Conoco Phillips (COP) — Q2 2019 Earnings Call Transcript

Thank you, Sanera. Hello, everyone, and welcome to our second quarter earnings call. Today's prepared remarks will be delivered by Don Wallette, our EVP and Chief Financial Officer; and Matt Fox, our EVP and Chief Operating Officer. In addition, our three regional Presidents are on the call today. They are Bill Bullock, our President of the Asia Pacific and Middle East region; Michael Hatfield, our President of the Alaska, Canada and Europe regions; and Dominic Macklon, President of our Lower 48 region. Page 2 of today’s presentation deck shows our cautionary statement. We will make some forward-looking statements on today's call that refer to estimates or plans. Actual results could differ due to the factors described on this slide and in our periodic filings with the SEC. We will also refer to some non-GAAP financial measures this morning and reconciliation of non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and on our website. And now, I’ll turn the call over to Don.

Thanks, Ellen. Good morning to all. I'll cover the second quarter highlights on Slide 4. Starting on the left with our financial performance, we realized adjusted earnings of $1.1 billion in the quarter or $1.01 per share. Our production outperformance in the quarter didn't fully translate to the bottom line as sales lagged production with inventories building by roughly 25,000 barrels a day, which represents about $0.03 a share. We generated $3.4 billion of cash from operations resulting in free cash flow of $1.7 billion in the quarter and $3 billion year-to-date. This quarter represents our seventh consecutive quarter of free cash flow generation across a broad range of prices underscoring our commitment to capital discipline. Importantly, over this seven quarter timeframe, cash from operations has more than covered all capital, dividends, and share repurchases. We ended the quarter with $6.9 billion of cash and short-term investments. In our strong financial returns continued on a trailing 12-month basis, our return on capital employed was 12.4%. Moving to the middle column, operationally, in the quarter we produced 1.29 million barrels of oil equivalent per day, up 6% on an underlying per debt adjusted share basis compared with the year-ago quarter. Sequentially, seasonal turnaround impacts were mitigated by growth from the Lower 48 Big 3. In the second quarter, we closed several small bolt-on transactions in the Lower 48 Big 3 for about $100 million. We continuously monitor the market for these types of low-cost supply additions around our core areas and completed a few royalty interest and acreage deals this quarter under attractive terms. Shifting to the far right strategic column, we've increased this year's planned share repurchase program by $500 million to a total of $3.5 billion. In the second quarter, we repurchased $1.25 billion of shares and expect to purchase $1.5 billion of shares in the second half of the year. Combined with our second quarter dividend, we returned 47% of cash from operations to shareholders in the quarter, emphasizing our priority to return capital to shareholders. In the second quarter, we realized $600 million in disposition proceeds and the UK disposition continues to progress toward closing in the second half of the year, with an expected gain of approximately $2 billion before tax and after tax when the sale closes. Upon closing, we'll see significant balance sheet improvement with net cash proceeds expected to be about $2 billion, while liabilities associated with asset retirement obligations will decrease by about $2 billion. If you turn to Slide 5, I'll wrap up with a look at cash flows. During the quarter, we began with cash and short-term investments of $6.7 billion. Cash from operations was $3.4 billion, including roughly $320 million in APLNG distributions, and about $90 million collected through the ICC settlement agreement with PDVSA. To date, we've received $665 million related to the $2 billion settlement. We've continued to receive contingent value payments from Cenovus during the quarter, accruing a little over $180 million in contingency payments from this 2017 transaction. Moving on, working capital was a $600 million use of cash during the quarter. We recognized $600 million in proceeds from dispositions and had $1.7 billion of capital expenditures in the quarter, which was exactly half of cash from operations excluding working capital, leaving $1.7 billion of free cash flow. For the first half, free cash flow was $3 billion, representing a 9% free cash flow yield on an annualized basis. The roughly $350 million in dividends and $1.25 billion of share repurchases represented a return of capital to shareholders of $1.6 billion or 47% of cash from operations. Total shareholder yield based on planned buybacks and our current dividend is running a little over 7%. You'll see a slight build from the first quarter in the ending cash, despite increasing buybacks by $500 million compared to recent quarters. In summary, this past quarter builds on our trend of consistent and strong operational and financial performance. It emphasizes our commitment to financial returns, capital discipline, free cash flow generation, and returning cash from operations to shareholders. We believe this is a sustainable and compelling value proposition for our industry. With that, I'll turn the call over to Matt.

Thanks, Don. I'll provide a brief overview of year-to-date operational highlights and discuss our outlook for the remainder of the year. So please turn to Slide 7. Across the portfolio, we continue to make progress towards the key milestones we highlighted at the end of last year. In Alaska, we wrapped up our winter appraisal season in the Greater Willow Area and Narwhal in the second quarter. During the first half of the year, we built seven successful appraisal wells and conducted a series of horizontal production well, injectivity and interference tests. The results have been encouraging for both Willow and Narwhal trends. Based on these positive results, we're also taking the opportunity to drill an additional unbudgeted horizontal well from an existing Alpine drill site into the Narwhal trend later this year. We also announced the high-value bolt-on to our Alaska position, acquiring discovered resource acreage called Nuna, directly adjacent to our Kuparuk field, and we expect that transaction to close in the third quarter. In June, planned maintenance was completed at Prudhoe Bay, and turnarounds will continue in the third quarter at Prudhoe, the Western North Slope, and Kuparuk. In Canada, we safely completed the first turnaround of our Surmont 2 central processing facility, which in addition to the maintenance scope, also paved the way for the alternative diluent project. This capability will not only reduce the amount of diluent we require, but provide diluent flexibility and improve our netbacks. We expect it to be fully operational by the end of the year as planned. In June, Surmont was brought back online, but continues to be subject to mandatory curtailment, impacting planned production by about 5,000 barrels a day for the rest of the year. In Montney, we continue completion activities on the 14-well pad and construction of the associated infrastructure with startup still on track for the fourth quarter. For the Lower 48 Big 3, second quarter production by assets was Eagle Ford at 221,000 barrels equivalent per day, Bakken at 98,000, and Delaware at 48,000, representing a 41,000 barrel a day increase from the first quarter to 367,000 due to strong execution and improved operational efficiency. We now expect Big 3 production in 2019 to average 360,000 barrels a day, up from our initial expectation of 350,000. This represents a growth rate of about 21% from 2018 to 2019 and an increase of over 60,000 barrels a day for the year. As Don mentioned, we made several royalty interest and acreage acquisitions across the Big 3 during the quarter. In Europe, as Don noted, the UK disposition continues to progress toward closing. We also completed a planned turnaround in the J-Area that was completed in July. In Norway, we completed the Greater Ekofisk area turnaround during the second quarter and sanctioned the Tor 2 fuel redevelopment project. This subsea production system tied back to Ekofisk is expected to come online at the end of 2020. In the third quarter, we will have more turnaround activity in Norway at our partner-operated assets. In Qatar, we remain very interested in participating in the North Field Expansion Project. Moving to Malaysia, production ramp-up at KBB continued, and flows through the Sabah-Sarawak Gas Pipeline recommenced, but we don't expect full ramp-up in production to be achieved until late in the year. Also in the quarter, KBB began delivering gas to a third-party floating LNG facility to help mitigate potential production disruptions through the pipeline. Finally, in Indonesia, the Ministry of Energy and Mineral Resources announced earlier this month that ConocoPhillips has been awarded a 20-year extension of our participation in the Corridor Block beyond the current contract expiring in December 2023. It's another quarter of strong execution and significant progress across the portfolio. Now let me discuss the outlook for the remainder of the year on Slide 8. As we progress through 2019, we are continuing our disciplined capital approach and making decisions to optimize the value of our high-margin assets. We are adjusting our full-year operating plan capital guidance from $6.1 billion to $6.3 billion, excluding acquisitions for the two unbudgeted activities. In Alaska, we'll spend about half of the incremental capital to conduct additional scope in our appraisal program, including a long-term test at the Putu horizontal appraisal well and the additional Narwhal appraisal well I mentioned earlier, as well as additional long lead items for the 2020 exploration and appraisal season. In the Eagle Ford, we've just started a rig to optimize rig count as we ramp towards the plateau phase of our development plans over the next few years, describing the basis for this optimization in more detail in November. The increased rate associated with this rig won't show up until 2020. Our 2019 operating capital guidance excludes acquisitions. To date, we have closed and announced both $300 million of transactions, including the Lower 48 acquisitions we've already mentioned and a low-cost entry into the Vaca Muerta shale play in Argentina. These represent opportunistic low-cost supply additions to our resource base. On the production side, we expect the third quarter to average between 1.29 million and 1.33 million barrels equivalent per day. You'll notice on the right side of this chart that we're narrowing the range in our full-year outlook because half of the year is behind us now but maintaining the midpoint in our previous guidance of 1.325 million barrels a day. While this might seem conservative considering our strong first half performance, we are not adjusting our full-year midpoint guidance for two reasons: First, we accelerated production vs our plan from the second half of the year into the first half, especially in the second quarter impacting growth from the Lower 48 Big 3. We now expect production levels for the remainder of the year to be flat, mostly growing to modestly growing levels from the increased rate we saw in the second quarter. The second factor is lower-than-expected performance in two areas: Surmont due to the mandated curtailments that are expected to continue through the year, and in Alaska, where one of the four production wells of the GMT1 project is performing below expectations. The increased production from the Lower 48 Big 3 in the first half of the year essentially helps offset these factors throughout the year. That's another great example of the value of diversification in our portfolio. We have a busy second half of the year with several turnarounds and the ramp-up of KBB production, so we don't think it's prudent to change full-year guidance at this time. To be clear, the original $6.1 billion operating plan capital is still delivering our planned 5% underlying production growth and with our planned buybacks, we expect to deliver 8% per debt-adjusted share growth. Also bear in mind that we are carrying the UK with all of these numbers. We will update production and other relevant guidance items at the close of the UK disposition. We are looking forward to your Analyst and Investor meeting on November 19 in Houston, where we will present a decade-long disciplined capital plan that delivers free cash flow and strong shareholder returns across a range of prices, providing a deep dive into our diverse portfolio assets. Our strong performance in the first half of the year highlights the strength of our portfolio diversity and our ability to generate free cash flow to support distinctive returns to shareholders. Our entire ConocoPhillips team is focused on successfully executing the second half of our 2019 plan and sharing our long-term plans with you in November. Now I’ll open up for Q&A.

Good morning, team and congrats on a good quarter here. I guess the first question is, you had really strong cash flow generation, part of it was led by the dividend payment out of APLNG and then the ability to pull cash from Venezuela. Can you talk about both of those line items? They're independently difficult to model the sizing and timing, and how we should think about that going forward?

Neil, this is Don. I'll take that one. Yes, cash flow was strong, and you pointed to a couple of the items that helped that. We did have strong distributions from APLNG totaling $320 million in the quarter. In the first quarter, I think it was $73 million, so for the first half, about $400 million. I think previously, maybe in the last call, I gave guidance to expect APLNG distributions of about $550 million to $600 million for the year. I need to probably bump that up a little bit, but I wouldn't take it as two times the $400 million; it won't be quite that high. But I think the new expectation on distributions for 2019 will be in the range of $650 million to $700 million. Now I’ve cautioned folks on this before, but I'll reiterate, these aren’t consistent across the quarters. The odd quarters, the first and third quarters are always going to be low because that’s when financing payments and tax payments occur, while the even quarters, the second and fourth, are relatively high. So as you're thinking quarter-to-quarter, you should expect the third quarter to be lower, and the fourth quarter to be higher. Regarding PDVSA, I think that's a very difficult one to give guidance on for modeling because we don't factor that into our cash forecast either. We only recognize the earnings and the cash as we receive it, and I think that's the appropriate way to view it considering the situation and the counterparty.

That's helpful. Then look, it's a small adjustment on CapEx from $6.1 billion to $6.3 billion, but certainly received some attention this morning. So can you just talk a little bit more about what drove the $200 million increase? When you think about the incremental rig in the Eagle Ford and the incremental spend in Alaska, why are those good incremental rate of return projects that help to lower the cost of the company?

Yes, I'll take that. So in Alaska, we've completed the off-ice appraisal season this winter, and the results we've seen from Willow and Narwhal are very encouraging. We're taking the opportunity to extend some of the appraisal from our existing drill sites in Alpine. For example, we've decided to conduct an extended well test on a horizontal appraisal, drilling into the Narwhal trend. The results of that well have been very encouraging, and we thought let’s see if we can conduct a long-term test to understand the long-term deliverability. So that's part of the increase. We can also drill an offset injection well from the same drill site, allowing us further information on the Narwhal trend. We're also firming up our plans for 2020, and we're going to have another aggressive appraisal and exploration season in 2020. This year was mostly focused on appraisal, so there are some long lead items to facilitate that. When we reach November, we will provide details on exactly what we've concluded from this year’s appraisal program, which is encouraging and has led us to want to accelerate some learning. In the Lower 48, we are continuously looking to optimize the value from our unconventional programs, and we’re specifically focused this year on establishing the optimum plateau rate for these unconventional activities. Ultimately, this led us to conclude that we should add a rig over time in the Eagle Ford. Thus, we're going to take the opportunity to add a seventh rig this year, potentially an eighth rig next year. While the seventh rig won't contribute to production until next year, it's part of a rational approach to establishing the best class rate for our unconventional plays.

Thanks. Good morning, everybody. Let's stay later this year, but in the last call, I seem to recall Ryan talking about trying to find a way to bring investors back to the sector. Over 30% of your cash flow is now returned to shareholders, and you've obviously exceeded that this quarter. My question really is the share price continues to languish along with the rest of the sector. What are you thinking in terms of how you differentiate your cash return? I think the expression that was used was how do you differentiate that? I'm thinking specifically about the prospect of a variable distribution, particularly in times when oil prices are elevated relative to what the market might think is sustainable. If you could share any thoughts on how you manage your own objectives there, I would appreciate it, and I have a follow-up.

Doug, this is Don. Let me take that one. Yes, we're trying to distinguish ourselves with our return of capital to shareholders. You saw the figures for the second quarter, and if you look at our $1.4 billion dividend and $3.5 billion of planned buybacks this year, that's $4.9 billion and let's just say you see maybe something around $12 billion of cash from operations, creating a return of approximately 40% cash return to shareholders for the year. We're trying to compete with the best capital returners in the business and certainly distinguish ourselves from other E&P companies out there. You mentioned variable dividends, and I would just say that we're always considering the best ways to return capital to shareholders, and we talk with the investment community to get feedback on their thoughts. We believe our current model of a meaningful common dividend and a significant level of buybacks that persist indefinitely is a very attractive capital return model. We’re always testing other ideas and will discuss this in more depth in November.

Yes, just a very quick follow-up comment on that. The cash return is terrific, as we all know, but your relative yield is where the pushback comes. So I'm just curious if there’s a difference. You never want to put yourself back in a position with a high ordinary dividend, but the buyback effectively replaced the delta between your prior and current dividend, leading to the challenge that your current yield is no longer competitive with companies having similar free cash flow capabilities. So just an observation; I’d be curious if you want to add any follow-up as to whether that's a consideration. I do have a follow-up.

Yes, those are always considerations, Doug. We continuously ponder the level of our distributions, the mix of our distributions between buybacks and cash returns in the form of dividends, and how best to distribute in periods of procyclicality. These are things the management team consistently challenges and questions, and we're looking forward to discussing more about this in November.

Okay. My follow-up—this should be a quick one. Matt, you mentioned you're still interested in Qatar LNG; I understand that things are at a confidential stage for the industry right now. But I'm curious, in a success case, would that be included in the sub-$7 billion multi-year capital plan, or would something like the potential liquidation of Cenovus provide a source for alternative funding if you're successful? I’ll leave it there. Thanks.

That is not included in the sub-$7 billion average capital plan. The only things we've factored in there are those we've already captured, and we don’t want to be presumptuous about whether or not we'll take a position in Qatar LNG. If we do secure a position there, we have ways of funding that incremental capital, but we didn't want to include it until it's confirmed.

Hi, yes. I guess the first question here would be a follow-up for Matt. You're making the comment about trying to align the rig counts in the Big 3 with an optimal long-term production plateau. I was wondering if you could elaborate on that a bit in terms of the three assets today. I know Bakken has been a flat asset for some time. Now you're adding to the Eagle Ford. So I'd be interested if you have updated thoughts on the Eagle Ford and even the Permian? Thanks.

Yes. We're going to give you more on this in November, but we see the Big 3 in quite different stages of their life cycle. Right now, Bakken is at our plateau, but based on the completions, it's been quite steady. We would expect it to be in the 80,000 to 90,000 barrel a day range for a long time to come, but we don't intend to pursue incremental growth there. The Eagle Ford is probably characterized as late-stage growth, and within the next few years, we will reach plateau there. The addition of the rig is to service the goal of reaching the optimum plateau and holding that for the maximum duration. The Permian for us is much earlier in its life cycle, so it has significant growth ahead of it, and it will be several years before we reach plateau there. We maintain a rigorous approach to this, and while it's too complex to explain in a phone call, we will elaborate on our strategy in November.

And just to clarify on Eagle Ford, is there a specific target you're thinking of that you could share, or would you rather wait for more context?

I think it's fair to wait to get the context for the whole picture, but it's fair to say that we are a few years from reaching plateau, so it will certainly plateau at a higher rate than where it is now, but we will share more of that in November.

Okay. And then just my follow-up is on the buyback. Don, maybe you could clarify a little bit. There's obviously a $500 million increase in the full-year, which you fully accomplished in the second quarter. Can you clarify how you're thinking about the back half? Is it just a case of what happens with prices, or is there some degree of conservatism there? Or was it intentional to step up in the second quarter? Just any thoughts you have about the progression you took. Thanks.

Yes, I think you can expect us to revert back to the $750 million a quarter that we've historically managed over the last couple of years. As for the $500 million increase in the second quarter, we intended to increase the buybacks for the year to $3.5 billion and had sufficient cash on hand to accomplish that, while recognizing a significant dislocation in our share price against Brent price correlation, the historical correlation. We felt the shares were selling at a large discount to intrinsic value, which is why we decided to be aggressive and spend that increment during the second quarter. We expect to go back to running at $750 million a quarter over the next two quarters, and we will talk about plans for 2020 and beyond as far as distributions in November.

Good morning, everybody.

Good morning, Doug.

Hi. This is probably for Don, but consensus expectations are for declining returns on capital and production growth for most E&P companies next year, which appears to be negatively affecting valuation and share prices in E&P sector. While you’ve differentiated yourselves with credible plans to sustain higher returns and grow shareholder distributions, delivering for several years, the message seems to be that lower spending in portfolio restructuring may be the optimal way to preserve value and share prices as the sector matures. My question is, when you consider this theme, alongside the quality of your investment opportunity set, does it change the way you think about future capital management, especially given your historic emphasis on returns on capital and trying to increase them?

I don't think it changes our thinking, Doug. Our strategy, which we defined in late 2016, was centered on capital discipline and balancing investments for growth while maintaining high returns of capital back to shareholders. We have seen good success from that strategy, and we have a lot of confidence in its continuing relevance going forward.

Good morning, all. The decision to increase CapEx this quarter could have been avoided if you were concerned about the optics of doing so. I'm just wondering why you couldn’t find a couple of hundred million dollars elsewhere, Matt, and stick to budget. Thanks.

Yes. We considered that, Paul. We really feel as if the original scope that we laid out for the assets should be delivered, and these opportunities for a modest increase in capital will be value-adding. We didn’t feel it was appropriate to stick to the capital program for the sake of doing that without recognizing the additional value we could create here. We made the decision to proceed. It’s a 3% increase in capital, not significant, but we believe those investments in Alaska and the Eagle Ford are something shareholders will support.

Yes, that’s kind of the point. It's a relatively minor amount. But I thought the optics would have been better if you'd had managed to stick with the number. Part of my reasoning for saying that is simply that you were running ahead of growth while doing strongly on growth, which again suggests perhaps you could actually work towards pulling back a bit on spending. Is that a fair assessment?

Yes, that's certainly a consideration. We exceeded our growth targets for the year, driven by significant outperformance in the second quarter primarily through the Big 3. But we still feel it’s prudent for us to maintain the full-year outlook as it was.

Understood. If I could ask just a quick one that you might not want to answer, along with a bigger question. Firstly, is there any timing on Qatar? Best guess? And secondly, where do you go from here on disposals after the North Sea? Thanks a lot.

We don't really have anything new to add to the timing expectations for Qatar. It's clear that Qatar gas is making progress on developing the project, but we can't provide any additional insights into the timing of when they select partners at this time. As for dispositions, yes, we have the UK disposition to close, and that's proceeding well. We have a few smaller dispositions in the works around the portfolio. If there’s anything significant to report on that front, we will inform you when we have something impactful.

Hi, everybody. A couple of questions. In the past, I think both of you had mentioned that Permian M&A doesn’t really complete on a cost-to-supply basis versus the portfolio interest. Are you seeing any changes in seller expectations, given the recent weakness in equity values? And then my follow-up, just to you now, on Corridor: the Indonesian PSC; I think you've mentioned previously that it was probably going to be quite challenging to renew. So I want to understand what changes have occurred and how that matches up on the costs of supply? Thank you.

Regarding your first question, if we've seen any changes in Permian seller expectations? We’re not active in that market asking sellers about their expectations, so we aren't seeing any significant changes from that perspective. We still believe there's a mismatch between what people expect for their assets and what we can compete for from a capital perspective, so that may shift over time. We're focusing on relatively small, but very high-value additions to our portfolio through the acquisitions we’ve announced over the past few months.

Hi, Alastair. It's Bill. I'm happy to discuss the Corridor extension. We were pleased with the Indonesian Minister of Energy and Mineral Resources' announcement that we would be awarded a 20-year PSC for the Corridor Block, allowing us to continue our presence in Indonesia for 45 years. This PSC starts in December 2023 and follows the expiry of the existing PSC. We will have a 46% working interest, which is prior to a 10% dilution for local governments required by regulations. This is a new growth split PSC, has a signature bonus of $115 million net to ConocoPhillips, and we expect to make that payment upon completion and definitive documentation. It also includes a commitment of about $100 million net framework commitment during the first five years of the new PSC. It's a robust low-cost supply extension, and we're pleased to have received this award.

Okay. Can I ask if net entitlement production will be lower going forward versus what you have today?

Yes, production will be a bit lower; our working interest is down about 13%, and it's on gross split terms.

Hey, guys, good afternoon. Two questions: one regarding the Permian; do you think now is the time, or do you have a timeline in mind for becoming more aggressive with activities there? And secondly, you've made comments about Austin Chalk. Based on what you see now, should we significantly downscale the potential over there, or are there still opportunities?

We will be increasing our activity in the Permian over time, moving from our current mode which is focused on ensuring that we optimize well spacing and stacking while addressing the various zones existing in our Permian acreage. Once we finalize that, we will increase our rig count toward a sustainable plateau. We plan to discuss this in more detail in November. So yes, we will ultimately become more aggressive in our development of the Permian resource. Regarding Austin Chalk, we've tested three of the four wells in that area, and while we've produced oil from those wells, they've also shown higher water cuts than we had hoped. The production rates we saw were just too low to justify further development, although we do have targets in other formations, such as Wilcox and Tuscaloosa Marine shale. Therefore, while the Austin Chalk doesn't look encouraging, the acreage is not condemned by that primary target.

Okay. Can I just sneak in a final real quick question? On the Eagle Ford for the second half of the year, are you simply being conservative, thus slowing down activity from the second quarter level?

Hey, Paul. It’s Dominic here. What we've observed in the Eagle Ford is an acceleration of wells coming online in the second quarter. The total wells online count we expect this year remains the same. Therefore, the growth profile is characterized by acceleration in the ramp up and a relatively flat outlook for the Eagle Ford for the remainder of the year.

Thanks. A question on Alaska: I’m curious about the timing of development or pre-FID developments. Initially, we thought about Willow being 2021 FID and perhaps Norwell and West Willow; does that still make sense? Where does Nuna fit into that development pipeline?

You're correct about the timing for Willow. With the positive results that Matt discussed from an exploration and appraisal perspective, we are encouraged. We are sizing facilities now and expect to reach FID in 2021, aiming for first oil from Willow in the 2025 to 2026 timeframe. Concerning Nuna, it’s a discovered resource on 21,000 acres adjacent to Kuparuk. It represents a low-cost potential in the low $30s, costing $100 million for 100 million barrels. We are very optimistic about this acquisition. We'll develop it using existing gravel pads and roads at Kuparuk, completing the remaining facilities during a single ice road season. We'll continue appraisal over the next couple of years, aiming for first oil in 2022. The process will utilize our existing drilling and completion technology and will integrate into the Kuparuk program, so it won't add to the total budget. We're excited about this low-cost supply addition.

Great. Thank you. And what about the 2020 exploration program? What's the focus?

We are currently developing plans for the 2020 exploration program, focusing on drilling at Willow to fully understand its extent for sizing the facilities. We also plan to drill several wells at a prospect to the Southwest, called Harpoon. That's the current plan, and we'll update you more on that in November.

Good morning. My first question is about some of the opportunistic bolt-on acquisitions, specifically in Argentina. What opportunity set do you see there longer term and how does it fit into your strategy, especially from a cost of supply or return standpoint against the other shales in your portfolio?

We've acquired a 25,000-acre position in Vaca Muerta, which closely resembles characteristics of both the Eagle Ford and Permian, having multiple stacked layers. It’s a promising geography and might yield over 0.5 billion barrels of potential on acreage we’ve secured. We view Vaca Muerta as the best international unconventional play outside of North America and believe it’s a low-cost entry into the basin with manageable work commitments over the next few years.

Got it. That's helpful. My second question is on Alaska. You mentioned in the prepared remarks some issues at one of the wells in the GMT development. Could you quantify the impact a bit more, what you're seeing there, and if there’s an opportunity to remediate that or offset that either later this year or perhaps in 2020 or beyond?

We've experienced underperformance at GMT 1; it was initially brought online last year and ramped up to plateau. Given it's a smaller development with only four producers, any single underperformer severely impacts overall production, which has been the case here. Despite the setbacks, with the capital reductions while executing the project, we actually delivered it within expected costs. We don’t see remediation at this stage, but we are advancing our GMT 2 plans, applying our learnings from GMT 1 to this different reservoir.

Yes. Thanks. On Canada, Matt, you talked about using alternative diluents, which would improve the netbacks going forward. Can you quantify how much incremental income or revenue you expect to see from that?

With the diluent project, the potential year-on-year improvement could be $1 to $2 a barrel. We're looking at an overall blend ratio improvement of about 35%, which could yield an increase of several dollars a barrel.

One key advantage here is flexibility; as Michael emphasized, it could be $1 or $2, or potentially more depending on market dynamics. We can optimize our blending strategy to capture the best values and unlock considerable long-term value.

Okay. Thanks for that clarity. One quick question, as discussed last quarter, do you have any excess gas firm in the Permian? Were you able to take advantage of weak pricing, and what capacity do you currently hold for that?

Yes, Scott, this is Don. Some of the specifics you're asking for are fairly commercial and thus we can't disclose much. However, I can say our offtake out of the Permian is substantially larger than our required equity production. We've managed to take advantage of low Waha prices, which averaged around negative $0.01 in the second quarter. We purchase gas within the Permian, transport it west, and capture a margin on that activity. The second quarter didn't see as much activity for us as the first quarter, but this situation will continue until new pipelines, like Gulf Coast Express, come online later this year.

Thanks for taking my question. One more point about the prior inquiry regarding gas: what's the latest you're seeing about flaring, particularly in the Permian given ongoing capacity constraints?

Well, yes, that’s a fair point. From our perspective, we don't face significant challenges since we have excellent offtake, as Don discussed. The crux of the matter is the timeline for new gas export capacity. There are significant pipelines anticipated to come online by the end of this year, followed by more thereafter, which means we expect the situation to improve quite soon.

I'm sorry if you covered this earlier, but I noticed your income tax for Q2 was 22%, the lowest in about eight quarters. Were there any special moving parts that explain why it was so low?

Yes, Pavel, that’s correct. Our reported effective tax rate was 22% during the quarter due to a number of special items. We provide supplemental information regarding our reported ATRs and our adjusted ATRs—which were about 40%, a typical range for us. So the differences between those rates can be attributed to special items where no tax or minimal tax applies. For example, in that quarter, we had significant tax benefits associated with the UK sale; being a tax benefit, it incurs no tax. Other earnings from equity affiliates don’t reflect in our corporate level taxes. This quarter's special items with low or zero tax rates gravitated our reported ATR downward.

Sanera, this is Ellen. It sounds like we’re out of questions.

Okay, everybody. Thank you very much for joining us today. If you have any follow-up questions after the call, feel free to reach out to us. Thank you for your ongoing interest in ConocoPhillips.