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 a listen only mode. After the speakers' remarks, there will be a question and answer session and instructions will be given at that time.
As a reminder, this conference call is being recorded. I would now like to turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yerington. Please go ahead.
Hey, good morning and thank you, Jonathan. Welcome to Chevron's 3rd quarter earnings conference call and webcast. On the call with me today are Jeff Schellabarger, President, Chevron North America Exploration and Production and Jeff Gustafson, General Manager, Investor Relations. We'll refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward looking statements.
We ask that you review the cautionary statement shown here on slide 2. Turning to slide 3. The company's 3rd quarter earnings were $5,600,000,000 or 2.95 dollars per diluted share. On a year to date basis, earnings were $15,800,000,000 or $8.29 per diluted share. Included in this quarter's earnings were gains on asset sales of approximately $420,000,000 foreign exchange gains of $366,000,000 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 $770,000,000 There is a full reconciliation of these items on our last slide. Return on capital employed for the trailing 12 months was 12% and our debt ratio at the end of September was 14%. We repurchased $1,250,000,000 of our shares during the Q3. And in the Q4, we expect to repurchase the same amount.
Turning to Slide 4. Cash generated from operations was $8,700,000,000 during the 3rd quarter and $25,000,000,000 year to date. Cash capital expenditures were $8,300,000,000 for the quarter and 25 $700,000,000 year to date. Free cash flow for the quarter was $1,500,000,000 and year to date 1,900,000,000 dollars At quarter end, our cash and cash equivalents totaled $14,500,000,000 giving us a net debt position of 11,000,000,000 dollars Slide 5 compares current quarter earnings with the same period last year. 3rd quarter 2014 earnings were $643,000,000 higher than Q3 2013 results.
Foreign exchange movements positively affected earnings by $366,000,000 during the quarter, representing a swing of over $600,000,000 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 $443,000,000 between quarters. Lower realizations and liftings and higher operating and DD and A expenses were partially offset by favorable foreign exchange movements and lower exploration expenses. Downstream results increased by about $1,000,000,000 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 Q3 impairment of a Power related equity affiliate. Turning to Slide 6, I'll now compare results for the Q3 of 2014 with the Q2 of 2014. 3rd quarter earnings were approximately $70,000,000 lower than 2nd quarter results.
Again, the earnings variance between quarters reflected a $600,000,000 favorable movement in foreign exchange effects, most of which impacted the upstream segment. Upstream earnings decreased by $615,000,000 reflecting lower realization 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 $670,000,000 driven by stronger R and 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 Gustafson will now take us through the comparisons by segment.
Thanks, Pat. Turning to slide 7. Earnings for the Q3 were $125,000,000 lower than 2nd quarter's results. Lower realizations decreased earnings by $175,000,000 consistent with the decline in U. S.
Liquids and natural gas primarily associated with the Deepwater Gulf of Mexico increased earnings by $95,000,000 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 8. International upstream earnings were $490,000,000 lower than last quarter's results. Lower crude oil realizations decreased earnings by $420,000,000 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 95,000,000 dollars Gains on asset sales were $430,000,000 lower also driven by the sale of our interest in Chad and Cameroon, which occurred during the Q2. Favorable movements in foreign currency effects increased earnings by 490,000,000 dollars The 3rd quarter had a gain of about $340,000,000 compared to a loss of about $150,000,000 in the Q2. The other bar reflects a number of unrelated items including lower trading results and higher DD and A, partially offset by lower exploration expenses. Slide 9 summarizes the change in Chevron's worldwide net oil equivalent production between the Q3 2014 and the Q2 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 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 TCO's KTL facility in Kazakhstan in addition to Australia was completed in the second quarter, while third quarter planned turnarounds including TCO's SGI SGP facility, the U. K. And Thailand were on balance less expensive than the prior quarter.
The TCO 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 3,100,000 barrels of oil equivalent today. Slide 10 compares the change in Chevron's worldwide net oil equivalent production between the Q3 2014 and Q3 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 30 1,000 barrels per day between periods. Unconventional production increased in the Permian and the Vaca Muerta and 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 Q3 of 2013. Our base business continues to perform well with a base decline rate of less than 3% per year. Year.
Turning to slide 11. U. S. Downstream results increased $292,000,000 between quarters. Higher volumes increased earnings by $160,000,000 primarily reflecting the completion of planned turnaround activities at the El Segundo California refinery where 4 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 $30,000,000 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 oil plant in July.
This benefited both volumes and margins. Lower operating expenses increased earnings by $110,000,000 due to the absence of costs related to the shutdown and maintenance activities in the prior Higher gains on midstream asset sales mainly the sale of a terminal in Beaumont, Texas improved earnings by $115,000,000 between periods. Lower Chemicals results along with various smaller items decreased earnings by 123,000,000 dollars Chemicals earnings were affected by various impairments in addition to the Port Arthur, Texas facility being offline since early Q3. Turning to slide 12. International Downstream earnings increased $374,000,000 between quarters.
Stronger margins increased earnings by $145,000,000 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 $70,000,000 positive earnings variance between quarters, largely due to the revaluation of inventory associated with falling crude and product prices during the Q3. Foreign exchange gains were $105,000,000 higher compared to the prior quarter. The 3rd quarter had a $20,000,000 compared to a loss of about $85,000,000 in the 2nd 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 2 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 6 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. Asset includes our Gulf of Mexico Shelf, Mid Continent conventional oil and gas operations in the San Joaquin Valley steamflood operations has helped us achieve more than 60% recovery at the Kern River oilfield. 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 2 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 are 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're 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 Q4 start up. Overall hookup and commissioning is about 90% complete. Buyback gas was brought on board the facility last weekend. Recently completed dewatering the oil export pipeline.
Both of these are significant milestones. Construction of the Big Foot 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's surface are naturally occurring typically last 1 to 3 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. Finally, investment decision was announced on the project earlier this week. On the exploration front, we recently announced a significant lower tertiary discovery at the Guadalupe prospect in Northern Kiefly 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 5 deepwater drill ships operating in the Gulf, 2 of which are focused on exploration activities where we plan to drill 4 to 6 impact prospects over the next 12 to 18 months.
Next, let's talk about shale and tight activities, Slide 16. In the Permian Basin, Chevron has been active since the 2020s. 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 our low lease holding costs allow us to focus on the highest return projects in a paced manner while developing 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. Finally, 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 1st 9 months of the year and we are on track to drill 10% more wells than originally planned for the year. As we mentioned during the Q2 call, we are transitioning towards a multi well pad based horizontal program. The Midland vertical wells have demonstrated that all 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 flowing back 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 5000 Results in the Delaware Basin have been equally positive. Our 2 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 1st 9 months of the year and we are planning to drill 180 wells in 2014.
Our company operated Salado 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 its 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 Q3 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 a sell down of 30 percent 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 and 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 5 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 our 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 5 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 MAF 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 our investor page at chevron.com.
In Bangladesh, we achieved startup at the Biviana Expansion Project, which includes 2 new processing trains with an incremental design capacity of 300,000,000 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 3rd quarter's results.
Our Chevron Phillips Chemicals joint venture also continues to make good progress on its U. S. Gulf Coast petrochemicals project, Construction of the 1,500,000 metric ton ethane cracker and the 2 500,000 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 $10,000,000,000 in asset sale proceeds from 2014 through 2016, goal we outlined at our Analyst Day meeting last March. At 9 months, year to date proceeds amount to $2,600,000,000 and there are several other transactions lined up to close in the Q4 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. And 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. 3rd, we want to maintain a strong balance sheet precisely for times like this. And 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 1 in earnings per barrel for the quarter. Now of course, we are cognizant of near term price realities.
Major capital projects under construction and other non discretionary spend represents about 1 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 2 operated deepwater projects. Within a year, we expect to see production from 3 of these 4 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. Now 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 competitive with our larger peers as well as a much broader set of E and 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, but 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 $10,000,000,000 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. Now 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. So Jonathan, please open up the lines for questions.
Thank you.
Our first question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please.
Hi, good morning. It's actually Jason Smith on for Doug. How are you?
Hi, Jason. How are you?
Good. So 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 tank use expansion and there's obviously been some chatter around costs and timing there. Can you maybe just offer some color on your latest thoughts on whether this moves forward?
Yes. So I mean, obviously, 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 2 prospective elements of that project that I think are important to separate out. 1 is the wellhead pressure management project.
It's really designed to keep existing capacity processing capacity the We are working very aggressively with our partners and with the government 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. And then we appreciate all the thoughts on buybacks and dividends going forward. But in the current oil price environment, at least at present, it looks like cash flow is not covering CapEx dividends and buybacks for the 1st 9 months of the year. So if we do end up in a depressed environment, can you just talk through what changes there?
Yes. So 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 1, 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, etcetera. And 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 dividend.
But in order to do that over a long period of time, we need to make continue to make very strong investments or investments in strong project, attractive projects. We've got a tremendous queue and we have the opportunity to do that. So 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 long standing 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 AA status.
And we are on the cusp of getting to a point where these major capital projects kick in with significant volumes and significant cash generation. So 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 Gammel from Jefferies. Your question please.
Thanks very much. My question is 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. And I guess if you could break it out between moving to longer laterals, the intensity of proppant 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. So we're adopting those designs applying those to our business. So lateral lengths are increasing stages in those lateral lengths increasing, proppant amounts are increasing. All of that is driving not only our performance per well, but the entire industry's performance per general with more development programs has increased year over year and that's driving the production growth.
Great. And 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. I mean it's a much wider distribution over there. So we'll talk a little bit more about that at our Analyst Day meeting.
Okay. Thanks.
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.
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.
And you seem to be saying that would be well, I'm not even sure in what areas you would lower CapEx? Thanks.
Yes. So what I was trying to say is and we're just in the middle of doing our business plans at the very moment. And you know our process. We go through that this time of year. We get approval of the Board and then we come out with our capital expenditure outlook for the year.
And we expect to do that. That typically would have happened in December. So we're right in the midst of pulling all the plans together. And 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 nondiscretionary must get through the phases since these projects are already under construction versus how much is discretionary. And so I tried in the prepared remarks to kind of 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. I mean, these would be projects where a deferral really doesn't result in an economic loss or value destruction. So 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. So for example, Rosebank was one of the areas that we deferred on the final investment decision. We sent we basically took a look at that again and said, let's reassess the design construct, let's reassess the economics here. And frankly, that's turning out quite well from a design concept standpoint as well as a reserve standpoint. And that effort looks to be coming forward perhaps sometime in 2015.
We've also had 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 time frame that allowed the bids that we had received and the marketing efforts that have been done to remain effective. So we're going to have to go through that cycle again. So there have been some projects that have moved out of the current year period for their own sort of operating reasons.
Great. And then 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.
Yes. So we take 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 is 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 3,100,000 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. And so that is an opportunity there should some of these things move in or out of the portfolio. So 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. So all in, our best view of the world right now is that 3,100,000 barrel a day target is a good target for
us. Thank you, Pat.
The other thing I would say maybe is that we do when we're putting our plans together and 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. And I would just say that the low price scenario that we use, current prices are within that band.
Great. And then 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, but we are a long way from compromising our AA status. And we want to keep the AA 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 JPMorgan. 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 etcetera.
So I guess I was just wondering ballpark is there a rough amount of 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 we're 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, if 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. So 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. And my follow-up would be if we think about the levers available between the CapEx incremental asset sales, the buybacks, I mean, 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 rank order relative to trimming the buybacks?
Yes. 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 longer term 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. So 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. So 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 the if I could two questions. One on delivery. 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 that the development pace there?
And secondly, can you talk about from the Ennis acquisition that you also get the Unica acreage there. And relative to the Chevron portfolio, how you rank those NAND position? Is it even have any meaningful outlook on 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 a very attractive it's less mature than the Permian, but the rocks that we've seen out there and the performance that we've seen on 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. So 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 4 years ago, 3 years ago when we bought into this thing, it was primarily dry gas and not 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 place, 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.
Just can I just add a quick follow-up? Do you have any rig drilling in the Utica?
Yes. We've got one rig up there.
Thank you.
Thank you. Our next question comes from the line of Evan Kalia from Morgan Stanley. Your question please.
Hi. Good morning everybody and welcome Jeff. All the CapEx alone, but a modest silver lining on the lower oil prices, a positive PSC effect. I mean, can you provide any sequential impact in 3Q? And maybe just talk through what the typical timing or lag effect may be there?
So I can take that one. Evan, this is Jeff Gustafson.
Hi, Jeff.
So we didn't see the full we did see a net production increase in the quarter, but remember prices dropped kind of late in the quarter. So I think you see more of that in the Q4 assuming prices stay at the levels they're at now. We redo our PSC sensitivity each and every year as part of our planning process. And 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. So 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 Karachaginak. So that was a little more of a pronounced impact. Plus there were some variable royalty effects with our TCO affiliate. But going forward 1,500 barrels a day per dollar change is the sensitivity you should be using.
Great. I appreciate that. And maybe a question for the other Jeff. On the Permian, you mentioned in your comments that it ranks highly. So I presume it'd be more insulated from any potential CapEx reduction.
So that's correct. And then you clearly have a very large position in both basins. And I didn't know if you could quantify any how much of your net acreage was prospective, in Wolfcamp, Bone Springs or even Lower Spraberry in Midland, if you had, if you could share that with us?
Yes. 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 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 and 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. So 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. But 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 kind of all more 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, 3 years ago, we wouldn't have seen this kind of potential. 3 years from now, it could be even better.
Yes. 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. Can you hear me?
Hi, Ed. Yes.
Great. So 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 is worth has been doing in the downstream and then obviously the shale contribution. But CapEx was going to stay relatively high to drive growth I guess beyond and into 2020. And the shade I see is sort of €37,000,000,000 to €40,000,000,000 which is I guess more similar to this year. So I'm trying to get a sense of what projects you were including in that 2017 time frame.
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?
So I'm not sure that I completely understand the question. You're just you're looking at 20 17
And 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 tengiz, but Kitimat and IDD perhaps, how much you would save?
Yes. I think for all of those, you would be talking about modest contribution in the 2017 time period. Yes. So I don't think it's an impactful element in terms of hitting that target.
Right, on the CapEx side.
Well, no, I was talking on the production side, I'm sorry. So you're talking on the CapEx side. We didn't give a 2017 target. We did show you that slide that had cash from operations growing and C and 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, dollars 10,000,000,000 to $11,000,000,000 It will trail off in 2015. It will trail off again in 2016. And we don't have that kind of sequential large projects queued up beyond that time period.
So we'll come out with a revised target on future year C and E as best we can in March at the Analyst Day meeting.
Okay. And then one for Jeff. The 20% CAGR, if I calculate 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. Yes. Well, I think the basin itself, if you look back the last 3 years, it's certainly capable of demonstrating that growth potential. I think we're up 500,000. We're almost 3,000,000 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 fresh water to brackish non 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. But 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 contractors' ability to deliver.
And 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 kitty mat potential timing of FID? It looks like at least one competing project is getting delayed.
And 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?
Well, I could give a quick update on Kitimat. I'll let Pat talk about Australia. So 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 data on that and we continue to do the FEED work on the plant, 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 and taxes. But our primary focus up there is really the appraisal and the delineation work that we've got going on in the Liard Basin.
Okay. And with regard to the union contract issue in Australia, I mean, 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 to the by the union membership. So we have agreement at the leadership level, but we still need to vote at the union member level. Frankly, there is more dialogue in the press about challenges, union related challenges for us on this project than there have been reality on the ground. So the project continues to make good progress here.
And 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 floatel. I'm not sure what the right hoteling accommodation nomenclature is, but we've got the capacity over the next several weeks to bring over time about 1200 additional workers to the island to work on the MEI work that's underway that needs to be done in the next year. So that's a good boost we think in productivity for that.
Thanks a lot.
Thank you. Our next question comes from the line of Ian Reeve 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. And is it time now that we get a kind of a complete update in terms of how much that project is going to cost?
Right. I mean, at this point, yes, you're right. We're about 49% complete. We 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 percent 60% of when the project is done.
So I would say that's coming, but I don't have a specific date as to when that will be completed.
Okay. And maybe as a follow-up on another big international asset, Angola LNG. Can you give us a kind of 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 is not a cost estimate that I am available to 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.
But 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. And 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, etcetera. Then it will be brought back online and we anticipate restarting and working towards sustained production levels late in 2015.
Did that answer your question?
Yes, 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 Alan Guth 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? And then secondly, on the new projections for growth, would it be does that imply a commensurate step up in spending as well? Or have you been able to achieve capital efficiency improvements from your initial projections that suggest that spending won't quite increase as much as the production is?
Yes, good questions. We benchmark ourselves all the time. We benchmark ourselves with respect to cost efficiency or finding and development costs etcetera, etcetera. 1.5 years 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 months to 16 months. We've made significant improvements in our execution efficiency, our cost efficiency. And today, I would say we're probably in the mid to upper part of the 2nd quartile. Our performance targets here to be the top of the heap there and we're making very, very good progress on getting there. With respect to how we're improving and what's going on there, I mean, it's really a host of things.
Certainly, we are seeing capital efficiency in what we're doing. We're being able to drill more wells with the same amount of money. We're seeing efficiencies in our completions. But 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. And if I just one quick follow-up, was the Duvernay sell down, was that included in the original 10,000,000,000 dollars estimate of asset sales? And then, is there any potential upside for that figure over the next couple of years?
Yes. So we wouldn't really talk to what's included or excluded in our overall target. Obviously, it's a significant component there. And in terms of future, I think your second question was, is there future efforts in that regard? I think that's
Do you think there's
I'm sorry, is there upside to that $10,000,000,000 figure now you've gone through it a little bit and progressed through? Do you see upside from your initial estimate?
So 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. So it will be a function of what the market will afford at that point in time. But we are on track for the $10,000,000,000 We can see our way to that almost at this point in Certainly, this year, 2014, or maybe there will be some slippage into Q1 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 BC 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 I'm 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.
I mean there are we've got to work a whole lot of other issues between now and FID and I think they'll remain our view is that they'll continue to remain flexible in those discussions. Okay. And then you
QidiMab before FID, but you also have some remaining capacity at Gorgon, which as I understand is still not covered by offtake. Are you prioritizing 1 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 timeframes. I mean, Gorgon production starts a year from now and ramps up with 3 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 for as a backstop behind IDD from a customer arrangement standpoint.
Now that the Indonesian deepwater 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. So I think that ends our queue at this particular point in time. So 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 3rd quarter 2014 earnings conference call. You may now disconnect.