Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's first quarter 2017 earnings call. At this time, all participants are in listen-only mode. After the speakers' remarks, there will be a question-and-answer session, and instructions will be given at that time. As a reminder, this conference call is being recorded. I will now turn the conference call over the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead. Patricia E. Yarrington: Okay, good morning and thank you, Jonathan. Welcome to Chevron's first quarter earnings conference call and webcast. On the call with me today is Steve Green, President, Chevron Asia-Pacific Exploration & Production company. Also joining us on the call is Frank Mount, General Manager of Investor Relations. We will refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. We ask that you review the cautionary statement on slide 2. I'll begin with a discussion of first quarter 2017 results. Steve will provide an update on upstream activities, with an emphasis on the portfolio he leads in the Asia-Pacific region. Then I'll conclude with a recap of key messages from our March 2017 security analyst meeting. Turning to slide 3, an overview of our financial performance, the company's first quarter earnings were $2.7 billion or $1.41 per diluted share. Excluding foreign exchange and special items, as detailed in an appendix slide, earnings for the quarter totaled $2.3 billion or $1.23 per share. Cash from operations for the quarter was $3.9 billion and included about $1 billion in working capital consumption. Excluding working capital, cash flow from operations was $4.8 billion. At quarter end, debt balances stood at $45 billion, approximately $900 million lower than where we ended 2016. On a headline basis, this means a debt ratio of approximately 24%. On a net debt basis, our debt net of cash totaled $38 billion. Our debt ratio stood at approximately 20%. During the first quarter, we paid $2 billion in dividends. Earlier in the week, we announced a dividend of $1.08 per share payable to stockholders of record as of May 19. We currently yield 4%. Turning to slide 4, we intend to be cash balanced in 2017 at $50 Brent prices, and this slide demonstrates that we are nicely on our way to delivering that. First quarter 2017 net cash generation of $900 million incorporates the impacts of growing operating cash flow, reduced capital spend, and proceeds from asset sales. Operating cash flow reflects improved realizations and high-margin volume growth. Deferred tax effects were approximately $600 million, and affiliate earnings exceeded affiliate dividends by approximately $700 million. TCO did not pay a dividend during the first quarter. That is more likely a second half event. Additionally, working capital requirements consumed approximately $1 billion in the quarter. If you look back over several years, you will generally see a pattern of working capital consumption in the first quarter and often the second quarter resulting from the timing of tax and variable compensation payments as well as inventory build. The historical pattern also shows reversal in the second half of the year, and we expect that reversal pattern to hold again this year. Cash capital spend for the quarter was $3.3 billion, approximately $2.3 billion or 40% less than the first quarter of 2016. Reductions come mainly from finishing our major capital projects under construction, pacing and high-grading future investments, and realizing efficiency gains along with higher cost reductions. First quarter asset sale proceeds were $2.1 billion, primarily from the sale of our geothermal assets in Indonesia. Turning now to slide 5, here you see current quarter earnings compared against the same period last year. First quarter 2017 results were $3.4 billion higher than first quarter 2016 results. Special items, primarily a gain from the sale of our Indonesian geothermal assets, increased earnings by $795 million between periods. Upstream earnings excluding special items and foreign exchange increased $2.3 billion between periods. This reflected improved realizations, lower operating expenses, and increased volumes. Downstream earnings excluding special items and foreign exchange increased by approximately $80 million, mostly due to the swing in timing effects and lower operating expenses. The variance in the other segment was primarily from lower employee expenses and favorable corporate tax items. As we've indicated previously, our guidance for the other segment is $1.6 billion in annual net charges, so quarterly results are likely to be non-ratable. Turning to slide 6, I'll now compare results for the first quarter of 2017 with the fourth quarter of 2016. First quarter results were approximately $2.3 billion higher than the fourth quarter. Special items, mainly from a gain on the sale of geothermal assets in Indonesia, increased earnings between periods by $600 million, while foreign exchange impacts decreased earnings by $267 million between periods. Upstream results excluding special items and foreign exchange increased by $267 million between quarters, primarily reflecting higher realizations. Downstream earnings excluding special items and foreign exchange were higher by $668 million, reflecting the absence of the impacts of the fourth quarter Richmond refinery turnaround and a swing in timing effects. The variance in the other segment largely reflects lower corporate charges and a swing in corporate tax items between quarters. Turning to slide 7, this chart shows first quarter production growth of 82,000 barrels of oil equivalent per day or more than 3% from full-year 2016 levels. Startups and ramp-ups, primarily from Gorgon, Angola LNG, and Alder as well as growth in our Permian assets support accelerated production through the quarter. Base declines, the impact of production sharing and variable royalty contracts, along with the 2017 impact of asset sales consummated in 2016, reduced production. Looking forward to the remainder of 2017, we expect to see additional growth from Gorgon Train 3, the first train at Wheatstone, and Sonam. Additionally, we expect to see continued ramp-ups from other MCPs such as Mafumeira Sul and Moho Nord as well as growth in our Permian assets. Ultimate production growth for 2017 will be impacted by uncertainties, such as the timing and speed of MCP startups and ramp-ups, external events such as the Partition Zone restart, and base decline rates. Price and spend levels will also impact the amount of cost recovery barrels we receive. All said, we expect to comfortably be within the 4% to 9% growth range we provided earlier in the year, again before asset sales. Our current estimate for the impact of 2017 asset sales on production continues to be a reduction of 50,000 to 100,000 barrels of oil equivalent per day. Earlier this week, we announced an agreement to sell our assets in Bangladesh, which produced approximately 114,000 barrels of oil equivalent per day in 2016. The annualized impact of this and other asset sales will be dependent upon the timing of this close and of other individual transactions. And now Steve will walk us through some upstream updates. Stephen W. Green: Thanks Pat. Good morning. Turning to slide 8, all three trains at Gorgon are operational making LNG and in aggregate running over 85% of nameplate capacity, processing gas from both the Jansz and Gorgon fields. The Gorgon project is currently loading a ship about every two days and has shipped 67 cargoes to date, with 38 cargoes shipped since the beginning of the year. Cargo 68 is currently loading now. Recent highlights include we maintained domestic gas production of about 130 million cubic feet per day through the quarter. The Gorgon offshore field started up mid-February. Trains 1 and 2 operated reliably near capacity, with first quarter net LNG production of 105,000 barrels of oil equivalent per day. Train 3 started up mid-March, a month ahead of schedule, and very much like Train 2, above expectations on ramp-up and approached nameplate capacity within two weeks We recently completed a shutdown of Train 2. The shutdown was planned to address a reliability issue previously identified and resolved on Train 1 and on Train 3 prior to startup. Once all three trains are at nameplate capacity, our share of Gorgon production will be over 200,000 barrels of oil equivalent per day. Looking ahead, we'll complete commissioning and startup of additional equipment which boosts efficiency of the trains such as the turbo expanders and the end flash gas compressors, systems that can be started now that all three trains are operational. Once all systems are in operation, we can begin the optimization and tuning of each train, the first step in further increasing capacity. After this, we'll analyze plant performance and look for debottlenecking opportunities that'll increase capacity and capture incremental value going forward. Turning to slide 9, at Wheatstone, the physical construction of all systems required to commence Train 1 startup is complete, and our outlook for first LNG remains mid-2017. Presently, we're focused on commissioning a range of systems as we move toward first gas and have begun running and testing the compressors. We've achieved permanent power at both the onshore and offshore facilities. We're also progressing activities such as mechanical, electrical, and instrument tests as well as final integrity inspections. Within Chevron, we're leveraging our experience locally from Gorgon and more broadly from Angola LNG, which has been operating steadily since the beginning of this year. We're also working closely with our partner, Woodside, which operates several LNG projects. We're preparing for a strong startup, recognizing it is still the first train of a new facility. We anticipate Train 2 startup about 6 to 8 months after Train 1. Turning to slide 10, a primary strength of our portfolio is our base business, where we generate value and cash flow through a disciplined approach. Capturing incremental value in base business is not new to us. We've been doing it for decades. During my time in Thailand, we continuously reinvented ourselves and increased efficiency. We planned our work to avoid stranding capital by bringing wells online timed to meet contractual obligations and market opportunities. This pattern continues today. This chart provides an example from our Thailand E&P business, where we drill over 500 wells per year and have net production of 240,000 barrels of oil equivalent per day. We've seen a substantial reduction in unit development and operating cost through well planning and execution. We've applied these best practices across the company and are seeing benefits in places such as San Joaquin Valley, Indonesia, and the Permian. We're also leveraging our installed capacity and our technological capability to generate value. An example comes from Agbami, where we've drilled and tied back 36 wells since 2005, which have kept the FPSO full. Another example is the 27-mile Lianzi tieback to an existing host in deepwater West Africa, where technology unlocked the opportunity to produce from a remote satellite reservoir. We have an integrated operations center in many of our core assets, where we create collaborative environments for cross-functional teams to analyze asset performance data and to make better intervention decisions. These centers are low-cost and consistently generate value. At TCO, it's helped achieve and sustain record production levels, with a focus on reliability and continued optimization of the well portfolio. We also have an integrated operations center in the Permian, which we expect will help us increase reliability and drive efficiency as our activity levels and production grows. Turning to slide 11, in the Permian, we continue to meet if not exceed expectations. The chart on the left shows our first quarter 2017 production of approximately 150,000 barrels of oil equivalent per day, up about 35,000 barrels of oil equivalent per day from the first quarter 2016. In March, we gave you our forecasted Permian compound annual growth rate of 20% to 35%, and we're currently well within that range. We're standing up our 12th rig, and our plan is to continue to add rigs at this pace, achieving 20 operated rigs by the end of 2018. In addition to our operated fleet, we'll see our share of production from 13 gross non-operated rigs. We continue to see efficiency gains and improved well performance, and we're incorporating the learnings into our forward plans. We intend to realize value through accelerated development and deliberate portfolio actions from the 150,000 to 200,000 acres we have identified as candidates for swaps, leases, or sales. Our objective in the Permian is to be fully competitive on our unit development and production cost and realizations and use our superior royalty position to generate leading financial performance. With that, I'll turn it back over to Pat. Patricia E. Yarrington: Okay, thanks, Steve. Now turning to slide 12, we continue to lower our cost structure and reduce our spend. The chart shows a steep reduction in quarterly average C&E since 2014. Year-to-date capital expenditures of $4.4 billion are down 22% compared to the average 2016 quarter and down 56% compared to the average 2014 quarter. We are trending below annual guidance. We previously communicated that our capital guidance range is $17 billion to $22 billion per year through 2020. If oil prices remain near the $50 per barrel mark, you can expect to see our future spend near the bottom of this range. Year-to-date operating expense is down almost 11% when compared to the average 2016 quarter and down 26% when compared to the average 2014 quarter. We have made substantial progress on lowering our cost structure, and we are striving to have the remaining quarters of 2017 broadly continue this pattern. Now on slide 13, we received approximately $2.1 billion in asset sale proceeds in the quarter, the vast majority of which related to the sale of our geothermal assets in Indonesia. Since the beginning of 2016, we've sold approximately $5 billion in assets, and thus have already achieved the lower band of our targeted two-year range. Also during the quarter, we signed sales and purchase agreements to sell our marketing and refining assets in British Columbia and Alberta as well as our downstream business in South Africa and Botswana. These in-progress transactions are subject to regulatory reviews prior to closing, hopefully later this year. Additionally, we announced an agreement to sell our upstream assets in Bangladesh, a business where gas production is sold into the domestic market at a fixed price. Turning now to slide 14, I'd like to close by reiterating our messages from our recent security analyst meeting. Our financial priorities are clear and consistent. Our number one priority is to maintain and grow the dividend as earnings and cash flow permit. To do that, we're focused on three areas. First, we are taking actions that should enable us to be cash balanced in 2017. We intend to continue to grow free cash flow thereafter. The first quarter was a good start. Second, we are focused on improving returns. This will happen as projects are completed and revenue is realized from growing production volume. It will happen as we shift our capital program. 75% of our spend is expected to generate cash within two years, and it will be aided by ongoing reductions in operating expenses and improvements in how we manage our major capital projects. Third, we're focused on unlocking value from our entire portfolio. Our portfolio is anchored by legacy positions and advantaged by assets that are early in life. This gives us the opportunity to realize efficiency, reliability, and debottlenecking gains with short-cycle high-return capital investments. So that concludes our prepared remarks, and we're now ready to take your questions. Please keep in mind that we do have a full queue, so please try to limit yourself to one question and one follow-up if necessary. We'll certainly do our best to get all of your questions answered. Jonathan, please go ahead and open up the lines for questions.

Thank you. Our first question comes from the line of Jason Gammel from Jefferies, your question, please.

Thanks very much and hi, everyone. I'd like to take advantage of Steve being on the call and ask a couple questions about Australia, if I could. Steve, you referenced in your remarks that Gorgon was currently operating at about 85%. I think each of the trains individually has been able to run at its nameplate capacity. Could you talk about anything that's on the critical path for all three trains being able to operate at nameplate capacity simultaneously and essentially what needs to be done before you can reach full economic capacity at Gorgon? Stephen W. Green: Sure, Jason. Thanks for the question. We have operated all three trains at or near capacity, and we're seeing good performance from all three trains. There's nothing that is prohibiting us from operating at nameplate capacity except the fact that we have to work through a methodical startup and again bring on the proper blend from gas from Jansz and Gorgon. In my prepared remarks, I referenced there's some additional equipment that we will now commission since all three trains are operating that will allow us to, again, boost capacity and continue working toward nameplate capacity. But all three trains have operated very reliably. They're operating reliably now. The Train 2 shutdown was a planned event to address a mechanical device that we knew we were going to. So we're looking forward now to a reliable period of operation that allows us to do some tuning and performance improvements.

Okay, very clear. And then maybe as a follow up, I did note in the media that there was an unfavorable tax ruling recently in Australia that I think was related to interest deduction on some intercompany loans for some prior-year tax returns. I think the number was about $250 million that was referenced. I just wanted to check and see if there was any further potential liability on any past tax returns related to this issue and if there's anything prospectively that you think will affect your tax position in Australia. Patricia E. Yarrington: So, Jason, I'm going to go ahead and take that one, and I guess I want to start with expressing our huge disappointment in the ruling. I want to make it clear to everybody though that the courts affirmed that the financing arrangements that we had in place are legal. And so the issue that is being litigated here is the appropriate interest rate for a loan between our corporate group and our Chevron Australia subsidiary. I would say that the court ruling deviates substantially from recognized international transfer pricing guidelines. And in those guidelines, the courts are to treat related parties to a transaction as if they were standalone separate legal entities. And the Australian appellate court really failed to do this, so in other words they were making no distinction between the creditworthiness of the Chevron Corporation as an entity versus Chevron Australia as an entity, and therefore no distinction on the relative borrowing costs between those entities. I'd say that there's an awful lot at stake with this ruling, not just for Chevron but for any intercompany lending in Australia and more broadly around the globe, because it fundamentally changes established transfer pricing guidelines and principles. So if the ruling stands, it certainly going to affect any future investment in Australia. And I would say going forward and thinking about it specific to the Chevron case, we're obviously evaluating the decision. Now the decision just came out a week ago. It's a fairly lengthy decision, and we're reviewing our options. Those options include going forward with an appeal to the High Court of Australia as well as continuing on with discussions with the ATO on possible settlements and any other reasonable resolution to the dispute.

Thanks, Pat, very helpful.

Thank you. Our next question comes from the line of Paul Cheng with Barclays, your question, please.

Hey, guys. Good morning. Steve, I had two questions. First, you mentioned that the Train 2 is done. So when's that supposed to come back? And I presume that you already – what happened is the mechanical issue you already addressing in Train 3 and Wheatstone. And also for Gorgon Train 4 and also Wheatstone Train 3, what kind of precondition do you need in order that you even consider an FID at this moment? Stephen W. Green: Sure. Thanks, Paul. With respect to Train 2, it is online and operating and producing LNG this morning. And as I mentioned, a little more color than in my prepared remarks, the issue that we addressed on the recent Train 2 shutdown was a mechanical device that's part of the flow measurement apparatus that we had previously dealt with in Train 1 and we corrected in Train 3 prior to Train 3 even starting up. Certainly, we are transferring all the learnings and experience from Gorgon to the Wheatstone project, so that prior to startup they have the opportunity to intervene and address those known issues prior to startup. As far as expansion trains at Gorgon and Wheatstone, there are a lot of factors that go into that. Our first priority is to get these assets up, stable, working as intended, and capture the value from the investment we've made. At that point then, it will be that decision, like any major capital project, will be a function of the market and the market's appetite for it and how those individual investments will compete in our portfolio at the time we FID them.

Thanks, Paul.

Thank you.

Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research, your question, please.

Hi, everyone. Pat, you mentioned TCO no dividend. Could you just remind us? I think that you had said that at $50 Brent, below $50 you have to contribute to the capital expenditure programs there, above it's self-financing. I was just wondering what the sensitivity is on the dividend as regards to the oil price and whether I've got about the right numbers there. Thanks. Patricia E. Yarrington: Actually, Paul, what happened was that in 2016, we and Exxon made co-loans into the joint venture. There was also a third-party borrowing. And a summation of that, when you looked at the amount of funds that came into the enterprise relative to the amount of investment that was going to be required on the capital project, there were sufficient funds projected out for 2017 where there would not be another co-lending requirement needed for 2017. As you look forward in 2018 and if you assume a $50-ish scenario, there will more likely than not be co-loans going on in 2018 – 2019. Somewhere in the $2 billion to $3 billion-ish range is our requirement for total affiliate spending over this period of time. So what we were saying is that because there was an advance funding of capital requirements in 2016, we didn't see that we would need to co-lend again in 2017. We do anticipate that there will be a dividend receipt in the second half of this year for us.

That would be around oil prices? Sorry. Patricia E. Yarrington: That's exactly right, that's exactly right. And going forward, there will be obviously a lot of planning around what is the pace of spending on the project, what's happening to oil prices, what's the internal cash generation at TCO, et cetera.

Great, thanks, Pat. And then the follow-up is your volume target for this year of 4% to 9% growth is a pretty big range. When I look at the uncertainties that you've listed, you seem to be saying that Gorgon/Wheatstone are bang-on schedule as far as you're concerned. I'll give you the Partition Neutral Zone uncertainty. I understand that one. I would have thought the base decline was fairly predictable by the time we're in April, and I don't really understand why there would be a PSC [Production Sharing Contract] effect if you were assuming $50 oil. Is it safe to say that we should be looking towards the higher end of that range because of the uncertainties apart from the Partition Neutral Zone are essentially being significantly mitigated? Thanks. Patricia E. Yarrington: I think what we were trying to do in addition to PZ, PZ is a significant component there, but we're also trying to say that even – what people capture in their mind is the 4% to 9%, and they forget the pricing premise that was used for it. And so yes, there are price sensitivities built into that range that influence cost recovery barrels and the like. Also, the investment levels going forward influence the cost recovery barrels as well. So we were just trying to be as descriptive as we possibly could be in naming the things that could either work to the upside or work to the downside.

I guess my point is that it feels like the downside effects are significantly mitigated. Patricia E. Yarrington: If we continue on with first quarter results into second quarter and third quarter results, I would agree with you.

Thanks, Pat.

Thanks, Paul.

Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs, your question, please.

Good morning, Pat. Patricia E. Yarrington: Good morning.

Hi, Neil.

Hey, how are you guys? First question relates to CapEx. It looks like you're tracking below the guidance, and I wanted to confirm, Pat. The $17 billion to $22 billion, it sounds like you're going to be on the lower end of that range at $50 a barrel Brent. And relative to the guidance, what surprised to the downside here as it relates to CapEx? Patricia E. Yarrington: I think that we are trending lower than a ratable amount would give you relative to our $19.8 billion target for this year. The affiliate spending was a little bit lower than ratable. And I think as you go through the year, there will be spending by TCO in particular that should pick up as the remaining three quarters get underway. Other than that, I would just speak to capital efficiency. I think we are getting much more output – much greater activity for a given dollar spend than we were anticipating. So coming in at the lower end of – coming in below the $19.8 billion could very well be where we end up for the year.

I appreciate that. And, Pat, corporate costs were a little funky this quarter, favorable after being unfavorable last quarter. Can you talk about some of the drivers that contributed to that benefit? Patricia E. Yarrington: Yes, it's my favorite topic. Actually, all I would say is that the corporate sector can be really quite volatile. It does include certain corporate expenses, for example, related to employees. I mentioned last quarter, if you'll recall, about pension settlement costs. That's a factor that goes on in here. But more impactful typically would be corporate consolidated tax entries, and those are just very hard for us to predict. They're not necessarily ratable, and that's really what you see going on here in this particular quarter. I would just again ask you to go back and think about the full year and use the $1.6 billion net charge for that sector for us in your predictions. That's the best information that I have, and it will be not ratable. It will be lumpy.

That's great. Thanks, Pat.

Thank you. Our next question comes from the line of Doug Leggate from Bank of America, your question, please.

Thanks, good morning, everybody. Good morning, Pat. Pat, disposals, you made the point that you've already hit the low end of your range. There is some speculation that there could be additional asset sales that you haven't yet put in the public domain, Canada oil sands being the case in point. I'm just wondering if you could frame what the objective is. Is it to achieve the $5 billion to $10 billion, or is it to high-grade the portfolio? And what I'm really getting at is, if there were other things to sell, would you cap the sales at $10 billion, or would you keep going as you upgrade the portfolio? And I've got a follow-up, please. Patricia E. Yarrington: Right. So I don't think it's an either/or circumstance. We do want to come in between the $5 billion to $10 billion, but we also are very focused on improving the portfolio and high-grading the portfolio. So we put this target out a year and a half ago or so now, and we're in the second half of the time period in executing it. I think it's still a good target for us this year, but we will continue to look at the portfolio and continue to see if there are assets that again, either aren't strategic or not closely strategic, whether there's value that others see in it that's greater than ours or that won't attract capital in our capital allocation process.

Can you address Canada specifically? Patricia E. Yarrington: Canada, it's a good asset for us. It's a cash generator for us. We're obviously aware of – you're talking about oil sands. I'm talking about oil sands at least.

Yeah, I am. Patricia E. Yarrington: We're aware of the transactions that have occurred in this space over the last few weeks. All I would say is that if we were to transact, we'd want to make sure we got good value for it.

My follow-up, Pat, hopefully a quick one. At the Analyst Day, you talked about evaluating a case to add an additional 10 rigs after the 20 rigs in the end of 2018. I'm just wondering, with CapEx trending below target, I know it's really early days. I get that. But I'm just wondering where you are in that evaluation, whether the pace might accelerate faster than you're currently guiding, and I'll leave it there. Thanks. Patricia E. Yarrington: Really I hate to – Doug, I hate to go off of guidance we gave just four weeks ago or so. It clearly is in our quiver here. We are obviously very much evaluating it. We're seeing great efficiency in terms of what we get per dollar spent. All of the production and operating cost improvements that we noted before continue to happen. So we very well may be able to capture much greater activity and therefore much greater volume per dollar spent. So we'll continue to look at this. We understand the – we have the same desire that our shareholders have, which is monetizing that asset as best we can, and this is certainly one avenue for doing that.

Appreciate that, Pat. Good weekend, everyone. Patricia E. Yarrington: Thanks.

Thanks, Doug.

Thank you. Our next question comes from the line of Phil Gresh from JPMorgan, your question, please. Philip M. Gresh: Hey, good morning, just one additional follow-up on Gorgon, I guess Wheatstone as well. With the production that we saw in the first quarter and where you're running today and then assumed startup cost for Wheatstone, how are you thinking about the real cash flow contribution from these two assets in 2017? I know they're meant to be a big contributor in the long term. But with the startup costs for Wheatstone and Gorgon finally just hitting its full stride, how much of that long-term cash flow contribution do you actually expect this year? Patricia E. Yarrington: I would say from a Gorgon standpoint, a reasonable number to have in your mind is a couple billion dollars. And of course, Wheatstone is just going to be ramping up, so I wouldn't expect a significant contribution there. Philip M. Gresh: Would you expect it to actually be a negative with the startup? Patricia E. Yarrington: I don't think I want to give a number there necessarily. There are still capital expenditures that are being incurred. And so if you look at it including capital expenditures, the answer on that would obviously be yes. It's probably a net drain on us. Philip M. Gresh: Understood. My follow-up is just... Patricia E. Yarrington: For 2016 (36:35). Philip M. Gresh: Yes, okay, got it. My follow-up is just on your supplement. The other production bucket for nat-gas has been up significantly. I assume that's Angola. You touched on it a little bit in the prepared remarks. But maybe, Steve, if you could just highlight a little bit more for us where you're at with Angola and what you're expecting for the year. Stephen W. Green: Well, as you know, Angola restarted early part of the year, and it's been running very reliably since that time. And we are consistently loading LNG cargoes, propane cargoes, butane, and we expect that performance to continue. We've gotten the plant where we want it now and it's operating reliably.

Thanks, Phil. Philip M. Gresh: Okay, thanks.

Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley, your question, please.

Hey. Good morning, guys.

Hi, Evan.

Pat, you mentioned that CapEx runs to a low end for 2017 if oil is near $50. Oil being near $50, can you discuss when you begin to adjust that spending? And is that adjustment within short-cycle Permian or elsewhere, just how that plays out in the 2017 capital program? Patricia E. Yarrington: I would just say within upstream, I think there is fine-tuning as the year progresses about where capital opportunities are being generated – additional spending opportunities are being generated. Obviously, the Permian is going to be one of the first places to draw additional capital, but there are other short-cycle investments, for example, in Thailand and also in San Joaquin that would also be attractive as well. So that is a routine optimization that goes on within the upstream leadership team – I won't say on a monthly basis, but obviously they continue to monitor that as the year progresses.

Right. So that works for lowering CapEx as well? I think you phrased it for raising CapEx. Patricia E. Yarrington: I did phrase it for lowering it. I'm sorry. Go ahead. I meant...

Perfect, sure. My second question, I know, for Paul, I know a lot's been covered here within Australia. I know you have a lot of moving pieces in the portfolio that are outside of Chevron's control. Maybe just some update of conditions to outlook in Nigeria, Venezuela, and PNZ, any update in those regions I think would be helpful. Thanks. Patricia E. Yarrington: Okay. Let me just – I'll take PZ first. I can say that negotiations and discussions are underway still. They're still occurring between the parties of the government. I really can't go out on a limb and predict when the resolution might occur. We're going on two years now where this has been an issue. I will say that the longer this goes on, the more challenging it is to get the equipment back up and running. We do continue to reduce operating expenses in PZ and continue to let people leave the payroll because we need to limit the losses that are occurring here. So I don't have any fresh news about when we might expect that restart, unfortunately. In Venezuela, I would just say it's a very tough circumstance for all of the people of Venezuela. We haven't had any or significant – it's really been minimal impact to our operations and our facilities. Priority number one for us is keeping our people safe, and so we're operating with that intention in mind. And Nigeria just continues to be a challenging location as well. There has been some disruption to production facilities in the first quarter of the year. We continue to monitor for safety there as well.

Thanks, Evan.

Great, I appreciate the color.

Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse, your question, please.

Yes, good morning, a question for Steve on Australia. You had the issue I think with the flow meter, and you sorted that out on the trains. I wanted just to confirm that there isn't any design difference between Gorgon and Wheatstone, and therefore, what the risks are in terms of starting up at Wheatstone, that it's all been fixed based on the learnings at Gorgon, if I understood you correctly. Stephen W. Green: Yes, Ed. Thanks for the question. There are design differences. They're two different technologies in the plant between Gorgon and Wheatstone. But of any common equipment and any issues that we have dealt with in the startup of all three trains at Gorgon, we have communicated. And those issues have been addressed at Wheatstone to the extent they're common to Gorgon. That also includes – I mentioned our partner, Woodside, any issues that they have experienced in any of their facilities. We're benefiting from that as well, or Angola LNG. So any place we can get learnings or experience or borrow it, we're factoring that in and addressing it as best we can pre-startup to try to remove those variables.

And then sticking with Australia, obviously at Gorgon you're talking about debottlenecking. It would be interesting to see what sort of debottlenecking uplift you can get from the plant, but also obviously there's Northwest Shelf, and there are other plants that need filling. Maybe how would those investments compete against each other? I obviously appreciate there's commercial terms to be negotiated as well. Stephen W. Green: Right. I guess I would start with your second part of your question first. We do have active work going on now to assess our large portfolio of discovered resource and look for commercial opportunities to accelerate that and commercialize that as the market materializes. So that work is ongoing, whether it be through one of our facilities or third-party facilities. With respect to Gorgon and debottlenecking, as I mentioned in the prepared remarks, we have been looking forward to the day where we are today at Gorgon where we have all three trains up and running. We can begin to now tune and improve performance in the system as a whole. We have some additional equipment that will boost capacity as we bring that online. I mentioned a couple of examples of that in the prepared remarks. But this is really an opportunity to exercise what I consider a real core competency of the company, and that is getting more and more out of assets once they're up and operating. A terrific example of that is our long experience at Tengiz, where we have consistently improved performance and efficiency and increased the throughput from that facility. And we're looking forward to having a similar experience at Gorgon as we go forward in time. Specific to the debottlenecking, we'll analyze those opportunities, and some of those will be relatively short-term that we can do while we're in operation. Others are more complex and will require engineering and scheduling into planned outages or turnarounds as we go forward in time.

Thanks, Steve. Stephen W. Green: Sure.

Thank you. Our next question comes from the line of Alastair Syme from Citi, your question, please. Alastair R. Syme: Hi, everyone. Pat, can you talk about the cost trend on slide 12 a little bit, as you look back, how much you think those have been variable costs, such as energy and chemicals? And are you seeing any signs that that's beginning to come back? And I had a follow-up for Steve as well. Patricia E. Yarrington: So I would say just general in terms of inflationary pressures, the only place around the globe really that we are seeing inflationary pressures of any size would be in the Permian, and that's obviously being driven by activity levels in the Permian. And within the Permian, obviously we're working very hard to restrict that through our contracting strategy in terms of fixed-price contracts, indexed contracts, staggered contract terms, performance contracts, et cetera. Overall, we think that will be manageable for us, relatively small impact in 2017. And then outside the Permian, we really just haven't seen inflationary pressures. So I think in general, that's why I said that we intend – we're certainly striving to have a continued downward trend on operating expense in the remaining three quarters of the year, acknowledging that we will be bringing on additional production, and that will be an element going in the other direction. Alastair R. Syme: Thank you. And my follow-up to Steve – I know this is going to be a sensitive subject. But can you comment on what you think the Australian government is trying to achieve with its PRRT [Petroleum Resource Rent Tax] review and other aspects of the existing legislation that you would like to get changed? Stephen W. Green: I think as an investor, there's no difference in Australia than we look anywhere. We look for stability of fiscal terms and conditions that we invest under to be maintained over the life of those investments. So we have been and have been engaged with the government on the PRRT question, and that is a cautionary note for all investors, not just us. But the government yesterday in Australia released the initial report, and any changes that are contemplated will be prospective, which is exactly what our position was, is you can't go back and change the rules of the game after the investments are made. And so I think we have good engagement with the government. It has been a bit of irony. I was there last week, and the second story on page 1A is the emerging gas crisis, or energy crisis on the East Coast, which of course a solution will demand significant capital investment. So I think Australia is appropriately trying to find the right balance between their fiscal needs in the government and preserving what has been a very, very successful regime for attracting large capital investment, especially in our sector.

Thanks, Alastair.

Thank you. Our next question comes from the line of Blake Fernandez from Scotia Howard Weil, your question, please.

Folks, good morning. Congrats on the results. I had two questions for you on the Permian. I know you already addressed the operated rig count, but my question was on the non-operated rig count. I think you said the base case contemplated 13 non-operated rigs. And just based on the level of activity increases we're seeing in the industry, it just seems like there's probably upward pressure there. So can you confirm whether you're getting pressure from peers to maybe increase activity on that and whether that probably leads to some upside on your base case? And then I guess tying in with the Permian question, the second is on the oil price realizations in the U.S. It seems like there was a pretty healthy increase in U.S. oil relative to the benchmarks. I didn't know if there was something one-off or this is just a function of Permian ramping up and that representing better realizations relative to the rest of the portfolio. Thanks. Patricia E. Yarrington: Okay, yes. So, Blake, I would say on the NOJV [Non-Operated Joint Venture] issue, I don't really have any significant information that would suggest the NOJV plan is any different than we had outlined. Currently, we've got 13 gross NOJV rigs, so that's five net. And I see that – I think in our plan as we look forward, there was ramping up some, but I don't have any new information relative to that. And with regard to the realizations, there's nothing unusual there in terms of one-offs on realizations. It really is just as a function of WTI prices, San Joaquin Valley prices, Mars prices, et cetera, and how those move relative to one another.

Fair enough, thank you.

Thanks, Blake.

Thank you. Our next question comes from the line of Anish Kapadia from TPH, your question, please.

Hi. My first question was really to Steve to think about the Southeast Asia business from a more strategic standpoint. You've divested of the Bangladesh assets. There have been quite a few stories in the press that you've been looking at least at divesting of maybe some of your other Southeast Asian assets. And then on the other side, you have got some predevelopment pre-FID decisions to make on things like Ubon and further developments in Indonesia. So I just wanted to get an idea of how you view Southeast Asia within the context of the portfolio and the strategic decisions that you're thinking about for that portfolio. Stephen W. Green: Thanks for the question. Southeast Asia has long been and remains a core part of our upstream portfolio. We have a great business in Thailand, have had for 40-plus years. That business continues to perform very well. And in terms of incremental investments in Thailand beyond the base business, those are evaluated just like they are anywhere else in the company. The market, the terms and conditions, the resource, all those things – the cost of finding and development on a unit basis, all those things factor into our decision, whether it's Thailand or Indonesia as well. And our process for some time has been to go through the portfolio systematically and look at incremental investments on how they compete within the portfolio relative to our other opportunities. But notwithstanding the asset divestments that have been announced, Southeast Asia's still a very, very core part of our upstream portfolio and is performing well.

Thank you, and then a follow-up for Pat around cash flow. So you mentioned some impacts in Q1 that may turn around in the second half of the year, I think in terms of the working capital in particular. And I'm guessing also you've got the impact of projects ramping up in the second half of the year. So I'm just thinking in a flat oil price environment, should we expect significantly higher cash flow in the second half of 2017 to the first half of 2017? And also just related to that, are there any significant pension contribution impacts through the course of this year? Patricia E. Yarrington: So I would say in general, I think that's a good premise for you. If you look back over time, our first quarter tends to be typically our lowest cash generation quarter, and part of it is driven by the working capital. I did indicate that we saw a portion of that working capital most likely reversing between the end of this quarter and the end of the year, so I don't think you will get the same kind of penalty there per quarter. I'd also say – I mentioned the dividends, a potential coming in from TCO in the second half of the year, so that would be a positive in the remaining quarters of the year. If you go back to what I said back in March, one of the questions I had was about all of the summation of all of these "headwinds", and I had given an indication then of them being about $4 billion, a little bit over $4 billion for the year. And I still think that is a good element to think about when you consider the deferred tax impact, the working capital impact, and the difference between affiliate dividend and dividend earnings during the period. So all said, when you put that all together, I know there was a lot of numbers there. I do think the second part of the year we'll have stronger cash generation, not only from these reasons that I'm talking about, but production increases and the fact that these are high cash margin barrels that we're bringing on.

Okay, thanks. And just to clarify, that $4 billion, does that include the cash contributions to pensions? Patricia E. Yarrington: It would, it would.

Right, thank you.

Thanks, Anish.

Thank you. Our next question comes from the line of Doug Terreson from Evercore ISI. Your question, please.

Good morning, everybody.

Hi, Doug. Patricia E. Yarrington: Hi, Doug.

To me a positive aspect of the capital allocation and the corporate governance changes that are underway at the company is the increased emphasis on cash returns at the business unit level and specifically on project execution, at least in my opinion. And while John [Watson] talked about this some at the analyst meeting, I wanted to see if you could provide a progress report on this process in the upstream business, the timeframes over which the teams are going to be judged, and really any other factors that you deem relevant to positive execution and performance in this area. Patricia E. Yarrington: It's a good question. I think the best place that I would go because where we're seeing it in action is in TCO because this is the most significant capital project that we have underway at this point in time of a longer duration. And so we've talked about the fact that we were increasing the overall engineering that was done before we began to essentially cut steel. We've now started fabrication in Korea and the Kazakhstani yards. We're monitoring – we've done more in terms of design assurance there on that project, optimizing contracting strategy, taking advantage of the lower-cost environment. So I really think the benchmark in terms of how this will turn out in terms of all of these elements that Jay [Pryor] and John have talked about before in terms of major capital project execution, the benchmark on how we're doing will be with regard to TCO and how well it is coming forward. And right now, the overall progress, we're on track with elements of fabrication and construction of the port and we're underway with constructing the village, the housing village, et cetera, and the drilling is going very well. So all of those efforts are really being focused in real time on the TCO project.

Okay, great. It'll be a good test case. And then also, Pat, there's a $2 billion sales proceeds figure floating around in the press for Bangladesh. And so my question, is that your number or is it somebody else's number, or is that a no comment at this point? Patricia E. Yarrington: That's a no comment at this point, so thank you very much for giving me that third option.

Okay, thanks a lot, guys.

Thanks, Doug.

Thank you. Our next question comes from the line of Ryan Todd from Deutsche Bank, your question, please.

Great, thanks. Maybe a follow-up to the earlier cash flow questions. You generated I think roughly $900 million of free cash flow in the quarter beyond the dividend and you used it to pay down some debt. I realize there was an asset sale at the tail end of the quarter. But as you start to generate modest amounts of discretionary cash flow beyond CapEx and the dividend, how should we think about the use of the discretionary cash flow? How would you prioritize debt paydown versus buyback versus incremental capital spend? Patricia E. Yarrington: Yeah, so I'm just going to go back and reiterate what our priorities have long been. The first priority is going to be given to growing the dividend when we feel cash flow and earnings can support it for the long term, and by that I mean in perpetuity. Secondly, we look at future additional investment opportunities that we've got because we do need to continue to grow future revenue streams. And then we look at the balance sheet. It is important for us to continue to have a strong balance sheet. And what you saw in this quarter is really a flex in our commercial paper program, and that's part of why we have a commercial paper program is to take flex like this. So all of those are important to us. We do balance that. We're at a 24% debt ratio, which is an okay place to be, I would say. But over time, I'd like to see us move a little bit lower in the debt profile when cash flow permits us to do that. Maintaining a AA is important to us. We did just meet with the rating agencies. We did just get affirmed by Moody's as a AA stable. We haven't heard from S&P yet, but it's an important element for us.

Okay, thanks. And then maybe you have a slide there in the deck. I think it's slide 10, showing efficiency gains across the base portfolio as well. And obviously for investors the efficiency gains in the U.S. onshore has been a huge area of focus and generally is quite transparent. Can you talk a little bit more about the efficiency gains that you're seeing across the broader global portfolio? Do you think the market underestimates gains outside the U.S? And is the 30 to 35-plus percentage type of gains that you're showing here and a couple anecdotal things, is that representative of the type of gains you're seeing across the broader portfolio? Stephen W. Green: The chart that you referenced, of course, is specific to our Thailand operations. But as I mentioned in the prepared remarks, we are transferring both people and learnings from those operations into the Permian, into AMBU [Appalachia-Michigan Business Unit], into other places where we have this factory well approach. And we are seeing those kind of gains in efficiency and driving down our unit cost. Another example that's probably a little less visible perhaps comes from Indonesia. Last year in Indonesia, in our Duri operations, which is a heavy oil steam flood, we were able to drive down the cost of our steam, which is our largest line item of OpEx, by over 40%, without degradating the production, no impact to production. So again, as I said in response to a question about Gorgon, this is the sweet spot of Chevron's core capability is transferring learnings and ways to get efficiency and operate assets in the portfolio and get more and more out of them as we go forward.

Thanks, Ryan.

Sure, thanks.

Thank you. Patricia E. Yarrington: Okay, I think we've got time for one more question.

Our last question comes from the line of Theepan Jothilingam from Exane BNP, your question, please.

Yes, hi. Good morning, Pat. Good morning, gentlemen. Patricia E. Yarrington: Good morning.

Just coming back to the financials, could you perhaps just talk a little bit about cash taxes? I know you've quantified the deferred tax impact this quarter. But just going forward at Chevron, let's say at $50, how should we think of cash tax rate? And then my follow-up question was just on PZ. Again, broadly speaking, what type of run rate should we be thinking about on OpEx and how we actually capture that back if and when PZ volumes are back onstream? Thank you. Patricia E. Yarrington: Yes, so I'll take PZ first. I don't want to get into describing what our ongoing operating costs are here when we've got an asset that is not operating. I will just say that when it does come back online, these cumulative losses will be taken into account in terms of the eventual recovery, tax recovery that's available to us. In terms of cash tax, this is a hard area for us to forecast at this particular time because of just issues that I've explained before about tax loss carryforwards and the fact that we've got different jurisdictions with different circumstances as their current tax position standpoint. I would say in general, we do still have some jurisdictions at current prices that are generating tax losses. And so that means that these tax losses will be carried forward into future periods. And when oil prices rise from $50 to $60 to $70, if you assume that hypothesis, we do need higher prices here to recover some of those previously deferred or those tax losses that have been carried forward that cannot then be carried back and will become a cash benefit, a relative cash benefit in future periods. That's really the best guidance that I can give you at this point in time. At low prices, there is not a lot of – we do have cash taxes in some locations, but it is not in all locations.

Is there any way to quantify that number in terms of an aggregate number there, if prices were to recover, Chevron could use in terms of tax allowances? Patricia E. Yarrington: I don't have it handy here. It's something I can consider for future disclosures.

Great. Thank you, Pat.

I Thanks, Theepan. Patricia E. Yarrington: Okay, I think that concludes our call for this morning. I want to thank everybody for your time today, and we certainly appreciate your interest in Chevron and your participation on the call. Thanks very much.

Ladies and gentlemen, this concludes Chevron's first quarter 2017 earnings conference call. You may now disconnect. Good day.