Hess Corporation

Good day, ladies and gentlemen, and welcome to the first quarter 2019 HESS Corporation Conference Call. My name is Amanda, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a -and-answer session. If at any time you require operator assistance, please press star followed by zero, and we will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I will now turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, Amanda. Good morning, everyone, and thank you for participating in our first quarter earnings conference call. Our earnings release was issued this morning and appears on our website, .hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the Federal Securities Laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the risk factor section of HESS's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss our non-GAAP financial measures, a reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Now, as usual with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Riley, Chief Financial Officer. I will now turn the call over to John Hess.

Thank you, Jay. Welcome to our first quarter conference call. I will review our continued progress in executing our strategy. Greg Hill will then discuss our operating performance and John Riley will review our financial results. Our company delivered strong performance this quarter. Our portfolio, which is balanced between our growth engines in Guyana and the Bakken and our cash engines in the deep border Gulf of Mexico and the Gulf of Thailand, is positioned to deliver approximately 20% compound annual cash flow growth and more than 10% compound annual production growth through 2025 at a $65 per barrel Brent oil price. In addition, we project that our portfolio, Breakeven, will decrease to less than $40 per barrel Brent by 2025. A key driver of our strategy is offshore Guyana, an extraordinary investment opportunity that advantage by its scale, reservoir quality, low cost, rapid cash paybacks, and superior financial returns. The Stabrook Block in Guyana, where Hess has a 30% interest in ExxonMobil, is the operator, covers 6.6 million acres, and contains a massive world-class resource that keeps getting bigger and better. We continue to have exploration success on the block with three new discoveries since the start of 2019 at Tilapia, Hamiro, and Yellowtail. Last Thursday, we announced that the Yellowtail Number 1 well, located about six miles from Tilapia, encountered approximately 292 feet of high-quality oil-bearing sandstone reservoir. This discovery is the fifth in the greater turbo area, which is expected to become another major development hub. In February, we announced that the Tilapia Number 1 well encountered approximately 305 feet of high-quality oil-bearing sandstone reservoir, the thickest net pay of any well yet drilled on the block. Tilapia is located approximately three miles west of the Longtail Number 1 well, which is also in the greater turbo area. In February, we also announced that the Hamiro Number 1 well, located in the southeastern part of the block, encountered approximately 207 feet of high-quality -condensate-bearing sandstone reservoir. We have now made 13 significant discoveries on the block since 2015, which will underpin at least five floating production storage and offloading vessels to produce more than 750,000 gross barrels of oil per day by 2025. Gross discovered recoverable resources on the block are estimated to be more than 5.5 billion barrels of oil equivalent, with multi-billion barrels of future exploration potential remaining. The Lisa Phase 1 development is progressing well and remains on track to achieve first oil by the first quarter of 2020, less than five years after discovery. This phase will develop approximately 500 million barrels of oil utilizing the Lisa Destiny FPSO, which will have the capacity to produce up to 120,000 gross barrels of oil per day. The Lisa Phase 2 development will use the Lisa Unity FPSO, which will have the capacity to produce up to 220,000 gross barrels of oil per day, with startup expected by mid-2022. A final investment decision is expected soon, subject to government and regulatory approvals. Planning is also underway for a third phase of development at the Giant Payara Field, which is expected to have the capacity to produce between 180,000 and 220,000 gross barrels of oil per day from a third FPSO. Sanction is expected to occur before the end of this year with first oil in 2023. Also key to our long-term strategy is the Bakken, where we have a 15-year inventory of high-return drilling locations. Our transition this year to -and-perf completions from our previous 60-stage sliding sleeve design is expected to increase the net present value of the asset by approximately $1 billion. Bakken net production is expected to grow approximately 20% per year to 200,000 barrels of oil equivalent per day by 2021, generating approximately $1 billion of annual free cash flow post-2020 at a $60 per barrel WTI oil price. Now turning to our financial results. In the first quarter of 2019, we posted net income of $32 million, or $0.09 per share, versus an adjusted net loss of $72 million, or $0.27 per share, in the year-ago quarter. Compared to 2018, our first quarter financial results primarily reflect our strong production performance, which was partially offset by lower oil prices and higher DD&A expenses. First quarter net production averaged 278,000 barrels of oil equivalent per day, excluding Libya, above our guidance of approximately 270,000 barrels of oil equivalent per day, and up from 220,000 barrels of oil equivalent per day in the year-ago quarter, pro forma for the sale of our Utica joint venture interests. Bakken net production averaged 130,000 barrels of oil equivalent per day, up from 111,000 barrels of oil equivalent per day in the first quarter of 2018. In closing, our company remains committed to executing our strategy that will deliver increasing financial returns, visible and low-risk production growth, and accelerating free cash flow well into the next decade. I will now turn the call over to Greg for an operational update.

Thanks, John. I'd like to provide an update on our progress in 2019 as we continue to execute our strategy. Starting with production, in the first quarter net production averaged 278,000 barrels of oil equivalent per day, excluding Libya, which was above our guidance of approximately 270,000 barrels of oil equivalent per day, reflecting strong operating performance across our portfolio. In the second quarter, we expect net production to average between 270,000 and 280,000 barrels of oil equivalent per day, excluding Libya. This reflects the impact from planned shutdown and maintenance activities at North Malay Basin in Malaysia and at the tubular wells and bald-pate fields in the Gulf of Mexico, all of which was included in our full-year guidance that we provided in January of 270,000 to 280,000 barrels of oil equivalent per day, excluding Libya. As usual, we will update our full-year guidance on our second quarter call in July. In the Bakken, we delivered a strong quarter, capitalizing on the success of our new -and-perf completion designs. Despite severe weather conditions in the Williston Basin in February, first quarter production averaged 130,000 net barrels of oil equivalent per day, an increase of more than 17% from the year-ago quarter and within our guidance range of 130,000 to 135,000 net barrels of oil equivalent per day. In the first quarter, we drilled 38 wells and brought 25 wells online. Weather conditions in the Basin have improved, and in the second quarter, we expect to drill approximately 40 wells and to bring online approximately 45 new wells. For the full year 2019, we still expect to drill about 170 wells and bring 160 wells online per our January guidance. In the second quarter, we forecast that our Bakken net production will average between 135,000 and 140,000 barrels of oil equivalent per day, and for the full year 2019, we continue to forecast production to average between 135,000 and 145,000 barrels of oil equivalent per day, approximately 20% above 2018 levels. Moving to the offshore, first quarter production performance was strong in our Gulf of Mexico and Malaysia-Thailand assets. In the Deepwater Gulf of Mexico, net production averaged 70,000 barrels of oil equivalent per day, and in the Gulf of Thailand, net production averaged approximately 68,000 barrels of oil equivalent per day. Now turning to Guyana. Our exploration success on the Stay Brook Block continues with three new discoveries so far in 2019 at Tilapia, Himara, and Yellowtail, bringing the total number of discoveries on the block to 13. In terms of drilling activities, the Stenekaren recently completed a drill stem test at Longtail and is now drilling the top hole section of Hammerhead 2, after which it will begin drilling Hammerhead 3. Following the completion of all operations at Yellowtail, the noble Tom Madden will drill out Hammerhead 2. Results from these tests will provide data for the operator to size an optimized plan of development for this area. Drilling plans for 2019 also include a second well at Ranger and three additional exploration wells, the locations of which are being finalized. Now turning to our Guyana developments, Liza phase 1 is progressing to schedule. At the Keppel Yard in Singapore, installation of topside modules is now complete on the 120,000 barrels of oil per day Liza desk in the FPSO, and commissioning activities are underway. The vessel is expected to arrive offshore Guyana in the third quarter of 2019. Drilling of the phase 1 development wells is proceeding and installation of subsea infrastructure is well advanced, with installation of subsea umbilicals, risers and flow lines planned for the second quarter. We are on track to achieve first oil by the first quarter of 2020. Liza phase 2 will utilize the Liza Unity FPSO, which will have the capacity to produce up to 220,000 barrels of oil per day. Six drill centers are planned, with a total of 30 wells, including 15 production wells, 9 water injection wells and 6 gas injection wells. Government and regulatory approvals are expected soon, after which final project sanction will be taken. First oil remains on track for mid-2022. A final investment decision is also expected later this year for a third phase of development, PIARA, which is expected to have a gross capacity of between 180,000 and 220,000 barrels of oil per day with startup as early as 2023. In closing, our team once again demonstrated excellent execution and delivery across our asset base. Our offshore cash engines continue to generate reliable cash flow. The Bakken is on a strong capital efficient growth trajectory and Guyana continues to get bigger and better, which in combination position us to deliver industry leading returns, material cash flow generation and significant shareholder value for many years to come. I will now turn the call over to John Riley. Thanks, Greg.

In my remarks today, I will compare results from the first quarter of 2019 to the fourth quarter of 2018. We reported net income of $32 million in the first quarter of 2019 compared to an adjusted net loss of $77 million in the fourth quarter of 2018. Turning to E&P, E&P had net income of $109 million in the first quarter compared to a net loss of $109 million in the fourth quarter of 2019. The E&P results between the first quarter of 2019 and the fourth quarter of 2018 were as follows. Lower exploration expenses increased earnings by $57 million. Lower cash costs increased earnings by $37 million. Lower DV&A expense increased earnings by $35 million. Changes in sales volumes increased earnings by $7 million. Lower realized selling prices decreased earnings by $9 million. All other items decreased earnings by $13 million for an overall increase in first quarter earnings of $114 million. Turning to Midstream, the Midstream segment had net income of $37 million in the first quarter of 2019 compared to $32 million in the fourth quarter of 2018. Midstream EVITA, before non-controlling interest, amounted to $129 million in the first quarter compared to $127 million in the previous quarter. For corporate, after-tax corporate and interest expenses were $114 million in the first quarter of 2019 and $104 million on an adjusted basis in the fourth quarter of 2018. Turning to our financial position, at quarter end, cash and cash equivalents were $2.3 billion excluding Midstream and total liquidity was $6.7 billion including available committed credit facilities while debt and finance lease obligations totaled $5.7 billion. In April, HES entered into a new fully undrawn $3.5 billion revolving credit facility that matures in May 2023 and replaces our previous credit facility that was scheduled to mature in January 2021. Cash flow from operations before working capital changes was $635 million while cash expenditures for capital and investments were $678 million in the first quarter including cash consideration of $89 million for the midstream assets acquired from Summit. Changes in working capital decreased cash flows from operating activities by $397 million in the first quarter. This included a one-time repayment of approximately $130 million to our joint venture partner for each year of sale leaseback proceeds related to our sale of the North LA basin floating storage and offloading vessel which was completed in the third quarter of 2018. The remaining working capital items included semi-annual interest payments on debt, an increase in accounts receivable and a reduction in accounts payable. In the first quarter, we adopted the new lease accounting standard which resulted in the recognition of operating lease liabilities of approximately $800 million on our consolidated balance sheet. The adoption does not impact our P&L or cash flow. Turning to guidance, our first quarter production, cash unit costs and capital and exploratory expenditures beat guidance and position us favorably for the full year. As is our normal practice, we will update full year guidance on our second quarter conference call. With respect to the second quarter, as Greg mentioned, we expect production and cash unit costs to be impacted by planned maintenance shutdowns at North LA basin and at the tubular bells and ball-paid fields. These planned shutdowns were incorporated in our full year guidance provided in January. We project E&P cash costs excluding Libya to be in the range of $13 to $14 per barrel of oil equivalent in the second quarter of 2019 up from $11.54 per barrel of oil equivalent in the first quarter, reflecting higher costs for the planned maintenance shutdowns and higher second quarter work over activities in the Bakken, including weather related deferrals from the first quarter. DD&A expense excluding Libya was $18.37 per barrel of oil equivalent in the first quarter of 2019 and is forecast to be in the range of $18 to $19 per barrel of oil equivalent in the second quarter of 2019. This results in projected total E&P unit operating costs excluding Libya of $31 to $33 per barrel of oil equivalent for the second quarter. Exploration expenses excluding dry hole costs are expected to be in the range of $45 to $55 million in the second quarter and the midstream tariff is expected to be approximately $170 million in the second quarter. The E&P effective tax rate excluding Libya is expected to be in expense in the range of 5 to 9% for the second quarter. Our 2019 crude oil hedge positions remain unchanged. We have 95,000 barrels of oil per day hedged for calendar 2019 with $60 WTI put option contracts. We expect option premium amortization to be approximately $29 million per quarter in 2019. E&P capital and exploratory expenditures are expected to be approximately $750 million in the second quarter, which includes drilling the Lano 5 well in the Gulf of Mexico that was deferred from the first quarter and drilling and completing more wells in the Bakken with tough winter conditions behind us. For midstream, we anticipate net income attributable to HES from the midstream segment to be approximately $35 million in the second quarter. For corporate, for the second quarter of 2019, corporate expenses are estimated to be in the range of $25 million to $30 million and interest expense is estimated to be in the range of $80 to $85 million. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

Ladies and gentlemen, if you have a question, please press star followed by 1 on your phone. If your question has been answered or you would like to withdraw your question, press the pound key. Questions will be taken and the order received. Please press star 1 to begin. Your first question comes from the line of Bob Braggate of Brinchstone Research. Your line is open.

Hi, good morning. I'll start by observing that it took 22 days to drill Yellowtail and then from that start to think about the cadence of what you're doing this year in terms of the exploration program and how do you feel about the commentary with ExxonMobil potentially adding a fourth exploration drill ship?

Yeah, thanks Bob. Yes, ExxonMobil has indicated they do plan to add a fourth rig to the theater. However, the drilling sequence and all that, we're still working out with the operator. I think they announced it will come into the theater sometime in September, but what gets drilled on our block and their other blocks, joint blocks, we're still working that out with the operator. So stay tuned on that.

In terms of once Hammerhead 2 and Hammerhead 3 are appraised, what are the Tom Madden and the Santa Karen going to do? Have you decided? Well,

yes. I think as I mentioned in my opening remarks, we definitely want to get a second well down at Ranger and then we have three other exploration wells right now, the sequence of which are being worked out between us and the operator. Also, depending on success and what you find, remember you might have an appraisal well or testing or whatever as success continues on the block. Thanks.

Thank you. And your next question is from the line of Aaron J. Rome of JPMorgan. Your line is open.

Good morning. Greg, I was wondering if you could detail maybe the objectives at Hammerhead 2 and 3 and also maybe give us a little bit more color on Hamara 1 and if you guys tested the deeper objectives at Hamara.

So let me start with the appraisal wells. Obviously, the objective of those is to understand the extent of the reservoir and continuity of the reservoir. So that's really the purpose. Hamara, that will feature later in the sequence. Again, I think the plan is to have some appraisal wells there as well, but the sequence and cadence of when that comes, again, we're still working all that out with the operator.

Fair enough. And did you all test anything deeper at Hamara or is that going to be on the next potential well?

That will probably be subject to later appraisal.

Fair enough. Greg, switching gears to the Bakken, I was wondering if you could highlight any of the testing that you planned at Goliath and Red Sky. And also, we also noted this week that you had what we think is maybe a record kind of Bakken completion at Bombeck. I don't know if you could maybe comment a little bit on that well, which kind of hit the state. I think it had an IP in the 10,000 BOE range.

Yeah, let me start with the Bombeck well test. Why did we do that? It was really designed to better understand open flow potential and it was a great result because we believe that we achieved the highest IP 24 ever recorded for a U.S. onshore well and that was some 14,600 barrels of oil equivalent per day. Now, while we achieved a very high IP rate and it confirmed that our acreage performed very strongly in comparison to other operators, we don't think this completion technique will be the standard practice just simply due to the higher costs and inefficiencies. But, again, it was a great well, great result. Regarding the testing in the Goliath acreage, as we kind of said earlier in the year, we will drill 25 wells or so outside the core areas this year. And that's really just to begin to establish what completion practices do we want in different parts of the field. Our current standard design is a 36 stage with about 280 entry points. We know that that can vary as we get out to other areas of the field. So we really want to get some wells out in that area to begin to understand and optimize what completion designs will be because obviously in the future those will feature in our inventory so we want to get ahead of that. Great. Thanks a lot.

Thank you. And your next question is from the line of Devon McDermott of Morgan Stanley. Your line is open.

Good morning. Thanks for taking the question. Morning. My first question is on Guyana and it's given the continued success there, incremental discoveries, growing resource size. I just wanted to talk at a high level about how that might impact the long-term development plan which I'm sure is still in flux but what I'm thinking about is specifically how the potential might be for parallel developments, tie backs or better use of shared infrastructure that might drive down the cost over time or improve returns on development of future phases.

And Devon, good question. Obviously a lot of our work this year is to do further appraisal to start to get more clarity on the answer to your question. ExxonMobil is the operator and we're working closely with them or trying to optimize what that development will be. Obviously with the bigger resource, we're still looking at phasing but it is possible that we will be more than five ships going forward to produce oil but the key is going to be doing further appraisal on the resource that we have and evaluation work to really optimize what the ultimate development will be. So work in progress.

Got it. Makes sense. And then shifting over to the Bakken as you noted on the call and one of the previous questions, the results there need to be strong and even with the weather issues that we've seen in the past quarter, you guys came in within guidance. I'm just wondering if you could give an update on what you're seeing there as you roll out the plug and perf completions across all of your wells relative to the guidance and base planning you all laid out last year.

Yeah, I think as you mentioned, we did have good performance in the first quarter in spite of the bad weather. We actually got 10 wells less online than what was in our plan but still were able to stay within guidance. We guided that these high intensity plug and perf completions are delivering a 15 to 20 percent increase in IP180 and a 5 to 10 percent increase in EUR versus that previous sliding 60 state sliding sleeve design. We're confirming those results. I mean, we're well within that range because where we were drilling in the first quarter was a little better than that but that's still going to be our guidance for the year. And as John mentioned in his opening remarks, this is going to increase BAC and NPV by over a billion at $60 WTI. So far so good. We're very pleased with the results. Great. Thank you.

Thank you. And your next question comes from the line of Doug Leggiet of Bank of America. Your line is open.

Good morning, guys. This is John Abbott on for Doug Leggiet. Doug is currently on a plane. Doug is currently on a plane flying back from the Destiny FPSO. I'm sure he's listening in on the plane if the Wi-Fi is working. He has sent me a list of questions. His first being, it is his belief that the FPSO will sell in mid-June and likely be in the United States in August. Can you now confirm that first oil may possibly start before the end of the year?

Well, I think, you know, as we said in our opening remarks, we expect first oil by first quarter 2020. The project is going well. The project is ahead of schedule. There is a chance that it will be on before that. You know, I think it's the reason that there's a little bit left in the schedule is because we start all the open water activities. So I think it's prudent, you know, to stick with our by first quarter 2020 for now until everything shows up in theater and you start the open water work.

Appreciate it. And his second question is on hedging. You're fully hedged onshore for 2019 with $60 million of floors. But you've also said at $60 oil in the bucket, you can generate around $450 billion of free cash in 2020 at $60. Given that oil is trading above that level now, how should we think about your hedging strategy going forward as it seems to us you have a chance to draw an early line under any future cash burn?

Thanks. So just like you said, we are well positioned here for this year and 2019 with our hedges that are 95,000 barrels a day to put options at a $60 WTI floor. So we're comfortable and well positioned in 2019. To your point, it is our intention to add positions for 2020, obviously depending on market conditions. We do not have any 2020 positions on right now, but it is our intent to add that just like you said to draw that line on the line in the sand, ensure that we have the strong cash flow next year as we continue to invest in Guyana and bucket.

Wow, we appreciate it. Thank you for taking our questions. Thank you.

Thank you. And your next question comes on from the line of Brian Singer of Goldman Sachs. Your line is open.

Thank you. Good morning. I wanted to just follow up on the topic of oil prices, maybe a little bit less on the hedging front, but more if these oil prices hold likely higher relative to what was originally anticipated. Can you just talk about the strategy for use of excess cash in terms of either returning to shareholders paying or investing in the business?

Yeah, Brian, our first priority, as you know, is to make sure we have a strong financial position and cash position to fund the first ship in Guyana, the second ship in Guyana and the six week program we have in the bucket. So the strong cash position will be prioritized for investing in those high return projects.

Great, thanks. And then my follow up is in Guyana. Can you just talk and compare and contrast what you're seeing so far in the Tilapia yellow tail area with the strong thickness of pay in comparison to say what you see at Liza? I know there's a knowledge difference right now, but a little bit of a compare and contrast would be helpful.

No, I think the yellow tail was a great result. It had high net to gross. As John mentioned in his opening remarks, 292 feet of that. Well at good porosity and it's got good oily fluids that are Liza-like. So yellow tail is closer to Liza from a geologic standpoint, and so we're very pleased with that result.

Great, thank you. And then Tilapia nearby?

Tilapia, again, a very good well, you know, 305 feet, very high quality oil bearing sandstone reservoir. So we're also very pleased with that also. I think the key point here is both of

those wells that we talked about are very oily, high quality oil, and really increase our confidence that the greater turbo areas should underpin the fourth and fifth FPSOs that are being contemplated.

Thank

you.

Thank you. And our next question is from the line of Jeffrey Campbell of Tui Brothers, and your line is open.

Good morning, and congratulations on the continued success in Guyana. Thank you. To that point, I just wanted to, it's kind of asking something that was asked before, but I just want to ask it a different way. It appears that you may have actually discovered additional Guyana oil resources beyond what might have been currently earmarked for the development plan through 2025, and that may not be right, you can tell me, but I was wondering if exploration success continues, could this potentially expand the plans into 2025, or is it more likely that it becomes longer-dated oil?

No, you know, again, we're optimizing our plans. The first three ships are very much defined. The fourth and fifth ship, you know, we still have more appraisal work to do. We're also looking at a hammerhead, how that might fit in the queue, but since this is a phased development, it's very manageable from a financial perspective and very much aligned with the financial outlook we gave out to 2025 in our investor day in December.

Okay, thank you. I appreciate that. And I just want to turn quickly to North Malay. When noted the output increase, I was under the impression we were already close to near peak, but that obviously wasn't the case. I was just wondering, is future growth beyond what we saw in the first quarter expected at some point, or are the volumes getting near their ceiling?

Really, what you saw in the first quarter were increased nominations, above typical nominations. Now the field, as you can see, has the capability of delivering that, but it's really based on local demand. So what I would say is you should expect that nominations to come down. We are expecting that. That's part of our second quarter forecast, is to have some of that demand for the nominations come down a bit. But the field, to your point, is performing very well and has the availability to produce at a higher level should the demand be there. Okay, great. Thanks for the clarification.

Thank you. Our next question comes from the line of Pavel Multinal of Raymond James. Your line is open.

Thanks for taking the question. I don't think anyone's asked yet about the midstream. You guys had a pretty sizable drop down a few months ago, if I'm not mistaken, the largest drop down since the MLP originally went public. What's the expectation for additional drop downs beyond the organic expansion that I know you guys announced this morning?

Yes, so you're right. We did, in the first quarter, we sold our water business or dropped that down into the upper tier of the midstream JV. So that was completed in the first quarter. And then also in the first quarter, the midstream did acquire some other North Dakota transportation assets from Summit midstream partners. So they did that. They've been busy. And as you know, you mentioned that we are expanding our Tioga gas plant from 250 to 400 million scuffs. So there's a lot of activity and there's a lot of demand for our infrastructure up in North Dakota. So we're well positioned for it. And we're excited actually for the increase in the gas plant. As far as other assets, we do have other assets in North Dakota. And actually outside of North Dakota, we've talked about the Gulf of Mexico as well that could be dropped in. So we'll continue to look at that and we'll put assets into the midstream over time. But as of right now, nothing immediate, I would tell you.

Okay. And when I look at the guidance for the midstream tariff starts at you did 162 million in Q1, guiding to 170. So the implied run rate for the second half of the year is about over 200 million per quarter. Is that right? And what explains the increase?

So we will have a significant, you know, begin to get significant increase of throughput capacity when the Little Missouri 4 plant comes online. And that is expected to come online in the third quarter. So the midstream we'll see. And it's not just HES, it's third parties as well utilizing our additional capacity at the Little Missouri plant. So it is just a throughput increase that will increase that tariff, some of it being HES related and some of it being third party. All right. Helpful. Appreciate it. Thank you.

Thank you. And our next question comes from the line with Ross Payne of both Fargo Securities. Your line is open.

Thank you. Nice job guys across the board. Can you speak to the process to sanction Lisa 2 and any governmental challenges you expect to get that sanctioned and permitted? And second of all, what's the latest news on the no confidence vote and does that have any impact on future permitting? Thanks.

No, I think I'll talk to phase two and John will speak to the no confidence vote. But, you know, on phase two, as we said in our opening remarks, the approval is imminent. So we don't expect any issues. In

terms of the no confidence vote, as you probably are aware, the no confidence vote was overturned in court. It's now going to a higher court to have that ruling upheld. We expect that to occur during the month of May. And I can assure you the current government is running their approval process in the normal course of business and we don't see the no confidence vote or the overturn of the no confidence vote of having any impact in the day to day running of the Guyanese government and their oil affairs.

Excellent. Okay. Thanks so much guys.

Thank you. This concludes today's conference. Thank you for your participation. You may now disconnect. Everyone have a great day.