Hess Corporation

Good day, ladies and gentlemen, and welcome to the fourth quarter 2019 HESS Corporation Conference Call. My name is Liz, and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question 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 would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, Liz. Good morning, everyone, and thank you for participating in our fourth 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 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. As usual, with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Reilly, Chief Financial Officer. I'll now turn the call over to John Hess.

Thank you, Jay. Welcome, everyone, to our fourth quarter conference call. I will review our continued progress in executing our strategy, then Greg Hill will discuss our operating performance, and then John Reilly will review our financial results. We had an outstanding year in terms of operational performance and continued execution of our long-term strategy, achieving a number of important milestones in delivering higher production and lower capital exploratory expenditures than our original guidance. With Guyana and the Bakken as our growth engines and Malaysia and the Deepwater Gulf of Mexico as our cash engines, our portfolio is on track to deliver increasing and strong financial returns, visible and low-risk production growth, and industry-leading cash flow growth.

It

is important to note that both Guyana and the Bakken will become significant cash generators over the next several years. As we have stated in our investor presentations, where we provide a financial outlook through 2025, our portfolio is positioned to generate approximately 20% compound annual cash flow growth and more than 10% compound annual production growth, and our portfolio breakeven is projected to decrease to below $40 per barrel Brent by 2025. As our free cash flow grows, we will prioritize return of capital to shareholders, both in terms of dividends and opportunistic share repurchases. Another key element of our strategy is maintaining a strong balance sheet and liquidity position and managing risk. We ended the year with more than $1.5 billion in cash and cash equivalents on the balance sheet, and have hedged 150,000 barrels of oil per day in 2020 using put options, with 130,000 barrels per day at $55 per barrel WTI and 20,000 barrels per day at $60 per barrel Brent. Without staining execution throughout our portfolio, we were able to reduce our full year 2019 capital and exploratory expenditures to $2.74 billion, down approximately $150 million from our original guidance. We have kept our 2020 capital and exploratory budget to $3 billion, in line with the guidance we provided at our December 2018 Investor Day. During the fourth quarter, we closed the previously announced transaction in which Hess Midstream converted to an up-sea corporate structure and acquired Hess Infrastructure Partners. As a result of the transaction, we received approximately $300 million in cash and own 47% of Hess Midstream. Turning to Guyana, where Hess has a 30% interest in the Staybrook Block and ExxonMobil is the operator, 2019 was an outstanding year in terms of both exploration and developments. On December 20, the Lisa Phase 1 development achieved first production and is expected to reach its full capacity of 120,000 gross barrels of oil per day in the coming months. We recognize this pivotal moment in Guyana's history and are committed to working collaboratively with the government, our partners, and the people of Guyana to build a safe and sustainable industry that fulfills the promise of shared prosperity. The Lisa Unity Floating Production Storage and Offloading Vessel, or FPSO, is under construction for the second phase of Lisa development. It is expected to start production in Guyana by mid-2022 with a production capacity of 220,000 gross barrels of oil per day. Front-end engineering design for a third FPSO, the Prosperity, is underway to develop the Payara field pending government approvals and project sanctioning. Production from Payara could start as early as 2023, reaching an estimated 220,000 gross barrels of oil per day. From an exploration perspective, 2019 was a banner year with five new discoveries at HaMira, Tilapia, Yellowtail, Trippletail, and Mako. On Monday, we announced an increase in the estimate of gross discovered recoverable resources for the Staybrook Block to more than 8 billion barrels of oil equivalent. We continue to see multi-billion barrels of exploration potential remaining. We also announced a significant oil discovery at Waru, marking the 16th discovery on the Staybrook Block. The Waru discovery will be incremental to the new resources estimate. Turning to the Bakken, our largest operated asset, our team had a very strong year. Full-year net production in 2019 for the Bakken averaged 152,000 barrels of oil equivalent per day, well above our original guidance range of 135,000 to 145,000 barrels of oil equivalent per day, and nearly 30% higher than 2018. Our Bakken performance showed the benefits of our successful transition to -and-perf completions. As a result, net oil production for 2019 was up 22% compared to 2018, and we are on track for Bakken production to average approximately 200,000 barrels of oil equivalent per day in 2021. In the Deepwater Gulf of Mexico, our successful oil discovery last quarter at ESOX will be brought online next month as a low-cost tieback to the Tubular Bells production facilities. HES is the operator and holds a .14% interest. Now turning to our 2019 financial results for the fourth quarter, our adjusted net loss was $180 million compared to adjusted net loss of $77 million in the fourth quarter of 2018, primarily reflecting the effects of lower realized prices. Full-year 2019 net production was 290,000 barrels of oil equivalent per day, excluding Libium, 17% higher than the pro-forma 248,000 barrels of oil equivalent per day produced in 2018. In 2020, our net production is forecast to average between 330,000 and 335,000 barrels of oil equivalent per day, excluding Libium. Bakken net production is forecast to average approximately 180,000 barrels of oil equivalent per day in 2020. As we continue to exude our strategy, our board, our leadership team, and each of our employees will be guided by our long-standing commitment to sustainability in terms of safety, protecting the environment, and making a positive impact on the communities where we operate. We are gratified to have been recognized by a number of third-party organizations for the quality of our environmental, social, and governance performance and disclosure, most recently achieving leadership status in CDP's Global Climate Analysis for the 11th consecutive year. In summary, we are proud of our 2019 performance and look forward to continuing this momentum into 2020 and future years as we execute our differentiated long-term strategy. With increasing cash margins and production volumes, our cash flow through 2025 is projected to grow at a rate that outpaces our industry peers and most companies in the S&P 500. As our portfolio generates increasing cash flow, the majority will be deployed toward increased return of capital to our shareholders through dividend increases and opportunistic share repurchases. I will now turn the call over to Greg for an operational update.

Thanks, John. 2019 marked another year of exceptional performance and strategic execution. In particular, I would like to call out three major operational highlights from 2019. First, we beat our guidance for both production and for capital and exploratory expenditures. Our 2019 net production averaged 290,000 barrels of oil equivalent per day, excluding Libya, which was above our original guidance of between 270,000 and 280,000 barrels of oil equivalent per day and also above our more recent guidance of approximately 285,000 barrels of oil equivalent per day. At the same time, our 2019 capital and exploratory expenditures were $2.74 billion, approximately $150 million below our original guidance. Second, we continued our extraordinary run of success on the 6.6 million acre Staybrook Block in Guyana with five discoveries, with the start of production from the Lease of Phase I development in December ahead of schedule and under budget, and with the sanction of the Lease of Phase II development, which is on track for first oil by mid-2022. Third, in the Bakken, we successfully completed our transition to plug and perf completions while driving down drilling and completion costs. Our plug and perf transition has, on average, delivered a 15% uplift in IP180 production. At the same time, we reduced our drilling and completion costs from an average of approximately $7.5 million per well in the fourth quarter of 2018 to approximately $6.5 million in the fourth quarter of 2019. By the end of 2020, we expect our DNC costs will approach $6 million per well. Proved reserves at the end of 2019 stood at 1.197 billion barrels of oil equivalent. Net proved reserve additions and revisions in 2019 totaled 121 million barrels of oil equivalent, including negative net price revisions of 35 million barrels of oil equivalent, resulting in an overall 2019 production replacement ratio of 104%. The majority of the additions were in the Bakken and Guyana. Now, turning to production. In the fourth quarter of 2019, company-wide net production averaged 316,000 barrels of oil equivalent per day, excluding Libya, above our guidance of approximately 300,000 barrels of oil equivalent per day, driven by strong performance across the portfolio, and in particular the Bakken. For the full year 2020, we forecast net production to average between 330,000 and 335,000 barrels of oil equivalent per day, excluding Libya, which is a 15% increase from 2019. In the first quarter of 2020, we forecast net production to average between 320,000 and 325,000 barrels of oil equivalent per day. In the Bakken, fourth quarter net production averaged 174,000 barrels of oil equivalent per day, an increase of approximately 38% above the year-ago quarter and above our guidance of 165,000 net barrels of oil equivalent per day. For the full year 2019, Bakken net production averaged 152,000 barrels of oil equivalent per day, above our original guidance of between 135,000 and 145,000 barrels of oil equivalent per day, and our most recent full year guidance of 150,000 barrels of oil equivalent per day. These results reflect the strong performance of our -and-perf completions and the quality of our acreage position. For the full year 2020, we forecast Bakken net production to average approximately 180,000 barrels of oil equivalent per day, which is approximately 18% higher than 2019. Our full year forecast reflects the impact of a 45-day planned shutdown of the Tioga Gas Plant in the third quarter. During the shutdown, we will perform a turnaround and tie in the plant expansion project, which will increase capacity from 250 million cubic feet per day to 400 million cubic feet per day. In 2020, we expect to drill approximately 170 wells and bring approximately 175 new wells online, compared with 160 wells drilled and 156 wells brought online in 2019. In the first quarter of 2020, we expect Bakken net production to average approximately 170,000 barrels of oil equivalent per day. Our first quarter 2020 forecast reflects lower planned activity levels due to seasonally difficult winter weather conditions, where we expect to bring online approximately 30 new wells compared with 59 in the fourth quarter of 2019. Net production will increase in the Bakken throughout the year, growing to approximately 200,000 barrels of oil equivalent per day by the end of 2020. As discussed previously, we plan to drop our rig count from six rigs in 2020 to four in 2021. At this level of activity, we expect to hold production relatively flat for at least five years and generate approximately $750 million of free cash flow annually at $55 per barrel WTI. Moving to the offshore, in the Deepwater Gulf of Mexico, net production averaged 70,000 barrels of oil equivalent per day in the fourth quarter and 66,000 barrels of oil equivalent per day for the full year 2019 in line with our guidance. Our focused exploration program in the Deepwater Gulf of Mexico yielded an oil discovery in the fourth quarter at the Esauks One Well in Mississippi Canyon, a dual completion was successfully run and the subsea installation is underway, which will tie back to the Tubular Bells production facility. We expect to achieve first oil in February. Esauks is a high return, cash generative tieback opportunity that was well executed. The timeframe from discovery to first oil is expected to be less than four months. In 2020, we forecast net production from our Deepwater Gulf of Mexico assets to average approximately 65,000 barrels of oil equivalent per day. This includes extended planned maintenance shutdowns in the second quarter. At the Malaysia-Thailand Joint Development Area in the Gulf of Thailand, where HESS has a 50% interest, net production averaged 36,000 barrels of oil equivalent per day in the fourth quarter and 35,000 barrels of oil equivalent per day for the full year 2019. At the North Malay Basin, also in the Gulf of Thailand, where HESS is operator and has a 50% interest, net production averaged 28,000 barrels of oil equivalent per day in the fourth quarter and for the full year 2019. Combined net production from our JDA and North Malay Basin assets is forecast to average approximately 60,000 barrels of oil equivalent per day for the full year 2020. Turning to Guyana, where HESS has a 30% interest in the Staybrook Block and ExxonMobil is the operator, in December we announced a 15th discovery on the block at the Mako 1 well, located approximately six miles southeast of the Lise Field. Mako 1, drilled in 5,315 feet of water, encountered approximately 164 feet of high-quality oil-bearing sandstone reservoir. On Monday, we announced another significant oil discovery at Waru, which is located approximately 10 miles northeast of the Lise Field. The Waru 1 well, drilled in 6,342 feet of water, encountered approximately 94 feet of high-quality oil-bearing sandstone reservoir. The well was drilled in a down-dip location on a large stratigraphic trap, further appraisal and testing is planned. Based on the 15 discoveries through year-end 2019, the estimate of growth discovered recoverable resources for the Staybrook Block has been increased to more than 8 billion barrels of oil equivalent, up from more than 5 billion barrels of oil equivalent only one year ago. The Waru discovery is incremental to this new resource estimate. The continuing growth of the resource base on the block has been truly remarkable. Looking forward, after the noble Tom Madden completes the evaluation of the Waru discovery, the drill ship will move to development drilling for Lise Phase 2. The Stenek-Haren is currently engaged on a well test at the Yellowtail discovery, after which it will drill and test the Yellowtail 2 appraisal well. After completing the evaluation program for MAKO-1, the noble Don Taylor will next drill and test the Longtail 2 appraisal well. Finally, the noble Bob Douglas will continue drilling development wells. As announced on Monday, the operator intends to bring in a fifth drill ship later this year. We expect the first half of 2020 will be dominated by appraisal activities, primarily in the greater Turbot area. In the second half of the year, we plan to drill several new exploration wells, including some that will test the emerging deeper plays on the Staybrook block. Turning now to our Guyana developments. On December 20, production commenced from the Lise Phase 1 development, less than five years after the discovery of hydrocarbons and well ahead of the industry average for deepwater developments. The project also came in under budget. At sanction, Lise Phase 1 was budgeted at $4.4 billion gross, including the purchase of the FPSO. We now expect the gross cost for the development to be approximately $3.5 billion, or 21% below the sanction estimate. Lise Phase 1 production continues to ramp up. Current gross production is approximately 75,000 barrels of oil per day from three of the five producers available at startup. Production is expected to reach the FPSO's capacity of 120,000 barrels of oil per day in the coming months. For the full year 2020, we forecast our net production to average approximately 25,000 barrels of oil per day. The Lise Phase 2 development is progressing the plan. On January 13, the hull for the Lise Unity FPSO, which will have a capacity of 220,000 barrels of oil per day, arrived at the Keppel Yard in Singapore. Construction of all 13 deck modules is currently underway. Meanwhile, in Guyana, installation of subsea flow lines and equipment is underway, and development drilling is expected to begin next month. We continue to forecast first oil by mid-2022. Pending government approvals and project sanctioning, a third development at PIARA is planned to utilize an FPSO with a gross production capacity of 220,000 barrels of oil per day, with first oil as early as 2023. Together with Hammerhead, discoveries on the southeast portion of the block, including Turbot, Yellowtail, Longtail, Pluma, Tilapia, and Triple Tail, will underpin future FPSOs. In closing, our execution continues to be strong. The Bakken is on a capital-efficient growth trajectory. Our offshore assets in the deep border Gulf of Mexico and Malaysia continue to generate significant free cash flow, and Guyana continues to get bigger and better, all of which positions us to deliver industry-leading returns, material-free cash flow generation, and significant shareholder value. I will now turn the call over to John Reilly.

Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2019 to the third quarter of 2019. We incurred a net loss of $222 million in the fourth quarter of 2019 compared to a net loss of $212 million in the third quarter of 2019. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $180 million in the fourth quarter of 2019 compared to a net loss of $105 million in the previous quarter. For E&P, on an adjusted basis, E&P incurred a net loss of $124 million in the fourth quarter of 2019 compared to a net loss of $41 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the fourth quarter and third quarter of 2019 were as follows. Higher exploration costs reduced results by $56 million. Lower realized selling prices reduced results by $13 million. All other items reduced results by $14 million for an overall reduction in fourth quarter results of $83 million. For Midstream, on an adjusted basis, the Midstream segment had net income of $49 million in the fourth quarter of 2019 compared to $39 million in the previous quarter, reflecting higher throughput volumes. Midstream EBITDA, on an adjusted basis and before non-controlling interest, amounted to $157 million in the fourth quarter of 2019 compared to $134 million in the previous quarter. For Corporate, on an adjusted basis, after-tax corporate and interest expenses were $105 million in the fourth quarter of 2019 compared to $103 million in the previous quarter. Now turning to our financial position, at quarter end, excluding Midstream, cash and cash equivalents were ,000,000 and total liquidity was $5.4 billion, including available committed credit facilities, while debt and finance lease obligations totaled ,000,000. In December 2019, Hess Midstream completed its previously announced acquisition of Hess Infrastructure Partners with a conversion to an up-sea corporate structure and incentive distribution rights simplification. As consideration for the transaction, we received additional shares and approximately $300 million in cash. We now own approximately 134 million shares of Hess Midstream, or approximately 47%. In the fourth quarter of 2019, net cash provided from operating activities was $286 million or $550 million before changes in working capital and items affecting comparability, while cash outlays for capital expenditures were $825 million in the fourth quarter. Changes in working capital reduced cash flows from operating activities by $234 million in the fourth quarter, primarily reflecting premiums paid for crude oil hedging contracts. For calendar year 2020, our crude oil hedge positions consist of WTI put options with a notional amount of 130,000 barrels of oil per day that have an average monthly floor price of $55 per barrel, and Brent put options with a notional amount of 20,000 barrels of oil per day that have an average monthly floor price of $60 per barrel. Now turning to guidance, first for exploration and production, we project E&P cash costs, excluding Libya, to be in the range of $11.50 to $12.50 per barrel of oil equivalent for the first quarter and for the full year 2020. DD&A expense, excluding Libya, is forecast to be in the range of $16.50 to $17.50 per barrel of oil equivalent for the first quarter and for the full year 2020. This results in projected total E&P unit operating costs, excluding Libya, to be in the range of $28 to $30 per barrel of oil equivalent for the first quarter and for the full year 2020. As guided earlier, capital and exploratory expenditures in 2020 are expected to be $3 billion. Exploration expenses, excluding dry hole costs, are expected to be in the range of $50 to $55 million in the first quarter, with full year 2020 guidance expected to be in the range of $210 to $220 million. The midstream tariff is projected to be in the range of $225 to $235 million in the first quarter, with full year 2020 guidance expected to be in the range of $940 to $965 million. E&P tax expense, excluding Libya, is expected to be in the range of $15 to $20 million for the first quarter and in the range of $80 to $90 million for the full year 2020. As highlighted earlier, we have purchased crude oil hedge positions for calendar year 2020. We expect non-cash option premium amortization, which will be reflected in our realized selling prices, to reduce our results by approximately $70 million per quarter. Now turning to midstream, we anticipate net income attributable to HES from the midstream segment to be in the range of $45 to $55 million in the first quarter, and full year 2020 guidance is expected to be in the range of $205 to $215 million. For corporate, corporate expenses are estimated to be in the range of $30 to $35 million in the first quarter, and full year 2020 guidance is expected to be in the range of $115 to $125 million. Interest expense is estimated to be in the range of $85 to $90 million for the first quarter, with the full year 2020 guidance expected to be $350 to $360 million. The increase from 2019 is due to ceasing interest capitalization at the LISA field, which commenced production in December 2019. 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 one on your phone. If your question has been answered or you would like to withdraw your question, press pound. Questions will be taken in the order received. Please press star one to begin. Your first question comes from the line of Doug Leggett with Bank of America.

Thanks. Good morning, everybody. Good

morning, Doug.

Guys, it looks like the market doesn't like the guidance too much. So I wonder if we could talk a little bit about the cadence of what's going on with downtime through the course of the year. Greg, you touched on Tioga, but I want to know, obviously you've given us a first quarter run rate for the back end, but can you walk us through how that progresses through the year? Because clearly 174 in fourth quarter and a 180 average for the full year looks a little soft and maybe touching the Gulf of Mexico planned downtime as well.

Yeah, thanks, Doug. So as we mentioned, we do have the turnaround at the Tioga gas plant. It's going to be about 45 days and we're going to turn it around and also tie in the gas plant expansion, as we mentioned. Now, that's not going to have much impact, if any, on oil. It's going to be primarily gas and the net effect of that is about 6,000 barrels of oil equivalent per day. For the year, Greg, or for the quarter? For the year, yeah, for the year. Thanks, Doug. And then if I turn to the Gulf of Mexico, we have two major shutdowns in the second quarter, one at Conger and one at Lano, both of which are down for 30 days. We also have Penn State down for about eight days in the second quarter. So the net impact of that on the quarter is about 13,000 barrels a day.

Okay, that starts to make a bit more sense and I appreciate the emphasis that oil doesn't get hit. So thank you for that. My follow-up is not to be too predictable, is obviously on Guyana. And I know we have the Exxon Analyst Day on March 5th, so to the extent you can share, it seems that the appraisal activity focused around turbot is probably, I'm guessing, is to define what the scale of that development is going to look like over time. You previously defined it as a major development hub, but we also know that Hammerhead has been passed to the development team for Exxon. So I'm just wondering if you can kind of walk us through your current thought on the timing over the scale of that 2025 run rate. And John Riley, how does that impact the 2018 guidance you gave us of a run rate of $3 billion capital program? And I'll leave it there. Thanks.

Yeah, thanks, Doug. I think, you know, as we've spoken before, you're right. I mean, Hammerhead has been passed off to the development team. That notionally right now is about 140,000 barrels of oil capacity kind of vessel. And then as you mentioned, all of the appraisal activities that are ongoing, really what I call on the Eastern seaboard between Turbot and Liza, are really trying to understand how many vessels will it take to evacuate all of that oil, which is substantial along that Eastern seaboard. So clearly, you know, clearly Vessel 5 is going to be in that area and probably several vessels after that. But we're trying to figure all that out. How many vessels will it take? And obviously the fifth vessel will be a large one. It'll be in the 220 class like the others are. But, you know, specific timing of the number of vessels and timing of the ones after five, that's really what we're working on. And that's kind of the heavy lift for this year, Doug, to really understand that. And

then, Doug, as far as our capital program, as we laid out on our Investor Day, we had $3 billion this year. We do have, if you see from the Investor Day, a little bit more next year as we move on with these developments. And as we've talked about, it's an approximate $3 billion. And right now, there's no change to that number. We've got a nice cadence going. Exxon, as an aside, has been doing a fantastic job on the execution of Phase 1. And now Phase 2, the execution is going along well. And so they're doing a great job for Guyana and for the partners. So what we're seeing from our capital program is that that $3 billion is a good number. Right now, as Greg said, you know, we're unsure of SPSOs beyond the five. And we'll see that. But, again, that will be much later in the profile of our timing of free cash flow. Because, as you remember, once Phase 2 comes on, it's a big inflection point for us from a free cash flow standpoint. So any SPSOs, be it 6, 7 or something beyond that, will be in a good period for us when we're generating a lot of free cash flow.

I appreciate that, guys. And I'll see you in a couple of weeks. Thank you. Thank you.

Your next question comes from the line of Ryan Todd with Simmons Energy.

Great. Thanks. And maybe one follow-up initially on Guyana. Can you talk about the upwards revision to the resource estimate to 8 billion barrels? Was all that based on the inclusion of incremental discoveries since the last estimate? Or was there any component driven by upward revisions to estimates at prior discoveries? Maybe just you talk about the primary drivers of what you continue to see as the significant upward pressure on resource?

No, I think the absolute grand majority of that was all new discoveries. So it's just continuing to add to this extraordinary success rate, five in 2019 and already another one in 2020 with more to come. Great.

Thanks. And then maybe a follow-up in the Bakken. I mean, the Bakken continues to exceed expectations in terms of productivity and also impressive costs. Can you talk about some of the drivers of what you've seen in terms of the strong Bakken production? And maybe you highlighted actual and targeted reductions in well cost for the Bakken in 2020. What are the drivers and what do you see in there in terms of costs in the Basin?

Yeah, so let me start with cost first. As I mentioned in my opening remarks, I'm really proud of the team and their ability to drive cost down with lean manufacturing. So if you think about our journey in 2019, we started at seven and a half in the fourth quarter of 2018, 7.3 in Q1, 7 in Q2, 6.7 in Q3, and 6.5 in Q4. So that's an amazing cost reduction over 12 months driven primarily by lean manufacturing, but also technology. And then as we look forward to next year, obviously that flattens out a bit, part of lean manufacturing, but we still think we'll be at six by the end of the year. The biggest driver on that is going to be, again, technology and lean, but we also are seeing some softness in the sand costs and also pressure pumping. So we built some of that into our cost estimates for next year. Regarding the productivity, really a function of where we're drilling, but also the plug and purse coming in very well. So on average, IP180s are up 15%, but if you look at certain areas of the field, particularly in the southern part of the field, we've outperformed that 15% in those areas, and those are very good prolific areas of the Bakken. And as we look forward to our 2020 program, again, it's 175 wells. It'll be very similar. EUR is kind of in the 1 to 1.2 range. IP180s in the 110 to 120 range, and IRR is at 60, well above 75%. So again, a very strong program in 2020. Great. Thanks, Greg. Very helpful.

Your next question comes from the line of Roger Reed with Wells Fargo.

Yeah, thanks. Good morning. Maybe just to follow up on that Bakken question, and this may be premature, but given that you're continuing to see improvements, as we think about holding flat at $200,000 a day kind of end of this year onwards, any reason at this point or any optimism to think about that costing less or maybe not taking quite four rigs as we go forward, or do we just need to balance that as you kind of move from, as you mentioned, the premium spots to maybe the next tier down that's incorporated in the outlook?

Yeah, I think it's a balance, as you said. So we're pretty confident that we can hold it flat at the $200 range for at least five years and probably longer. And as you mentioned, as technology improvements continue to occur, as costs potentially continue to come down, obviously that plateau will be extended even longer. And I will mention that in our tier two acreage, we are doing a lot of trials on profit loading, on number of entry points, on spacing. So we are not decided yet in some of those areas exactly what that's going to be. So the assumption going forward is none of that's built in. So I'm very optimistic that that will get much better as we go forward, as we learn in those areas.

Yeah, it certainly has not been a static environment so far, right? One other question, and it's got two parts. I apologize for doing it that way. But it's some of the pushback we've gotten post-results here. One is the hedging program. So I'll just kind of put the question up to you of why hedge. The second part is we did see debt go up in the quarter. It looks like mostly that was to take care of the midstream side of things. But I was wondering if you could clarify on those two points for us.

Sure, Roger. And I'll only do the second one first, just as quick. The debt that went up was related to midstream and the completion of the transaction that we spoke about, the acquisition of HES infrastructure partners, and the conversion to the up-sea. That was the debt. So it's just purely midstream debt that is non-recourse to HES. As far as the hedging, Roger, you know the prize we have from our investor day there with Bakken getting up to 200,000 barrels a day and bringing on phase two. So what we do is we look at it year by year and we put these hedges on for insurance just to ensure that we can fund that investment program because of the returns that that program will drive for us. So we're getting closer and closer. Phase two, right, is mid-2022. We just want to finish this Guyana program, execute it, continue to execute that, and as Greg said, continue to execute our six-rig program, which will drop the four rigs the following year. And so we just put hedges on for insurance purposes, and hopefully we don't use them.

I appreciate it. Thank you.

Your next question comes from Janine Why with Barclays. Hi. Good morning, everyone.

Good morning.

I guess my two questions are on capex and Guyana. The first one is it looks like total EMP capex for the quarter came in a little bit higher than expected, and I believe some of that might be related to Guyana. So can you provide any color on that and any implications for phase two that it may imply?

It did come in for the quarter, very small amount. Again, we just went out with an approximate 850, came in at 876. As Greg mentioned, with the Bakken, we did get a little bit more completions in the Bakken, so a little bit is in the Bakken. A little bit of it is in acceleration in Guyana, and the rest of it is kind of just through the portfolio, really small numbers. Again, we were just given approximate amounts, so there's no implication on that going forward. We have the $3 billion capital that we set. We are going up approximately $300 million in Guyana next year versus 2019, and again, we laid that out for the continuation of phase one, about $400 million for phase two, and then the rest of it for phase three and future developments.

Okay, great. That's really helpful. Thank you for that. My second question on Guyana, can you comment on any of the recent news headlines about the potential for contract renegotiations?

Yeah, you know, most of the news that you hear is not from reliable sources, neither the current government or opposition government. I think they both have been pretty clear that they are going to honor the PSC, so I think that's the real takeaway you should have.

Okay, great. Thank you for taking

my questions.

Pleasure.

Your next question comes from the line of David Dekeldon with Cowen.

Good morning, everyone. Thanks for taking my questions.

Thanks.

Just wanted to ask, you talked about having the first tanker loading attributed to HESS or allocated to HESS in March with 1 million barrels. How do you see the liftings or tanker loadings progressing throughout the year? Should we always be thinking about the same sort of capacity and what kind of cadence are you expecting throughout the year?

So the cadence can move around a little bit from that on how they get allocated, but here there's a general rule of thumb. It will be a million barrels each lift, and for us, as you heard, Greg gave the guidance on Guyana that it's 25,000 barrels a day for the year. If you multiply that by 365, you're getting just about 9 million, a little over 9 million barrels. So we expect just from a forecast standpoint to have nine lifts this year. I can't exactly be specific which quarters that will be coming in. Our first lift, your right, is expected in early March.

Okay, I appreciate that. But it does sound like your net sales amount is approximating your production guidance for the year, so that's

encouraging. That is correct. So by quarter by quarter, you could get some under-overlifts, but right, for the full year, the sales should approximate the production amount.

Got it. And then just to revisit some of the Bakken guidance, I know that it's difficult to forecast with lumpiness around the quarters, but the expectation is that you'd be exiting 20 at approximately that 200 equivalent target?

Yes, we'll achieve that sometime in the fourth quarter.

Okay. And then in the third quarter with the Tioga turnaround and expansion, how is it that oil volumes are not impacted there from a logistical perspective?

Well, again, they're separate systems, right? So the gas is separated on the pad from the oil, and it goes through a separate system. So you can still produce the oil, but obviously that gas goes through the plant, so that's where the impact is going to be. So we'll do some local flaring on the pads and some flaring at the gas plant as well during that 45-day shutdown, but the oil will largely stay on.

Okay, but I guess as a total program,

you'd still

be under the regulations for flaring at the state level?

Yes, yes. There will be some restrictions that we'll have to deal with, but of course you can get some dispensation for things like turnarounds, et cetera.

All right. I appreciate the color on that. Thank you, guys.

Your next question comes from the line of Michael Hall with Hikin and Energy Advisors.

Thanks. Good morning. I'm just curious, a little bit of an accounting question, I guess. On the Guyana volumes, the $25,000 a day, does that include cost barrel recoveries? If so, how much? If not, how should we think about that for 2020?

It does include that. It's just part of the normal production sharing contract that cost recovery barrels are included as part of our production and the partners' production.

And do you have an estimate of how much of that is cost recovery by chance?

I could walk you maybe through it a little bit more in detail after the call, but the contract is out there that you can see, but the way it basically works is on the revenue, then 75% of the revenue goes for cost recovery for the contractors. So that's how you can factor in. And then you go into profit share after that.

Okay. Yeah. Just wanted to make sure we're calibrating right. And then I was curious on, I guess, the Gulf of Mexico, the capital on the 2020 plan. I think we backed into around $350 million or so. Relative to, at 2018 Analyst Day, you talked about an annual average capital of $150 million to sustain 65 MBOE a day. So I'm just trying to line those two things up. And should we be, yeah, how do we reconcile those two things?

I just want to make sure that we were on the same page with the numbers. So in our release that we went out for 2020, the Gulf of Mexico capital will be approximately $135 million for this year. That's what we're spending from a production aspect of it. Last year we did have a higher amount. It was approximately $290 million. And that is because we were running full year. We had two rigs running for Stampede, which will be coming off contract here basically in the second quarter. So there's lower Gulf of Mexico spend. And so as you know, we will be tying in ESOX, which again helps and keeps us at that 65,000 barrels a day that we've talked about.

And then as we did mention, going forward you can expect about $150 to $200 million of capex per annum for infill and tieback wells. So, you know, and this is our objective in the short term to medium term to maintain the Gulf at about 65,000 barrels a day. And we've been very successful doing that. If you look at Conger 10, you know, that was about 6,000 barrels a day. Penn State 6, about 14,000 barrels a day. Londo 5, about 8. And ESOX is anticipated to be a very good will. We see four to six more things that we'd like to drill in the next couple of years in our expectation of keeping those hubs full. Then beyond that, of course, it'll be Greenfield. So we'll drill a Greenfield expiration well, probably one a year on average over the next several years, again, trying to maintain that production or potentially even growing it with a new hub.

Okay. Yeah, I guess that's helpful. And I guess to maybe make sure I'm thinking about the numbers right here. So, I mean, I was trying to connect $1.73 billion of total U.S. capital per the release with the $1.375 billion in the Bakken and the remainder being in the Gulf of Mexico, I'm assuming some of that being for exploration. So I guess what's being spent in the U.S. outside of the Bakken and the Gulf of Mexico, if anything, and how would you break out the $1.73 billion between the Bakken and the Gulf of Mexico? It just seems like those two don't – that doesn't all add up.

So you have $1.730 billion you're saying in the U.S., right?

So you have

$1.730 billion, back out the Bakken, which is $1.375 billion, right, in production. And you're going to back out $1.35 billion for the Gulf of Mexico, right? So then the rest of that amount is in exploration. That can be wells being drilled or seismic being spent. So that approximate $200 million that you have left relates to exploration.

Sure. Okay. And that exploration is all in the Gulf?

In the Gulf, correct, that U.S. piece, correct.

Okay. Thank you.

Your next question comes from the line of Paul Chang with Scotiabank.

Hey, guys. Good morning. Good morning. I have to apologize that I joined late. So my questions have already been answered. Just let me know so I will just look at the transcript. John, I think two quick questions for you on the accounting. The hatching premium amortization, the 70-minute quarter, is that pre-tax and after-tax? And also from an accounting standpoint, since in Guyana you have the government going to pick up the income tax, so when you guys report it, are you going to report the corresponding tax as a gross up and then you report it also the tax or that you just don't report any tax at all? How is the accounting treatment going to be?

Okay. So first on the hedges, it is pre-tax and post-tax. So that will be the same amount because we have evaluation allowance against our net operating losses in the U.S. So that will be the same number. In Guyana, we do pay taxes in the entitlement of our contract. So the taxes are embedded in our entitlement, effectively reducing our entitlement. And therefore what we do then with our entitlement for financial reporting purposes is disaggregate that and then show the tax and gross it up from relating to that. I can walk you through that more after the call, but that is how we are doing that.

Yes, because I think that is how Apache has done in Egypt. I just want to make sure that that is the same methodology because that is how we are modeling right now.

Yes, that is how it would work and happy to discuss that further. We can do that.

Okay. And Greg, when I am looking at your production guidance, that seems conservative. Is there any area that maybe we have a bit more of the upside?

I think you probably missed the start of the call where we kind of went through the shutdowns. Again, Taya, gas plant down 45 days and then a heavy maintenance period in the Gulf of Mexico where we have two of our big assets down 30 days in the second quarter. So that is really kind of what reduced our normal capacity of our production was those two shutdowns.

Okay, I will read the transcript. And then the final one, have you guys booked any additional reserve related to the Lisa 1 last year?

We booked a minor amount for the wells that we were drilled here. Again, rule of thumb is, Paul, probably we have got a third of the reserves on the books right now for Phase 1. And then as we get the dynamic data, see how the injection goes, we will begin to pick up additional reserves. Okay. All right, we will do it. Thank you.

Your next question comes from the line of Pavel Mokhanov with Raymond James.

Guys, thanks for taking the question. So this year after about five years you will begin to drill on a brand new exploration block in Guyana. And given your experience on Stub Brogue, I am curious what kind of expectations should we be thinking about in terms of pre-drill estimates and the geology of this new acreage that you are going to be getting underway?

No, I think you are referring to the Kytour block, which is outboard of Stub Brogue, which we have a 15% interest in Exxon, the operator. See, very similar play types that exist on the Lisa block or on the Stub Brogue block. And in fact, we will spud our first well, a well called Taninger, this year on that block. So stay tuned.

Okay. All right. Fair enough. And a question about HES Midstream. So now that the Bakken is very close to it, it is not reaching plateau, so what's going to be the drop down model for the MLP if the underlying production is essentially flatlining?

So for HES Midstream now, it's not an MLP and all the assets in North Dakota have been acquired by the Midstream because we completed that transaction in the fourth quarter. So they now have all the gathering facility there and the Tioga gas plant. So from the old drop down model, that won't be happening going forward. So what you do have here is this growth that we have. So in the Bakken, obviously, as we're going from 180 to 200,000 barrels a day, they're going to pick up that growth. The HES Midstream will be picking up that. Then as you know, the flaring regulations get tighter and tighter as we move on in North Dakota. And so what HES Midstream is doing now is they've completed the LM4 plant and so picked up additional gas processing capacity there. We're doing the expansion of the Tioga gas plant, and so that's going up to 400 million cubic feet a day. And it is looking to pick up third party business as these flaring regulations get tighter and tighter. And we are in a good infrastructure position and a good position to pick up that. So there's a lot of growth going from there, and they'll look for other opportunities up there in North Dakota. All right.

Appreciate it, guys.

Your next question comes from the line of Brian Singer with Goldman Sachs.

Thank you. Good morning. Can you talk about the benefits and risks in Guyana of co-development of SPSOs and how discussions and plans with the operator are evolving, if at all, as you ramp up the first SPSO and you gain greater insight into the reservoir and processes? How on the table is this when you look out to SPSOs three, four, five or beyond?

No, I think, Brian, the current strategy, which we agree with, is to design one, build many, because you can get such leverage of learning as you go from vessel one to two to three. Right. Now, what is likely going to happen is the time frame between those vessels will begin to collapse. So from a cadence of maybe one a year, maybe it becomes every nine months or potentially even every six months, you know, as you get out in time. That's what those synergies, you know, will do for you. So that's what we really see. We don't really see doubling or tripling up because that's very inefficient, but rather design one, build many, but continue to collapse the time frame based on efficiencies.

Yeah, and just to embellish on that, it's really a phased approach to be capital efficient. ExxonMobil has done a great job optimizing the development, lowering the costs. The learnings from Ship 1 help us in Ship 2, and that will continue in Ship 3. So we're really looking at a phased approach, but as Greg said, maybe with more compression of the time frame. And, you know, I just want to remind everyone the eight billion barrels of oil equivalent we talked about, we've had 16 successes, so it's basically 500 million per discovery. And that's world class. And it's got very low costs, very high returns, and ExxonMobil is doing a great job moving the project forward.

Great, thanks. And then, John, in your opening comments, you talked about free cash flow over time, going to dividend increases and opportunistic share purchase. Is there any change in the timing of when you would expect to consider that? Is that still when you get more into free cash flow mode post or with the startup of Phase 2 in Guyana, or is that something that we could see earlier or later than that?

No, I would say right now stick with our guidance that it's going to be timed with Phase 2 coming online, when again, that is the big inflection point for us from a free cash flow and earnings standpoint.

And the priority would be on increasing the dividend as the first call. Great, thank you.

Your next question comes from Lina Bin Lavaglio with Mizuho Securities. Mr. Lavaglio, your phone may be on mute.

Hello. Hi, sorry, it's Paul Snanky here. Can you hear me? Yeah, we can hear you, Paul. Yeah, sorry about that. I got myself on mute. Guys, we put out a note on ESG and oil and gas, and you have tested very, very well in terms of certainly your disclosures. Can you talk a little bit about some of the areas where you think you can still get better, and I'm specifically thinking about flaring? And beyond that, could you talk about the impact of Guyana and how that will change some of the metrics that you do such a great job of disclosing? Thanks.

Yeah, thank you, Paul. Obviously, ESG sustainability is core value for the company. We've been doing a sustainability report for 22 years. We're honored and proud to be an industry leader. We want to make sure we continue that leadership role. As we look at our flaring, let's say, in the Bakken, we're ahead of the state limits, and we have a program in place to continue that. And we're looking at updating our sustainability efforts in terms of the environment, and we'll be coming out with some new targets within the year for the next five years. So that's a work in progress, but we always want to stay ahead of the regulations. And in terms of Guyana, the gas is basically reinjected, and again, ExxonMobil does a great job minimizing the flaring in startup, et cetera, but the majority of glass is reinjected, so there's really not an issue there. And one of the things we're going to be looking at in Guyana is how can we help the country going forward in social responsibility, which is something that's very important to our company and our board, and every employee.

Got it, John. Thanks very much for that. And then a follow-up on the previous hedging question, totally different subject. How do you expect that hedging program that has sort of changed around a little bit over time? I wonder how you expect Guyana to affect that going forward and whether or not you'll have a different hedging strategy, let's say, in perhaps five years' time. Thanks.

Sure, I mean, we do look at it, Paul, year to year, and make our decisions on our hedging requirements. And right now, obviously, with the investment still going in for Guyana until we get to that phase two, we wanted to put a significant amount of insurance on to ensure we fund that. As we move forward and we get to more free cash flow, we'll still be, obviously, have a heavy oil portion in our portfolio. We'll make those decisions year to year, and we could make some different decisions at that point in time. Thank you, Guyana.

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.