ukraine, we're still interested in having the PSA signed. We're hopefully getting closer on that. We continue to make progress. It will be dependent upon the local governments and the local communities wanting to have us be there, that's been a challenge.
It is an exploration play, I think we need to give it time to mature.
All right. Appreciate it.
Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question please.
Yes, good morning.
Good morning.
I guess I'd like to, on the upstream side, focus a little bit more on the cost side of things. Obviously it was a good quarter in terms of realizations on the top line, but you talked a little bit earlier about DD&A being an issue. Is there anything else maybe particular to the third quarter from an operating cost standpoint that's not recurring? I know maintenance is an issue sometimes, but I was just seeing if you could help us there and maybe think about how that unfolds in 2014 and 2015.
Yeah, no, I think from a cost standpoint, Exploration was heavier in the third quarter than the second quarter. If you look on a year-to-date basis, it's pretty much in line with what we have seen previously. We're seeing higher industry costs. You referenced that. I think that's just a general trend that has been evident. Also, maintenance in the third quarter was a little bit heavier, kind of per planned as well as some unplanned as well. I think those are the factors that I would call your attention to.
In terms of any thoughts on 2014 and 2015, are we seeing trends here? I agree with you that industry is seeing higher costs. Are there any trends specific to Chevron that we should think about? Even another way of asking it, as the LNG projects come on, are we going to see that as a significant impact, maybe lowering operating costs?
Yeah, I don't think there's anything unique in Chevron's operations going forward that I would suggest. I think I'll defer on the LNG operation side of things. I'm not in a position to comment about what operating expense looks like in 2015 and 2016 at this point. Okay, I think we've got time for one more question.
Certainly. Our final question comes from the line of Allen Good from Morningstar. Your question please.
Good morning, everyone. Just a couple for Joe on LNG. You've been pretty detailed on the merits of Canadian gas relative to Gorgon and relative to the U.S. Should we go ahead and just take it that exporting natural gas out of the Gulf Coast doesn't fit competitively within Chevron's current LNG portfolio?
You're making too many assumptions right there. We're focused on Kitimat for now. Again, we have opportunities in Australia. We're not ruling anything out at this stage.
Okay.
At the same time, I'm not prepared to tell you that we won't look at opportunities anywhere else in the world. For now, we're focusing on Canada.
Okay, thanks. Finally, you mentioned the appeal of the equity availability in Kitimat for some of your potential partners. Is there a minimum equity stake that Chevron would like to retain in Kitimat or vice versa, a sort of a target that you'd like to sell down as portion of equity in the project?
We have not put any number out there. Obviously, it's up to the buyer also to indicate interest. We kind of like a number in our mind in terms of where it end up, it's really a function of where the buyers are. We're flexible, remember, we've got a partner as well, we got to consult with them in terms of where they like to end up. The gate is open, though, for the buyers to tell us what they think. I don't know that we have indicated externally what that number is, we're open to entertain the buyers' ideas.
Okay, thanks. I'll just give one more quick one. You make a pretty convincing case that the demand for the LNG will be out there. Do you see any threats on the supply side, though, that could potentially disrupt the potential long-term economics for LNG projects?
In fact, I see the threat in the opposite direction. I see the threat as the longer it's taking us to enable projects to reach FID, and you fast-forward four to five years how long it takes to build them, this market can only go up, and that is not really where the buyers would like. That's why our plea with the buyers have been, we need to enable supply to come to the market because we have not seen anything on the demand side that is managing that carefully. We see more subsidy. We see nuclear out of the energy mix. We see shale gas development, a lot of places slower outside the U.S. All of that point to more need for LNG. I look at how many projects are actually reaching FID outside the U.S. I don't see a whole lot.
That can only mean problem down the road. We've seen that play out in the past. Back in 2007, there was an estimate of about 75 million tons of LNG that will hit the market in 2014. As we sit today, there's only 10 million ton that will come in 2014. We got to crack this equation, both from the supply side and the demand side. The longer we see projects delayed from reaching FID, I think the price equation gets more difficult.
Okay, great. Thanks for that.
Okay, thank you. Before we close off the call, since we didn't get a question on Ecuador, I would like to provide our investors an update on this matter before we close out here. It's a very important matter. As you're probably well aware, there have been several recent positive developments related to this ongoing litigation. Earlier in the year, several key witnesses, financiers, and other associates, including an Ecuadorian judge involved in the case, publicly denounced and exposed numerous examples of the blatant fraudulent tactics used by the plaintiff's lawyers during the trial.
More recently, an international tribunal convened under the authority of the U.S.-Ecuador bilateral investment treaty and administered by the Permanent Court of Arbitration in The Hague, found that the settlement and release agreements between the government of Ecuador and Texaco in the mid to late 1990s released Texaco Petroleum Company from any liability for all public interest or collective environmental claims. This was a definitive ruling on the single most important legal issue in the case, and it was made by an impartial tribunal in The Hague, where Chevron had picked one arbiter, the government of Ecuador had picked one arbiter, and we both had agreed on the third, and it was a unanimous ruling. Importantly, this ruling confirms that the claims against Texaco were not valid and should not have been brought in the first place.
It also signifies that efforts to enforce the Ecuadorian judgment, which the plaintiffs have so far unsuccessfully attempted in both Canada and Argentina, that those are in direct violation of national and international laws. Separately, a couple of weeks back on October 15th, the U.S. trial began in New York related to Chevron's civil lawsuit against the Lago Agrio plaintiffs and several of their lawyers, consultants, and supporters alleging RICO violations of the Racketeer Influenced and Corrupt Organizations Act. Trial proceedings in this New York lawsuit are expected to last a few more weeks. We're encouraged by these recent developments, but at the same time, we expect to need to continue to defend our position and defend our assets well into the future before a final resolution becomes available to us. With that, I will close off finally here.
Again, thank you for your interest in the company and your time here this morning. Good day to everyone.
Ladies and gentlemen, this concludes Chevron's third quarter 2013 earnings conference call.