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Hess Corp  (NYSE:HES)
Q1 2019 Earnings Call
April 25, 2019, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

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. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Jay Wilson -- Vice President of Investor Relations

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, www.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 Factors section of Hess' annual and quarterly report filed with the SEC.

Also, on today's conference call, we may discuss certain 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 Rielly, Chief Financial Officer. I'll now turn the call over to John Hess.

John Hess -- Chief Executive Officer

Thank you, Jay. Welcome to our first quarter conference call. I will review our continued progress and executing our strategy. Greg Hill will then discuss our operating performance, and John Rielly 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 deepwater 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 and an extraordinary investment opportunity that is uniquely advantaged by its scale, reservoir quality, low-cost, rapid cash paybacks and superior financial returns.

The Stabroek Block in Guyana, where Hess has a 30% interest and 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 3 new discoveries since the start of 2019, at Tilapia, Haimara and Yellowtail. Last Thursday, we announced that the Yellowtail number 1 well, located about 6 miles from Tilapia, encountered approximately 292 feet of high-quality oil-bearing sandstone reservoir.

This discovery is the fifth in the greater Turbot 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 3 miles west of the Longtail number 1 well, which is also in the greater Turbot area.

In February, we also announced that the Haimara number 1 well, located in the southeastern part of the block, encountered approximately 207 feet of high-quality gas condensate-bearing sandstone reservoir.

We have now made 13 significant discoveries on the block since 2015, which will underpin at least 5 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 multibillion barrels of future exploration potential remaining.

The Liza Phase 1 development is progressing well and remains on track to achieve first oil by the first quarter of 2020, less than 5 years after discovery. This phase will develop approximately 500 million barrels of oil, utilizing the Liza Destiny FPSO, which will have the capacity to produce up to 120,000 gross barrels of oil per day.

The Liza Phase 2 development will use the Liza Unity FPSO, which will have the capacity to produce up to 220,000 gross barrels of oil per day with start-up expected by mid-2022.

A final investment decision is expected soon subject to government and regulatory approvals.

Planning is also under way for our 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 plug 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 a 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 interest. 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.

Greg Hill -- Chief Operating Officer

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 plant shutdown and maintenance activities at North Malay Basin in Malaysia and at the Tubular Bells and Baldpate 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 plug 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 Stabroek Block continues with 3 new discoveries so far in 2019 at Tilapia, Haimara and Yellowtail, bringing the total number of discoveries on the block to 13.

In terms of drilling activities, the Stena Carron recently completed a drill stem test at Longtail and is now drilling the top-hole section of Hammerhead-2, after which we will begin drilling Hammerhead-3.

Following the completion of well operations at Yellowtail, the Noble Tom Madden will drill out Hammerhead-2. Results from these tests will provide data for the operator to size and optimize the plan of development for this area.

Drilling plans for 2019 also include a second well at Ranger and 3 traditional 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 barrel of oil per day Liza Destiny FPSO and commissioning activities are under way. 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. 6 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 the third phase of development at Payara, which is expected to have a gross capacity of between 180,000 and 220,000 barrels of oil per day, with start-up 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 Rielly.

John Rielly -- Chief Financial Officer

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 $5 million in the previous quarter.

The changes in the after-tax components of 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 DD&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 EBITDA, before noncontrolling 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, Hess 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 flow 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 its share leaseback proceeds related to our sale of the North Malay Basin floating storage and offloading vessel, which was completed in the third quarter of 2018.

The remaining working capital items included semiannual interest payments on debt and 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 cost to be impacted by planned maintenance (ph) shutdowns at North Malay Basin and at the Tubular Bells and Baldpate fields. These plant 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 cost 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 cost, excluding Libya, of $31 to $33 per barrel of oil equivalent for the second quarter.

Exploration expenses, excluding dry-hole cost, are expected to be in the range of $45 million 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 an 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 Llano-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 Hess 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 expenses estimated to be in the range of $80 million to $85 million.

This concludes my remarks. We'll be happy to answer any questions. I will now turn the call over to the operator.

Questions and Answers:

Operator

(Operator Instructions) Your first question comes from the line of Robert Brackett of Bernstein Research. Your line is open.

Robert Alan Brackett -- Bernstein Research. -- Analyst

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 drillship?

Greg Hill -- Chief Operating Officer

Yes. Thanks, Bob. Yes, ExxonMobil has indicated they do plan to add a 4th rig to the theater. However, the drilling sequence and all that, we're still working out with the operator. I think they announced, they 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.

Robert Alan Brackett -- Bernstein Research. -- Analyst

And in terms of once Hammerhead-2 and Hammerhead-3 are appraised, what are the Tom Madden and the Stena Carron going to do, have you decided that?

Greg Hill -- Chief Operating Officer

Well. Yes, I think in the -- as I mentioned in my opening remarks, we definitely want to get a second well down at Ranger and then we have 3 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.

Operator

And your next question is from the line of Arun Jayaram of JP Morgan. Your line is open.

Arun Jayaram -- JP Morgan -- Analyst

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 Haimara 1? And if you guys tested the deeper objective at Haimara?

Greg Hill -- Chief Operating Officer

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. Hamaira, 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.

Arun Jayaram -- JP Morgan -- Analyst

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

Greg Hill -- Chief Operating Officer

That will probably subject to later appraisal.

Arun Jayaram -- JP Morgan -- Analyst

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 -- we think it maybe a record kind of Bakken completion at Bomback. 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?

Greg Hill -- Chief Operating Officer

Yes. Let me start with the Bomback (ph) well test. Why we'd do that? It was really designed to better understand the open flow potential. And it was a great result because we believe that the well 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 what we achieved a very high IP rate, and it confirmed that our acreage performs 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 cost and inefficiencies. But again, it was a great well, great result.

Regarding the testing in the Goliath acreages. 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 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're 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 is, those will feature in our inventory, so we want to get ahead of that.

Operator

And your next question is from the line of Devin McDermott of Morgan Stanley. Your line is open.

Devin McDermott -- Morgan Stanley -- Analyst

Good morning. Thanks for taking the question. Morning. So my first question is on Guyana, and 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 longer-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 pellet developments, tiebacks or better use of shared infrastructure that might drive down the cost over time or improve returns on development in future phases?

John Hess -- Chief Executive Officer

Yes. Devin, 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 a bigger resource, we're still looking at phasing. But it is possible that we will be more than 5 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.

Devin McDermott -- Morgan Stanley -- Analyst

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 continue to be strong, and even with the weather issues that were seen in the past quarter, you guys came in within guidance. So I just wonder if you 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 plan you all laid out last year?

Greg Hill -- Chief Operating Officer

Yes. I think as you mentioned, we did have a 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 we're able to stay within guidance. We guided that these high-intensity plug and perf completions are delivering 15% to 20% increase in IP 180 and a 5% to 10% increase in EUR versus at previous sliding, 60-stage sliding sleeve design. We're confirming those results. I mean we're well within that range. Because wherever we are drilling in the first quarter was a little better than that, but that is still going to be our guidance for the year. And as John mentioned in his opening remarks, this is going to increase Bakken NPV by our $1 billion, at $60 WTI. So, so far so good. We're very pleased with the results.

Devin McDermott -- Morgan Stanley -- Analyst

Great. Thank you.

Operator

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

John Abbot -- Bank of America -- Analyst

Good morning guys. This is John Abbot on for Doug Leggate. Doug is currently on a plane. Doug is currently on a plane flying back from the Destiny FPSO. I'm sure he is 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 sail in mid-June and likely be in Guyana in August. Can you now confirm that first oil may possibly start before the end of the year?

Greg Hill -- Chief Operating Officer

Well, I think, 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. I think it's the reason that there is a little bit left in the schedule is because we started all the open-water activity. So I think it's prudent to stick with our by first quarter 2020 for now until everything shows up in theater and you start the open-water work.

John Abbot -- Bank of America -- Analyst

Appreciate it. And his second question is on hedging. You're fully hedged onshore for 2019 with $60 floor. But you've also said, at $60 oil in the Bakken, you can generate about $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?

John Rielly -- Chief Financial Officer

Thanks. So just like you said, we are well positioned here for this year in 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 -- line in the sand, ensure that we have the strong cash flow next year, as we continue to invest in Guyana and Bakken.

John Abbot -- Bank of America -- Analyst

We appreciate thank you for taking our questions.

John Rielly -- Chief Financial Officer

Thank you

Operator

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

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning. I wanted to follow up on the topic of oil prices and 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 down debt or investing in the business?

John Hess -- Chief Executive Officer

Yes. 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 6-week program we have in the Bakken. So the strong cash position will be prioritized for investing in those high-return projects.

Brian Singer -- Goldman Sachs -- Analyst

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

John Hess -- Chief Executive Officer

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

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you. And then Tilapia nearby?

John Hess -- Chief Executive Officer

Tilapia, again, a very good well, 305 feet, a very high-quality oil-bearing sandstone reservoir. So we're also very pleased to that also.

I think the key point here is both of those wells, Greg talked about, are very oily, high-quality oil, and really increased our confidence that the greater Turbot area should underpin the fourth and fifth FPSOs that are being contemplated.

Operator

And our next question is from the line of Jeffrey Campbell of Tuohy Brothers. Your line is open.

Jeffrey Campbell -- Jewish Brothers -- Analyst

Congratulations on the continued success in Guyana.

John Hess -- Chief Executive Officer

Thanks for that.

Jeffrey Campbell -- Jewish Brothers -- Analyst

To that point, I just wanted to just kind of asking something that was asked before, but I just want to ask in a different way. It appears that you may have actually discovered additional Guyana oil resource that's 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 to become as longer-dated oil?

Greg Hill -- Chief Operating Officer

No. Again, we are optimizing our plans. The first 3 ships are very much defined. The fourth and fifth ship, we still have more appraisal work to do, we're also looking at Hammerhead. How that might fit in the queue. But since this is a phase 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.

Jeffrey Campbell -- Jewish Brothers -- Analyst

Okay. Thank you. I appreciate that. And I just want to turn quickly to North Malay. We noted the output increase. I was under the impression we already closing their peak, but that obviously wasn't the case. So I was just wondering, is future growth beyond what we saw in the first quarter is expected at some point? Or the volumes getting their new ceilings?

Greg Hill -- Chief Operating Officer

Really from what you saw in the first quarter were increased nominations above typical nominations. Now the field, as you can see, it has the capability of delivering that, but it is really based on local demand. So what I would say is you should expect that nominations to come down. We are expanding 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.

Jeffrey Campbell -- Jewish Brothers -- Analyst

Okay great. Thanks for the clarification.

Operator

Our next question comes from the line of Pavel Molchanov of Raymond James. Your line is open.

Pavel Molchanov -- Raymond James -- Analyst

Thanks for taking the question. I don't think anyone's asked you 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 kind of the expectation for additional drop downs beyond the organic expansion that I know you guys announced this morning?

Greg Hill -- Chief Operating Officer

Yes, so you're right. We did in the first quarter, we sold our water business or dropped it down into the upper tier of the Midstream JV. So that was completed in the first quarter. And then also, in the first quarter, Midstream did acquire some other North Dakota transportation assets from Summit Midstream partner. So they did that. They've been busy, and as you know, you mentioned that we are expanding our Tioga Gas Plant from 250 million 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 forward 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 in 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 will tell you.

Pavel Molchanov -- Raymond James -- Analyst

Okay. And when I look at the guidance for the Midstream tariff starts, you did $162 million in Q1, guiding to $170 million. 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?

Greg Hill -- Chief Operating Officer

So we will have a significant -- begin to get significant increase of throughput capacity when the Little Missouri Four plant comes online. And that is expected to come online in the third quarter. So the Midstream will see -- and it's not just Hess, it's third parties as well utilizing our additional capacity at the Little Missouri plant. So it is just the throughput increase that will increase that tariff. Some of it being Hess-related and some of it being third-party.

Operator

And our next question comes from the line of Ross Payne of Wells Fargo Securities. Your line is open.

Ross Payne -- Wells Fargo Securities -- Analyst

Thank you. Nice job guys, across-the-board. Can you speak to the process to sanction Liza 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?

Greg Hill -- Chief Operating Officer

I think I'll talk to Phase 2, and John will speak to the no-confidence vote. But on Phase 2, as we said in our opening remarks, the approval is imminent. So we don't expect any issues.

John Hess -- Chief Executive Officer

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/or oil affairs.

Operator

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

Duration: 40 minutes

Call participants:

Jay Wilson -- Vice President of Investor Relations

John Hess -- Chief Executive Officer

Greg Hill -- Chief Operating Officer

John Rielly -- Chief Financial Officer

Robert Alan Brackett -- Bernstein Research. -- Analyst

Arun Jayaram -- JP Morgan -- Analyst

Devin McDermott -- Morgan Stanley -- Analyst

John Abbot -- Bank of America -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Jeffrey Campbell -- Jewish Brothers -- Analyst

Pavel Molchanov -- Raymond James -- Analyst

Ross Payne -- Wells Fargo Securities -- Analyst

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