Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's third quarter 2014 earnings conference call. At this time, all participants are in listen-only mode. After the speaker's remarks, there will be a question-and-answer session, and instructions will be given at that time. If anyone should require assistance during the conference call, please press star then zero on your touchtone telephone. As a reminder, this conference call is being recorded. I would now like to turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.
Okay, good morning. Thank you, Jonathan. Welcome to Chevron's third quarter earnings conference call and webcast. On the call with me today are Jeff Shellebarger, President, Chevron North America Exploration and Production, and Jeff Gustavson, General Manager, Investor Relations. We'll refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. We ask that you review the cautionary statement shown here on slide two. Turning to slide three, the company's third-quarter earnings were $5.6 billion, or $2.95 per diluted share. On a year-to-date basis, earnings were $15.8 billion, or $8.29 per diluted share. Included in this quarter's earnings were gains on asset sales of approximately $420 million, foreign exchange gains of $366 million, and a non-recurring economic buyout of a long-term contract. Taken together, these equate to a positive $0.34 per share.
On a year-to-date basis, the impact of foreign exchange movements is minimal. While asset sale gains and other non-recurring charges have provided a net boost to 2014 earnings of $770 million. There is a full reconciliation of these items on our last slide. Return on capital employed for the trailing 12 months was 12%. Our debt ratio at the end of September was 14%. We repurchased $1.25 billion of our shares during the third quarter. In the fourth quarter, we expect to repurchase the same amount. Turning to slide four, cash generated from operations was $8.7 billion during the third quarter and $25 billion year-to-date. Cash capital expenditures were $8.3 billion for the quarter and $25.7 billion year-to-date. Free cash flow for the quarter was $1.5 billion, and year-to-date, $1.9 billion.
At quarter end, our cash and cash equivalents totaled $14.5 billion, giving us a net debt position of $11 billion. Slide five compares current quarter earnings with the same period last year. Third quarter 2014 earnings were $643 million higher than third quarter 2013 results. Foreign exchange movements positively affected earnings by $366 million during the quarter, representing a swing of over $600 million between periods, mostly occurring in the upstream segment. As a reminder, foreign exchange movements for us are largely book translation effects with minimal cash flow impacts. Upstream earnings decreased by $443 million between quarters. Lower realizations and liftings and higher operating and DD&A expenses were partially offset by favorable foreign exchange movements and lower exploration expenses. Downstream results increased by about $1 billion, driven by stronger U.S.
refining and marketing results, larger gains on asset sales, favorable foreign exchange movements, and timing effects related to revaluation of inventory in a lower price environment. The improvement in the other segment primarily reflects the absence of a 2013 third quarter impairment of a power-related equity affiliate. Turning to slide six, I'll now compare results for the third quarter 2014 with the second quarter 2014. Third quarter earnings were approximately $70 million lower than second quarter results. Again, the earnings variance between quarters reflected a $600 million favorable movement in foreign exchange effects, most of which impacted the upstream segment. Upstream earnings decreased by $615 million, reflecting lower realizations and lower gains on asset sales, partially offset by a favorable foreign exchange swing between quarters and lower exploration expenses.
Downstream earnings increased by almost $670 million, driven by stronger R&M results, higher gains on asset sales, and a positive swing in foreign exchange between quarters, partially offset by lower chemicals earnings. The decrease in the other segment largely reflects corporate tax items and higher environmental expenses. Jeff Gustavson will now take us through the comparisons by segment.
Thanks, Pat. Turning to slide seven, our U.S. upstream earnings for the third quarter were $125 million lower than second quarter's results. Lower realizations decreased earnings by $175 million, consistent with the decline in U.S. liquids and natural gas price indicators. Higher production volumes in San Joaquin Valley and the Permian Basin increased earnings by $40 million. Lower exploration expenses, primarily associated with the deepwater Gulf of Mexico, increased earnings by $95 million. The other bar reflects a number of unrelated items. Lower operating expenses were more than offset by the negative impact from the economic buyout of a long-term contractual obligation. Turning to slide eight, international upstream earnings were $490 million lower than last quarter's results. Lower crude oil realizations decreased earnings by $420 million, consistent with the decline in international crude prices between quarters.
Lower liftings, primarily related to the sale of our upstream interest in Chad, decreased earnings by $95 million. Gains on asset sales were $430 million lower, also driven by the sale of our interest in Chad and Cameroon, which occurred during the second quarter. Favorable movements in foreign currency effects increased earnings by $490 million. The third quarter had a gain of about $340 million, compared to a loss of about $150 million in the second quarter. The other bar reflects a number of unrelated items, including lower trading results and higher DD&A, partially offset by lower exploration expenses. Slide nine summarizes the change in Chevron's worldwide net oil equivalent production between the third quarter 2014 and the second quarter 2014. Production increased by 23,000 barrels per day between quarters.
Shale and tight resources growth contributed 18,000 barrels per day, driven primarily by production increases from the Midland and Delaware Basins in the Permian, where new wells were brought online. The net impact of lower turnaround activity during the quarter increased production by 23,000 barrels per day. Planned maintenance at Tengizchevroil's KTL facility in Kazakhstan, in addition to Australia, was completed in the second quarter, while third quarter planned turnarounds, including Tengizchevroil's SGI/SGP facility, the U.K., and Thailand, were on balance less extensive than the prior quarter. The Tengizchevroil SGI/SGP turnaround continued through October. Asset sales reduced production by 18,000 barrels per day, principally due to the sale of producing assets in Chad.
As a reminder, the production impact associated with this sale had already been incorporated in both our updated production guidance for 2014, as well as in our 2017 production target of 3.1 million barrels of oil equivalent per day. slide 10 compares the change in Chevron's worldwide net oil equivalent production between the third quarter 2014 and the third quarter 2013. Production was 17,000 barrels per day lower than the same period a year ago. Excluding production entitlement effects and the production impact associated with asset sales, production grew by 31,000 barrels per day between periods. Unconventional production increased in the Permian and the Vaca Muerta in Argentina by 40,000 barrels per day. Lower turnaround activity, mainly in Trinidad and Tobago, Kazakhstan, and the Gulf of Mexico, increased production by 19,000 barrels per day. Production entitlement effects decreased production by 28,000 barrels per day.
The decrease in crude oil prices between periods resulted in a small increase in net production volumes, primarily as a function of our production-sharing contracts in Indonesia. This increase was more than offset, however, by negative production entitlement effects in Kazakhstan, as well as lower cost recovery volumes due to changes in absolute spending levels. The sale of producing assets, mainly in Chad, reduced production by about 20,000 barrels per day. The base business and other bar principally reflects normal field declines with a partial offset from the absence of external constraints, which negatively impacted production in the third quarter of 2013. Our base business continues to perform well with a base decline rate of less than 3% per year. Turning to slide 11. U.S. downstream results increased $292 million between quarters.
Higher volumes increased earnings by $160 million, primarily reflecting the completion of planned turnaround activities at the El Segundo California refinery, where four new coke drums were installed. These new coke drums are expected to enhance the future reliability of the refinery. Despite declining industry refining margins on both the West Coast and Gulf Coast, our realized margins were $30 million higher. Overall, we benefited from more optimal sourcing of intermediates and other feedstocks following the completion of the El Segundo refinery's major turnaround in the prior quarter. In addition, we had improved reliability at both the Pascagoula, Mississippi, and Richmond, California refineries. Pascagoula's refinery contributed a full quarter of premium base oils production after the successful startup of its new premium base oils plant in July. This benefited both volumes and margins.
Lower operating expenses increased earnings by $110 million due to the absence of costs related to the shutdown in maintenance activities in the prior quarter. Higher gains on midstream asset sales, mainly the sale of a terminal in Beaumont, Texas, improved earnings by $115 million between periods. Lower Chemicals results along with various smaller items decreased earnings by $123 million. Chemicals earnings were affected by various impairments in addition to the Port Arthur, Texas facility being offline since early third quarter. Turning to slide 12. International Downstream earnings increased $374 million between quarters. Stronger margins increased earnings by $145 million. Falling crude prices contributed to improved refining margins across multiple refineries, in addition to the completion of planned turnarounds at our Thailand and South Korea affiliate refineries. Asia marketing margins benefited from favorable aviation price lag effects and improved retail margins.
Timing effects represented a $70 million positive earnings variance between quarters, largely due to the revaluation of inventory associated with falling crude and product prices during the third quarter. Foreign exchange gains were $105 million higher compared to the prior quarter. The third quarter had a gain of about $20 million compared to a loss of about $85 million in the second quarter. The other bar includes a number of unrelated items, mainly higher trading results. Jeff will now provide an update on our North America Upstream operations.
Thank you, Jeff. It's a pleasure to be on the call with you all today. I'll provide a brief overview of our North America Upstream operations, followed by more detailed reviews of two key areas for us, the Gulf of Mexico Deepwater and our unconventional activities, particularly those in the Permian Basin. The photo on slide 13 shows the Jack/St. Malo facility safely moored on location in the Deepwater Gulf of Mexico. We continue to make steady progress towards first oil later this year. Let's turn to slide 14. Let me start by providing a brief overview of Chevron's North America Exploration and Production Company. We're a diverse organization made up of six business units. We're active in the key hydrocarbon basins across the continent. Production has averaged 731,000 barrels of oil equivalent per day year to date 2014.
This represents almost 30% of Chevron's total Upstream volumes. The heart of our portfolio is our legacy base business, which has generated production value creation for decades. Assets include our Gulf of Mexico shelf, mid-continent conventional oil and gas operations in the San Joaquin Valley in California, where our industry-leading expertise in steam flood operations has helped us achieve more than 60% recovery at the Kern River Oil Field. These robust base business assets provide a low decline, high cash generation foundation to underpin and support our current and future growth opportunities. Next, I'd like to highlight two of these areas in more detail, Deepwater Gulf of Mexico and our shale and tight assets. Slide 15. Chevron has a leading position in the Gulf of Mexico.
We're the largest leaseholder, currently produce about 200,000 barrels a day in the Gulf, slightly more than half of which comes from our existing deepwater assets. In the deepwater, we are making good progress on our major capital projects. Tubular Bells' first oil is imminent in the next few days. The remaining work on Jack/St. Malo is progressing well, and the project remains on track for a late fourth quarter startup. Overall hookup and commissioning is about 90% complete. Flowback gas was brought on board the facility last weekend. We recently completed deepwater and oil export pipeline. Both of these are significant milestones. Construction of the Bigfoot tension leg platform is essentially complete and is ready for sail away and offshore installation. The central Gulf of Mexico has currently experienced a significant loop current event.
These strong currents at the ocean surface are naturally occurring, typically last one to three months. This loop current is particularly strong, and we are monitoring for the conditions that will allow us to proceed with installation once the loop current subsides. We're taking advantage of the extra time in the construction yard to start some pre-commissioning activities normally done offshore. Investment decision was announced on the Stampede project earlier this week. On the exploration front, we recently announced a significant lower tertiary discovery at the Guadalupe prospect in Northern Keathley Canyon. We have also completed appraisal work at the Buckskin and Moccasin prospects and expect to move into front-end engineering and design in 2015.
We've got five deepwater drill ships operating in the Gulf, two of which are focused on exploration activities, where we plan to drill four to six impact prospects over the next 12-18 months. Let's talk about shale and tight activities. Slide 16. In the Permian Basin, Chevron has been active since the '20s. We continue to be a leading producer in the basin. We have an enviable acreage position. We have good exposure to the key sweet spots in the basin. Our legacy position provides critical access to infrastructure. We are employing a disciplined, value-focused development strategy in the Permian. We are not in a drill or drop situation, and our low lease holding costs allow us to focus on the highest return projects in a paced manner while leveraging industry learnings.
Our efforts on lowering costs while simultaneously increasing production rates and ultimate recoveries are helping to improve overall well and program economics. We've executed joint development agreements which help optimize well placement and lateral lengths, as well ensure the efficient build-out of takeaway and other infrastructure. Already high level of activities in the basin continued to increase in the efficiency programs to lower costs, increase EUR working. We're anticipating that our 2014 unconventional production will be more than 10% higher than initially forecast, and our long-term unconventional production growth continues to steepen, as shown in the chart on the right. We'll provide an updated production forecast at our Analyst Day in March. Slide 17.
Looking into the Midland Basin, production has increased by 15,000 barrels of oil equivalent per day or 40% during the first nine months of the year. We are on track to drill 10% more wells than originally planned for the year. As we mentioned during the second quarter call, we are transitioning towards a multi-well pad-based horizontal program. The Midland vertical wells have demonstrated that all of the identified benches are potentially productive. Our Bradford Ranch program on the southwestern edge of the basin is a great example of our transition to horizontals. We've drilled our first two wells. We're now batch drilling the next four. The first well has been completed, is Flowback, and will be on production next month. At its full potential, we expect up to 150 wells in this development, with lateral lengths ranging from 5,000 feet-7,500 feet.
We believe that we are well-positioned in what looks like the sweet spot of the Midland Basin horizontal play. Slide 18. Results in the Delaware Basin have been equally positive. Our two non-operated joint development areas in Culberson and Eddy Counties continue to deliver excellent results. Production has increased by approximately 20,000 barrels of oil equivalent per day or 60% during the first nine months of the year. We are planned to drill 180 wells in 2014. Our company-operated Toledo Draw horizontal program in Lea County, New Mexico, remains on track to spud its first well within the next month. While there are multiple benches in this area, we are targeting the Upper Avalon with this initial 16-well development. With success, we envision more than 60 well locations at Toledo Draw. Our recent well results give us continued optimism on the growth potential in the Delaware.
Wells drilled in the third quarter have 30-day IPs that average just over 1,000 barrels of oil equivalent per day. I'd like to close by providing an update on some of our other key North America shale and tight assets. Let's turn to slide 19. Starting with the Duvernay in Canada, we recently announced the sell-down of 30% of our Duvernay position to Kuwait Foreign Petroleum Exploration Company, consistent with our risk management practices for early life assets. They are a valued partner in our Wheatstone project. We welcome them to this exciting development. The consideration received reflects the prospectivity and inherent value of our attractive acreage position, 90% of which is in the liquids-rich window. Appraisal drilling has commenced on our first two horizontal well pads located in what we call the central focus area.
In the Utica and Marcellus, we have prioritized our near-term efforts into five core development areas across West Virginia and southwestern Pennsylvania. As we move more aggressively into the development mode, pad drilling, optimization of lateral lengths and completions, and the build-out of water infrastructure allow us to further lower costs, increase recoveries, and therefore enhance overall development economics. Let me turn it back over to Pat.
Okay. Thank you, Jeff. In addition to the significant amount of activity going on in our North America upstream business, I'd also like to touch on a few other highlights during the quarter. In Australia, we continue to make good progress on both the Gorgon and the Wheatstone LNG projects. For Gorgon, which is now 87% complete, all of the development wells have been successfully drilled, and a majority are through the completions phase. LNG tank number 1 is through construction and testing, awaiting product, and LNG tank number 2 is on plan to achieve that same status by the end of January. The five turbine generators are all installed, and the jetty is essentially complete. 11 of 17 train 2 modules have been received and installed. The key focus in the months ahead remains in the mechanical, electrical, and instrumentation work scopes on the island.
The Wheatstone project is now 49% complete. The project team met a major milestone back in August with the installation of the offshore steel gravity-based structure. The MOF, or materials offloading facility, is 100% operational. The upstream drilling campaign, the fabrication of the platform, site preparation, and construction of the LNG tanks are all on schedule. We are making good progress bringing these projects online, both of which will be important contributors to production, cash flow, and earnings for decades to come. I encourage you to review the new pictures that show progress on both projects on our investor page at chevron.com. In Bangladesh, we achieved startup at the Bibiyana expansion project, which includes two new processing trains with an incremental design capacity of 300 million cubic feet of natural gas and 4,000 barrels of condensate per day.
Moving to the downstream, we have completed investments at several of our U.S. refineries, including El Segundo, Pascagoula, and Salt Lake City. We expect these investments will lead to notable reliability and operational improvements going forward, some of which were evident in the third quarter's results. Our Chevron Phillips Chemical joint venture also continues to make good progress on its U.S. Gulf Coast petrochemicals project. Construction of the 1.5 million metric ton ethane cracker and the two 500,000 metric ton polyethylene units is almost 25% complete. It is on schedule and on budget. Finally, we continue to sell non-strategic assets. We're on target for achieving $10 billion in asset sale proceeds from 2014 through 2016, a goal we outlined at our Analyst Day meeting last March.
At nine months, year-to-date proceeds amount to $2.6 billion, there are several other transactions lined up to close in the fourth quarter or early in the new year. I'd like to close with a couple of thoughts about Chevron's position and outlook given recent commodity price declines. Our priorities haven't changed. By necessity, we take a long-term view of prices because our investments last for decades. We continue to believe global demand for oil and natural gas will grow while existing sources of supply will inevitably decline. As it has always done, although with some lags, we expect the industry cost structure will align to the revenue stream such that economic incentives will exist to invest in developing new energy supplies. Our strategies have remained, and will remain, constant. They are designed for long-term value creation. Our financial priorities haven't changed. They start with growing an attractive dividend.
Next, we look to invest in economic projects that create value and allow us to sustain and grow the dividend for years to come. Third, we want to maintain a strong balance sheet, precisely for times like this. Finally, any available cash is distributed to our shareholders through our share repurchase program. Our program is scalable and could be adjusted in a period of low prices. We'll continue to make that assessment each quarter, and our future actions will obviously be influenced by how low prices stay and for how long. We remain focused on excellent execution each day and every day. Our businesses are performing well. Based on preliminary information, it appears our upstream and our downstream segments were number one in earnings per barrel for the quarter. Of course, we are cognizant of near-term price realities.
Major capital projects under construction and other non-discretionary spend represents about one half of our current capital budget. Even at low prices, we plan to continue funding these projects. Key among these are Gorgon, Wheatstone, and our two operated deepwater projects. Within a year, we expect to see production from three of these four projects online, and they'll turn from being cash consumers into cash generators. After that, we prioritize and rank our remaining investments that are more discretionary in nature, only funding those that are most competitive in the portfolio or where deferral can be achieved without economic loss. Permian development, for example, remains quite attractive even at lower prices. This ranking and prioritization is not a new process for us. It's a routine process for us. We're also keenly focused on managing operating costs.
This, too, is not a new area of effort for us since oil prices have been drifting south for the past few years while costs have continued to rise. As we showed you last March, our costs are already highly competitive with our larger peers, as well as a much broader set of E&P companies. Well before the recent price decline, several of our international and domestic business units, as well as our corporate departments, already had notable cost reduction efforts underway. Finally, we plan to continue, but we will be careful about managing our ongoing asset divestment and portfolio rationalization efforts. The valuations for some assets targeted for sale are not likely to be affected by near-term circumstances. The valuations for other prospective sale assets may be. In all cases, we will only sell if we can capture good value.
By the end of 2014, we should be well on our way to our $10 billion asset divestment target. We still have confidence in achieving it between now and the end of 2016. We have a great deal of experience in managing through prior price cycles in both our upstream and our downstream businesses, and we feel confident in our ability to allocate capital appropriately and to sustain a competitive cost structure, even in a lower commodity price world. That concludes our prepared remarks. I appreciate you listening in this morning. We're ready to take some questions. Keep in mind that we do have a full queue, so please try to limit yourself to one question and one follow-up if that's absolutely necessary, and we'll do our very best to get all the 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 at this time, please press star then one. Our first question comes from the line of Douglas Leggate from Bank of America Merrill Lynch. Your question, please.
Hi, good morning. It's actually Jason Smith on for Doug. How are you?
Oh, hi, Jason. How are you?
Good. Pat, I think in your comments around some of the projects you'd look to move forward with in the future, one of the ones you didn't mention is the Tengiz expansion, and there's obviously been some chatter around cost and timing there. Can you maybe just offer some color on your latest thoughts on whether this moves forward?
This is a very attractive asset for us. It's one of the critical assets that we've got in the company. Strong earnings, strong cash flow, and it has the potential, we think, to grow even further. There are two prospective elements of that project that I think are important to separate out. One is the wellhead pressure management project. It's really designed to keep existing processing capacity full. The second is a project for the growth that really could add 250,000 to 300,000 barrels a day, taking full field growth production up to around 1 million barrels a day. It's a very exciting project. We are working very aggressively with our partners and with the Kazakhstan government to progress this project through to final investment decision. We have not made a final investment decision at this point in time. We don't have a cost estimate.
Our teams are working very hard to conclude the final engineering, understand the full suite of the economic impacts here, get complete alignment between our partners and the government, and proceed that forward. When we do take FID, we'll have a number that we can put forward.
Got it. Okay. We appreciate all the thoughts on buybacks and dividends going forward. In the current oil price environment, at least at present, it looks like cash flow is not covering CapEx dividends and buybacks for the first nine months of the year. If we do end up in a depressed environment, can you just talk through what changes there?
I think, Jason, it's really going to depend on the outlook that we've got on a whole series of parameters. Oil price is one. Cost structure is another. Length of duration of any sort of dip or price excursion, how quickly we see the cost structure amending to that. Our capital program, balance sheet health issues, et cetera. All of that gets taken into account when we look at our allocation of cash uses. The priority, as I've said before, and we've been longstanding in saying this, is really about being able to grow our dividends. In order to do that over a long period of time, we need to continue to make very strong investments or investments in strong projects, attractive projects. We've got a tremendous queue, and we have the opportunity to do that.
We're going to be driven by the economics of the portfolio that we have at hand. We're very cognizant of the risk in our business, the commodity price cycle risk, and we've longstanding kept a pristine balance sheet to weather through positions just like this. We have a lot of borrowing capacity still ahead of us without putting into jeopardy our double A status. We are on the cusp of getting to a point where these major capital projects kick in with significant volumes and significant cash generation. We feel very comfortable about the position that we're in, and we're not bothered in a temporary sense of having to fund our shareholder distributions off of our balance sheet. We obviously can't do that for a long period of time, but that is not the window that we find ourselves in.
Thank you. Our next question comes from the line of Jason Gabelman from Jefferies. Your question, please.
Thanks very much. My question's on the Permian. Jeff, I was hoping that you might be able to at least qualitatively explain why you're seeing such a significant increase in the production levels. I guess if you could just break it out between moving to longer laterals, the intensity of propping in your completions, or even just higher activity levels or maybe just something else I'm not thinking about.
Thanks for the question, Jason. It's really all of the above. Maybe start back with a year ago, a lot of our activity was focused on appraisal, and we had some lease tenure work to do up in the Delaware with the Chesapeake acquisition. Most of that work is done. That's helped us identify the sweet spots that we want to be in. As you know, the industry is innovating every single day on completions and design. We're adopting those designs, applying those to our business. Lateral lengths are increasing. Stages in those lateral lengths are increasing. Proppant amounts are increasing. All of that is driving not only our performance per well, but the entire industry's performance per well in an upward direction.
Finally, on top of that, our activity in general with more development programs has increased year-over-year, and that's driving the production growth.
Right. I really did have a true follow-up on this one. I think you said that the 30-day IP in the Delaware Basin was just over 1,000 barrels a day. You may have said it, but I missed it. Do you have a similar figure for the Midland Basin?
No, I don't. It's a much wider distribution over there. We'll talk maybe a little bit more about that at our Analyst Day meeting.
Okay, thanks.
Yep.
Thank you. Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question, please. Ryan, you might have your phone on mute. Ryan, we're still not hearing you.
Maybe we'll try to queue him up again. Let's move on to the next caller, Jonathan.
Certainly. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question, please.
Hi, Pat. Can you hear me?
I can hear you. Thanks, Paul.
Jolly good. Good morning. Pat, you guided at the analyst meeting to flat CapEx going forward. Today, you seem to be saying that you may cut it. I'm not quite sure what the message is. I guess if we were to stay at current prices, we would anticipate lower CapEx in the future. You seem to be saying. Well, I'm not even sure in what areas you would lower CapEx. Thanks.
Yeah. What I was trying to say is, we're just in the middle of doing our business plans at the very moment. You know our process. We go through that this time of year. We get approval of the board. Then we come out with our capital expenditure outlook for the year. We expect to do that. That typically would have happened in December. We're right in the midst of pulling all the plans together. Obviously, we're having to have some tough discussions around what do we think the price outlook is going to be? What do we think the cost structure is going to be? How much of our capital program is really in this non-discretionary must get through the phases since these projects are already under construction versus how much is discretionary?
I tried in the prepared remarks to walk you through that logic. Now, in the discretionary category, there are areas like exploration. Exploration would be one of the first areas that you would look to perhaps trim back in a cash flow constrained sort of mode. There are other areas that we would look to, projects that are not under construction, but are in the first few phases of development. These would be projects where a deferral really doesn't result in an economic loss or value destruction. Those are the first couple of areas that we would necessarily look. I'd call to your attention that there have been some projects where we have already done a pushback on the FID for various reasons. For example, Rosebank was one of the areas that we deferred on the final investment decision.
We basically took a look at that again and said, "Let's reassess the design construct. Let's reassess the economics here." Frankly, that's turning out quite well from a design concept standpoint as well as a reserve standpoint. That effort looks to be coming forward perhaps sometime in 2015. You're probably aware, we've also had a delay in the Indonesian Deepwater project because we weren't able to get the government approvals in the timeframe that allowed the bids that we had received and the marketing effort that had been done to remain effective. We're going to have to go through that cycle again. There have been some projects that have moved out of the current year period for their own sort of operating reasons.
Great. The follow-up would be, would we assume that your volume target for 2017 is regardless and viable, or would you see the potential for that to need to be cut as a result of low prices? Thanks.
Yeah. Paul, I guess the other thing I tried to mention is that we take a long-term view on prices, because we think over time that's the direction. The world's still going to need our product, and costs are going to rise to get access to more challenged resources. We still are on plan for the 3.1 million barrel a day production by 2017. We have a vast majority of that volume is already under construction, and we can see our way to those barrels. You'll recall perhaps that when we did put out that target back in March, we also indicated that there was about a 50,000 barrel a day cushion that we put in for the unknown and the unknowable. That is an opportunity there should some of these things move in or out of the portfolio.
Some things are going to move out, some things are moving in. Jeff already talked about the strength in the Permian that we've got. All in, our best view of the world right now is that 3.1 million barrel a day target is a good target for us.
Thank you, Pat.
The other thing I would say maybe, is that when we're putting our plans together and when we're actually taking our projects to investment, we obviously test our investments against a mid-price scenario, but a low price scenario as well as a high price scenario. I would just say that the low price scenario that we use, current prices are within that band.
Great. Just if I could, the credit rating is all important, isn't it? That's an important way to think about how much you would borrow.
Yes, it is. Credit rating is important, we are a long way from compromising our double A status, and we want to keep the double A status for exactly times like this when prices fall and we're committed on projects.
Thanks. I'll let you move on. Thank you.
Thanks, Paul.
Thank you. Our next question comes from the line of Phil Gresh from J.P. Morgan. Your question, please.
Hi, Pat. Good morning.
Good morning.
Just to follow up on Paul's question, you talked about some of the areas of flexibility. Appreciate the color there. Specifically for 2015, you talked about the major capital projects. You talked about the Permian still being attractive, et cetera. I guess I was just wondering, ballpark, is there a rough amount or range you could give us in terms of your CapEx flexibility for next year? Is it 10%? Just any preliminary thoughts you could give us?
Phil, I don't really want to go down that pathway because, again, we're putting our budgets together right now. I mean, the areas that we would look to flex, exploration, it's currently been 3. That would probably come off some. These phases 1 through 3 project developments, that will take some declines, again, if we see these price levels holding. Base business and Permian activity, those are obviously very economic plays at this particular point, but you could toggle those, and you can toggle those without destroying value. It would mean delaying value, but you wouldn't be destroying value. Those are all of the kinds of decisions that we're working through at the very moment, and I don't want to get ahead of our formal plan.
Understood. I appreciate the additional color. My follow-up would be, if we think about the levers available between the CapEx, incremental asset sales, the buybacks, I guess, is it fair to say with your leverage where it is that maybe something on the CapEx and something on the asset sales would be more of a priority at this point or a rank order relative to trimming the buybacks?
Yeah, again, I don't want to get ahead on that. I think all of those avenues are open to us, and it's really going to be a question of how we settle out on our medium to longer term view on prices and costs, and it's also going to be a function of the economic cue that we've got. We will take all of those parameters in place. I'll just reemphasize that we have a fair amount of leverage, a lot of leverage still available to us. That will be taken into account as well.
Okay. Thank you.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question, please.
Hi. Good morning, guys. Jeff, I have, if I could, two questions. One on Duvernay. Can you share with us the rationale behind the farm down, is it because you think within your portfolio that this is not ranking as well, or that it is a financial consideration, you just need the money so that you can accelerate the growth or the development pace there? Secondly, can you talk about from the Aneth acquisition that you also get the Utica acreage there. Relative to the Chevron portfolio, how you rank those land position? Is it even have any meaningful outlook or that future within your portfolio on those? Thank you.
Okay. Two good questions, Paul. On the Duvernay in Canada, we are very excited about that. It's less mature than the Permian, but the rocks that we've seen out there and the performance that we've seen on our exploration program are good. Chevron has been very clear about our position on risk management. We had 100% interest in more than 300,000 acres up there. Typically, we look to farm that down a bit. This helps us manage risks. It helps us manage across our whole portfolio. The sell down, in that particular venture, was really a part of our normal risk management process. With respect to the Utica, Southwestern Pennsylvania, these are very attractive prospects. Recall four years ago, three years ago, when we bought into this thing, it was primarily dry gas, and that was what was driving the business.
Obviously, that part of our portfolio, we have a low holding cost, and we pulled back from that with respect to investments. On the liquids-rich gas side and on the deeper Utica plays, we're very excited about those. Again, we're seeing the same efficiencies in the drilling and completions up there as we see everywhere else. It's competing for our capital, and it's important in our portfolio.
Can I just add a quick follow-up? Do you have any rig drilling in the Utica?
Yeah, we've got one rig up there.
Thank you.
Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley. Your question, please.
Hey. Good morning, everybody, and welcome, Jeff. I'll leave CapEx alone, a modest silver lining on the lower oil price is a positive PSE effect. Can you provide any sequential impact in Q3 and maybe just talk through what the typical timing or lag effect may be there?
I can take that one, Evan. This is Jeff Gustavson.
Hi, Jeff.
We did see a net production increase in the quarter, but remember, prices dropped late in the quarter. I think you see more of that in the fourth quarter, assuming prices stay at the levels that they're at now. We redo our PSE sensitivity each and every year as part of our planning process. Right now, at these price levels, what we're showing is about a 1,500 barrel a day impact per dollar change in Brent prices. That's the sensitivity you should be using going forward. I would note that this quarter, and we mentioned this in the text, we did have a couple of maybe one-off effects. Profit oil split change, like contractor versus government in Kazakhstan. That's with Karachaganak. That was a little more of a pronounced impact.
Plus, there was some variable royalty effects with our Tengizchevroil affiliate. Going forward, 1.5 thousand barrels a day per dollar change is the sensitivity you should be using.
Great. I appreciate that. Maybe a question for the other Jeff. On the Permian, you mentioned in your comments that it ranks highly. I presume it'd be more insulated from any potential CapEx reduction, if that's correct. You clearly have a very large position in both basins. I didn't know if you could quantify how much of your net acreage was prospective Wolfcamp, Bone Spring, or even Lower Spraberry in Midland. If you had, if you could share that with us.
Yeah. Well, just to confirm really what Pat said, the Permian does rank at the high end of our investment portfolio, and it should be good at the current price environment. It is good at the current price environment that we see. With respect to quantifying the acreage position, I think that's in the eye of the beholder. We have a large acreage position. It's across all the different benches. Every day, there's a new bench that looks productive out there. What I can tell you is that the areas that we're focused on our development activity are the sweet spots as we in the industry define those things today, and they're highly prospective. They're highly sought out after. We start looking at the outer edges of that basin. Other people are out there. They're trying new technologies. They're testing those benches.
I think what we're trying to do is not get out ahead of our skis on that and follow a bit the appraisal work and the delineation of these things that are going on. We're going to stay in highly prospective areas as we pace our development program.
Is that what drives your location estimates then, or is that all-encompassing?
Well, the total location estimates is what we see across the basin with sort of the current and some advancement of the technologies that exist. Certainly three years ago, we wouldn't have seen this kind of potential. Three years from now, it could be even better.
Yeah. It's trending that way. Thank you .
Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please?
Good morning.
Go ahead. Yeah.
I guess some of the discussion around CapEx, apart from oil prices, comes from the slide at the Analyst Day this year, where obviously you demonstrated the cash flow was going to come on from the major projects, from the work that Mike Wirth has been doing in the downstream, and then obviously the shale contribution. CapEx was going to stay relatively high to drive growth, I guess, beyond and into 2020. The shade I see is sort of $37 billion-$40 billion, which is, I guess, more similar to this year. I'm trying to get a sense of what projects you were including in that sort of 2017 timeframe. You've mentioned Kitimat, IDD, Tengiz. How much of a contribution was there in that year, if you can share that with us so we can get a sense of where the adjusted CapEx might be?
I'm not sure that I completely understand the question. You're looking at 2017-
I'm looking at how much of Kitimat and IDD and Tengiz you were assuming in that sort of 2017 outlook that you gave us so that we can, if they do delay, not at Tengiz but Kitimat and IDD perhaps, how much you would save.
Yeah. I think for all of those, you would be talking about modest contribution in the 2017 time period.
Right.
Yeah. I don't think it's an impactful element in terms of hitting that target.
Right. On the CapEx side.
Oh, no, I was talking on the production side. I'm sorry. You're talking on the CapEx side.
Yeah.
We didn't give a 2017 target. We did show you that slide that had cash from operations growing and C&E being more contained relative to cash from operations. We still stand by that overall profile. It is our distinct intent to widen out our free cash flow over time once we get into the cash generation phase of these critical projects. We've been in this very unusual capital-intensive phase with Gorgon and Wheatstone and these large projects right on the heels of one another. We're coming off of that. LNG spending this year is going to probably be the peak LNG spending, $10 billion-$11 billion. It will trail off in 2015. It will trail off again in 2016. We don't have that kind of sequential large projects queued up beyond that time period.
We'll come out with a revised target on future year C&E as best we can in March at the Analyst Day meeting.
Okay, one for Jeff. The 20% CAGR, if I calculated that right in the Permian, is obviously quite impressive for any independent or major. What are the constraints? I mean, the resource is clearly there. What are the constraints on perhaps even going faster, perhaps as you get out into the second half of the decade in the Permian?
Okay. Yeah. Well, I think that the basin itself, if you look back the last three years, it's certainly capable of demonstrating that growth potential. I think we're up half a million. We're almost 3 million barrels a day as an industry in that basin. The constraints are what everybody talks about. It's just basic stuff like the labor force out there. That's been challenged. It's a boom time out there. Water is an area of concern for some people. We work hard on that in terms of moving from freshwater to brackish non-potable drinking water, securing those supplies and the infrastructure around that. Sand has been an issue, but I think the service companies and others are starting to address that supply chain issue. I think the real uncertainty for me is just how high that activity could go and what would be the knock-on effects of that.
You've got to look at, there's a lot of companies in there, and the current price environment, maybe some of that stabilizes out. I don't see the activity levels that we see being at risk from takeaway capacity or really the contractor's ability to deliver. That's one thing that we take into consideration when we look at our pace of investment.
Thank you.
Thank you. Our next question comes from the line of Asit Sen from Cowen and Company. Your question, please.
Thanks. Good morning. Two quick ones here. First, could you update us on Kitimat potential timing of FID? Looks like at least one competing project is getting delayed. Secondly, could you update us on any labor productivity items on the west coast of Australia in light of recent union agreement on Curtis Island? In other words, are things getting better?
I could give a quick update on Kitimat. I'll let Pat talk about Australia. Apache has announced their intent to fully exit the project. We're still committed to this project. We think that the low cost, potentially prolific reserves up in the Liard and Horn River are going to make an attractive LNG project in time. We've been very clear that we will not take FID of this project until we have gas contracts signed and know that we've got a value-adding economic project. With respect to FID, we haven't given a date on that, and we continue to do the FEED work on the plant site. We continue to work with the government of British Columbia. We're encouraged by the recent news that's come out of there with respect to how they want to treat LNG in taxes.
Our primary focus up there is really the appraisal and the delineation work that we've got going on in Liard Basin.
Okay. With regard to the union contract issue in Australia, at this point in time, we know that there's been a downstream agreement reached in principle with the certain construction unions, and that it still needs to be put to a vote by the union membership. We have agreement at the leadership level, but we still need a vote at the union member level. Frankly, there's more dialogue in the press about union-related challenges for us on this project than there have been reality on the ground. The project continues to make good progress here. I guess one of the exciting things that I would just mention, we didn't put it in the formal remarks, but we have secured, I guess, I'll call it a flotel. I'm not sure what the right hoteling accommodation nomenclature is.
We've got the capacity over the next several weeks to bring over time, about 1,200 additional workers to the island to work on the MEI work that's underway, that needs to be done in the next year. That's a good boost, we think, in productivity for that.
Thanks a lot.
Thank you. Our next question comes from the line of Iain Reid from BMO. Your question, please.
Hi there. Pat, I wonder if you could give me an update on the Wheatstone budget. I think you're about 49% through now in terms of spend. Is it time now that we get a complete update in terms of how much that project's going to cost?
Right. I mean, at this point, yes, you're right. We're about 49% complete. It is a typical process for us to go through and do a mid-project update. I don't have a specific calendar date for that, but it would be a reasonable thing that we would do anytime between 40% and 60% of when the project is done. I would say that's coming, but I don't have a specific date as to when that will be completed.
Okay. Maybe as a follow-up on another big international asset, Angola LNG. Can you give us a cost to repair and some schedule for restart up of that project?
Sure. I can talk a little bit about the schedule side of things, but there's not a cost estimate that I have available to give to you. Let me just make sure. We are just a 36% partner in a consortium here. We are not a controlling entity. We work through the partnership there. In terms of the progress on the repair work, we're continuing to make good progress there. We do, at this point, anticipate an initial restart somewhere around the middle of 2015. After initial performance testing, as is typical, that plant will go down for a couple of month period of time while we clean out and remove the strainers, clean out the filters, et cetera. It will be brought back online, and we anticipate restarting and working towards sustained production levels late in 2015.
Did that answer your question?
Yeah, no, it did. Thank you.
Okay. Thank you. All right. I guess we'll take the next caller.
Our next question comes from the line of Allen Good from Morningstar. Your question, please.
Good morning, everyone. A couple on the Permian. First of all, when you look around and you benchmark yourself against maybe some of your smaller peers there on operating cost and other efficiency metrics, how do you see yourself stacking up? Secondly, have you been able to achieve some capital efficiency improvements from your initial projections that suggest that spending won't quite increase as much as the production is?
Yeah, good questions. We benchmark ourselves all the time. We benchmark ourselves with respect to cost efficiency or finding the development costs, et cetera. A year and a half ago, we were probably down at the lower end of our competition. Part of that was because we were new in the basin, and part of that was because we were focused on the appraisal and some of the other work to really understand what's going on in the basin in these new areas. We've made a concentrated effort in that area over the last 14-16 months. We've made significant improvements in our execution efficiency, our cost efficiency. Today I would say we're probably in the mid to upper part of the second quartile. Our performance targets here to be the top of the heap there, and we're making very good progress on getting there.
With respect to how we're improving and what's going on there, it's really a host of things. Certainly, we are seeing capital efficiency in what we're doing, so we're being able to drill more wells with the same amount of money. We're seeing efficiencies in our completions. I think even more important to that, moving to horizontal wells, moving to longer lateral lengths, moving to more stages, our acreage position allows us to do that, and we're going to see more of an impact on that in our production forecast than probably anything else.
Okay, great. Thanks. Just one quick follow-up. Was the Duvernay sell down, was that included in the original $10 billion estimate of asset sales? Is there any potential upside for that figure over the next couple years?
Yeah. We wouldn't really talk to what's included or excluded in our overall target. Obviously, it's a significant component there. In terms of future, I think your second question was is there future efforts in that regard? I think that's.
I'm sorry. Is there upside to that $10 billion figure now that you've gone through it a little bit and progressed through? Do you see upside from your initial estimate?
I think that's going to be a function of what the market is going to allow. We have certain assets that, and as we've tried to describe, that are either early in life or late in life. We know what those assets are, and we will, as I said, only go for the sales when we can get good value. It will be a function of what the market will afford at that point in time. We are on track for the $10 billion. We can see our way to that almost at this point in time. Certainly this year, 2014, or maybe there will be some slippage into first quarter 2015 of some of the transactions that I have line of sight on, but I feel very good about where we sit at this point in time.
Great. Thank you.
Thank you. Our final question comes from the line of Pavel Molchanov from Raymond James. Your question, please.
Thanks for taking the question. Two quick ones on LNG. First, in relation to Kitimat. With the tax announcement from the B.C. government earlier this month, is that still a hurdle, or are you pretty satisfied with how that went?
Well, that's just one element of our investment decision. I think that what we're satisfied with is that the British Columbia government is very attentive to the realities of the industry. They've listened to what we've said. They've listened to what the buyers have said, and I think they've made some very good moves in terms of what reality is out there and what it takes to make these projects economic. We've got to work a whole lot of other issues between now and FID, and I think our view is that they'll continue to remain flexible in those discussions.
Okay. You mentioned you want to sign offtakes for Kitimat before FID, but you also have some remaining capacity at Gorgon, which as I understand, is still not covered by offtake. Are you prioritizing one versus the other if a particular customer is open to either option?
Well, I think a fundamental driver there is that the volumes would be available under different time frames. Gorgon production starts one year from now and ramps up with three trains over subsequent years. Kitimat was going to be in a much longer term horizon there. Just speaking to the Gorgon unallocated volumes or uncontracted volumes at this point in time, yes, we are sitting at about 65%. We did have notionally some of that volume earmarked as a backstop behind IDD from a customer arrangement standpoint. Now that the Indonesian deep water is no longer going forward on that same development time plan, we are available to take some of those volumes that we had earmarked there and market them, and that's exactly what we're doing now.
Okay. That's useful. Appreciate it.
Okay. I think that ends our queue at this particular point in time. I'd like to thank everybody on the call for your interest in Chevron and your participation with questions. We wish you a good day. Thank you.
Ladies and gentlemen, this concludes Chevron's third quarter 2014 earnings conference call. You may now disconnect.