HES Stock | Hess Corp Q4 2020 Earnings Call

Good day, ladies and gentlemen, and welcome to the fourth quarter 2020 Hess Corporation conference call. My name is Andrew, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. If at any time you require operator assistance, please press star then 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, Andrew. 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 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 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 we have done in recent quarters, we will be posting transcripts of each speaker's prepared remarks on our website following the presentations. As usual online 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.

Thanks, John. I also hope that everyone on the call is well and staying safe. 2020 marked another year of strong performance and strategic execution for Hess, despite the challenging conditions on many fronts. In particular, I would like to call out several operational highlights from the year. First, across our company, we have implemented comprehensive COVID-19 health and safety measures, including health screenings and testing, extended work schedules at offshore platforms, and social distancing initiatives, all based on government and public health agencies guidance. I'm truly grateful to our Hess response team and our global workforce for their commitment to keeping their colleagues and our communities safe during this pandemic. Second, in the Bakken, despite dropping from six rigs to one in May, our full year net production came in well above our original guidance for the year and 27% above that of 2019. These results reflect the strong performance of our plug-in-perf completions, increased natural gas capture, and the quality of our acreage position. Third, in Guyana, we made significant advances on all three of our sanctioned developments on the Stabroek Block, with Liza Phase One reaching its full production capacity in December, Liza Phase Two remaining on track for first oil early next year, and Payara sanctioned in September with first oil expected in 2024. Continued exploration and appraisal success increased the gross recoverable resource estimate for the block to approximately 9 billion barrels of oil equivalent. Now, turning to our operations. Proved reserves at the end of 2020 stood at 1.17 billion barrels of oil equivalent. Net proved reserve additions in 2020 totaled 117 million barrels of oil equivalent, including negative net price revisions of 79 million barrels of oil equivalent, which resulted in an overall 2020 production replacement ratio of 95% and a finding and development cost of $15.25 per barrel of oil equivalent. Excluding price-related revisions, our production replacement ratio was 158% with an F&D cost of $9.10 per barrel of oil equivalent. Turning to production, in the fourth quarter of 2020, company-wide net production averaged 309,000 barrels of oil equivalent per day excluding Libya, above our guidance of approximately 300,000 net barrels of oil equivalent per day, driven by higher natural gas capture in the Bakken and higher natural gas nominations in Southeast Asia. For the full year 2021, we forecast net production to average approximately 310,000 barrels of oil equivalent per day excluding Libya. For the first quarter of 2021, we forecast net production to average approximately 315,000 barrels of oil equivalent per day excluding Libya. In the Bakken, fourth quarter net production averaged 189,000 barrels of oil equivalent per day, an increase of approximately 9% above the year-ago quarter and above our guidance of 180,000 to 185,000 net barrels of oil equivalent per day. For the full year 2020, Bakken net production averaged 193,000 barrels of oil equivalent per day, an increase of approximately 27% compared to 2019 and well above our original four-year guidance of 180,000 barrels of oil equivalent per day, despite dropping from six rigs to one in May. We have a robust inventory of more than 1,800 drilling locations in the Bakken that can generate attractive returns at current oil prices, representing approximately 60 rig years of activity. With WTI prices now in the range of $50 per barrel, we will add a second operated drilling rig during the first quarter. A two rig program will enable us to hold net production flat at approximately 175,000 barrels of oil equivalent per day and will sustain strong long-term cash generation from this important asset. In 2020, our drilling and completion costs per Bakken well averaged $6.2 million, which was $600,000 or 9% lower than 2019. In 2021, we expect D&C costs to average below $6 million per well. Over the full year, we expect to drill 55 gross operated wells and bring approximately 45 new wells online. This compares to 71 wells drilled and 111 wells brought online in 2020. In the first quarter of 2021, we expect to drill approximately 10 wells and bring four new wells online. Bakken net production is forecast to average approximately 170,000 barrels of oil equivalent per day for both the first quarter and for the full year 2021. Our four-year forecast reflects the impact of a planned 45-day shutdown of the Tiger Gas Plant in the third quarter, which is expected to reduce full year net production by approximately 7,500 barrels of oil equivalent per day, predominantly affecting natural gas production. During the shutdown, we will perform a turnaround and tie in the plant expansion project completed in 2020, which will then increase capacity to 400 million cubic feet per day from the plant's current 250 million cubic feet per day capacity. Now moving to the offshore. In the deepwater Gulf of Mexico, net production averaged 32,000 barrels of oil equivalent per day in the fourth quarter and 56,000 barrels of oil equivalent per day for the full year 2020. Fourth quarter net production came in below our guidance of 40,000 barrels of oil equivalent per day due to the early closing of the Shenzi sale and extended hurricane recovery downtime at two third-party operated production platforms. In 2021, no new wells are planned in the deepwater Gulf of Mexico, and we forecast net production from our assets to average approximately 45,000 barrels of oil equivalent per day. This includes the impact of planned maintenance shutdowns in both the second and third quarters. The deepwater Gulf of Mexico remains a very important cash engine for the company, as well as a platform for future growth. In Malaysia and the Joint Development Area in the Gulf of Thailand, where Hess has a 50% interest, net production averaged 56,000 barrels of oil equivalent per day in the fourth quarter and 52,000 barrels of oil equivalent per day for the full year 2020. Fourth quarter production was above our guidance of 50,000 barrels of oil equivalent per day because of higher natural gas nominations. For the full year 2021, net production from Malaysia and the JDA is forecast to average approximately 60,000 barrels of oil equivalent per day. Turning to Guyana, where Hess has a 30% interest in the Stabroek Block and ExxonMobil is the operator, in 2020 we announced three new discoveries, bringing the total number of discoveries to 18 and increasing our estimate of gross discovered recoverable resources to approximately 9 billion barrels of oil equivalent. And we continue to see multi-billion barrels of exploration upside on the Stabroek Block. We are planning an active exploration program in 2021. In March, the operator will bring a fifth drillship, the Stena DrilMax, into theater, and in April a sixth drillship, the Noble Sam Croft. We plan to drill 12 to 15 exploration and appraisal wells in 2021 that will target a variety of prospects and play types. These will include lower risk wells near existing discoveries, higher risk step-outs, and several penetrations that will test deeper Lower Campanian and Cenomanian intervals. This ramped up program will allow us to accelerate exploration of the block and enable optimum sequencing of future developments. In addition, the emerging deep play, which we believe has significant potential, needs further drilling to determine its commerciality and ultimate value. Over the next several months, we will participate in two exploration wells and two appraisal wells on the Stabroek Block. The next exploration well to be drilled is Ko Ko Bi-1, which is located approximately 16 miles northeast of Liza. This well will target Liza-type Campanian-aged reservoirs and is expected to spud in February using the Stena Karen drillship. In March, we expect to spud the Longtail 3 appraisal well, which will provide additional data in the Turbot-Longtail area, and we will drill a deeper section that will target Lower Campanian and Santonian geologic intervals. The Stena DrilMax will drill this well. Moving to April, we expect to spud the Uaru 2 appraisal well utilizing the Noble Don Taylor drillship. Success here and at Mako 2, which will be drilled later this year, could move the Mako-Uaru area forward in the development queue. Then in May, we plan to spud the Whiptail 1 exploration well, located approximately 12 miles east of Liza. This well will test Campanian and Santonian-aged reservoirs and will be drilled by the Stena DrilMax. Turning now to our Guyana developments. In mid-December, the Liza Destiny floating production, storage and offloading vessel achieved its nameplate capacity of 120,000 gross barrels of oil equivalent per day, and since then has been operating at that level or higher. During 2021, the operator intends to evaluate and pursue options to increase nameplate capacity. For 2021, we forecast net production from Guyana will average approximately 30,000 barrels of oil per day, with planned maintenance and optimization downtime being broadly offset by an increase in nameplate capacity. The Liza Phase 2 development remains on track for first oil in early 2022. The overall project, including the FPSO, drilling, and subsea infrastructure, is approximately 85% complete. We anticipate that the Liza Unity FPSO, which will have a capacity of 220,000 gross barrels of oil per day, will sail from the Keppel shipyard in Singapore to Guyana by mid-year. Payara, our third sanctioned development on the Stabroek Block, will utilize an FPSO with a gross production capacity of 220,000 gross barrels of oil per day, with first oil expected in 2024. The hull for the Prosperity FPSO is complete, topside construction activities are underway, and we expect the integration of the hull and topsides to begin at the Keppel yard in Singapore by year-end. Front-end engineering and design work is ongoing for a fourth development at Yellowtail. This work will continue through 2021, and we anticipate being ready to submit a plan of development to the government of Guyana for approval in the fourth quarter. In closing, our execution continues to be strong. The Bakken and our offshore assets in the deepwater Gulf of Mexico and Southeast Asia are performing well and continue to generate significant cash flow, and Guyana continues to get bigger and better. All of which positions us to deliver industry-leading cash flow growth and significant shareholder value over the course of the next decade. I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2020 to the third quarter of 2020 and provide guidance for 2021. We incurred a net loss of $97 million in the fourth quarter of 2020 compared with a net loss of $243 million in the third quarter of 2020. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $176 million in the fourth quarter of 2020 compared to a net loss of $216 million in the previous quarter. Fourth quarter results include an after-tax gain of $79 million from the sale of our interests in the Shenzi field. Turning to E&P, on an adjusted basis, E&P incurred a net loss of $118 million in the fourth quarter of 2020 compared to a net loss of $156 million in the previous quarter. The after-tax changes in adjusted E&P results between the fourth quarter and third quarter were as follows: higher realized selling prices improved results by $18 million; higher sales volumes improved results by $11 million; lower DD&A expense improved results by $40 million; lower exploration expenses improved results by $12 million; higher cash costs driven by workovers and hurricane-related maintenance costs in the Gulf of Mexico reduced results by $41 million; and all other items reduced results by $2 million, for an overall increase in fourth quarter results of $38 million. Our E&P operations were overlifted compared with production in the fourth quarter by approximately 1.6 million barrels, resulting in an increased after-tax income of approximately $15 million. Turning to midstream, the midstream segment had net income of $62 million in the fourth quarter of 2020 compared to net income of $56 million in the previous quarter. Midstream EBITDA before non-controlling interest amounted to $198 million in the fourth quarter of 2020 compared to $180 million in the previous quarter. Turning to corporate, after-tax corporate and interest expenses were $120 million in the fourth quarter of 2020 compared to an adjusted after-tax expense of $116 million in the previous quarter. Turning to our financial position, at quarter end, excluding midstream, cash and cash equivalents were approximately $1.74 billion and our total liquidity was $5.4 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.6 billion. Our fully undrawn $3.5 billion revolving credit facility is committed through May 2023. In November 2020, we completed the previously announced sale of our 28% working interest in the Shenzi field in the deepwater Gulf of Mexico for net proceeds of $482 million. Net cash provided by operating activities before changes in working capital was $532 million in the fourth quarter of 2020 compared with $468 million in the previous quarter, primarily due to higher crude oil sales volumes. In the fourth quarter, net cash provided from operating activities after changes in working capital was $486 million compared with $136 million in the prior quarter. Proceeds from the September sale of the first VLCC cargo of 2.1 million barrels of oil were received in October. We have entered into agreements to sell the second and third VLCC cargoes, totaling 4.2 million barrels of oil, in the first quarter of 2021. We expect to recognize net income of approximately $60 million in the first quarter from these sales, including associated hedging gains and costs. First quarter 2021 net cash provided by operating activities after changes in working capital is expected to include approximately $150 million of cash flow from these sales. For calendar year 2021, we have purchased WTI put options for 100,000 barrels of oil per day that have an average monthly floor price of $45 per barrel and Brent put options for 20,000 barrels of oil per day that have an average monthly floor price of $50 per barrel. Now turning to guidance. First, for E&P, we project E&P cash costs excluding Libya to be in the range of $10.50 to $11.50 per barrel of oil equivalent for the first quarter and for the full year 2021. DD&A expense excluding Libya is forecast to be in the range of $12 to $13 per barrel of oil equivalent for the first quarter and for the full year 2021. This results in projected total E&P unit operating costs excluding Libya to be in the range of $22.50 to $24.50 per barrel of oil equivalent for the first quarter and for the full year 2021. Exploration expenses excluding dry hole costs are expected to be in the range of $30 to $35 million in the first quarter and $170 to $180 million for the full year 2021. The midstream tariff is projected to be in the range of $265 to $275 million in the first quarter and $1.09 to $1.12 billion for the full year 2021. E&P income tax expense excluding Libya is expected to be in the range of $30 to $35 million for the first quarter and $80 to $90 million for the full year 2021. As highlighted earlier, we have purchased crude oil hedge positions for calendar year 2021. We expect non-cash option premium amortization, which will be reflected in our realized selling prices, to reduce our results by approximately $37 million per quarter. Our E&P capital and exploratory expenditures are expected to be approximately $425 million in the first quarter and approximately $1.9 billion for the full year 2021. For midstream, we anticipate net income attributable to Hess from the midstream segment to be in the range of $70 to $80 million in the first quarter and $280 to $290 million for the full year 2021. For corporate, corporate expenses are estimated to be in the range of $35 to $40 million for the first quarter and $130 to $140 million for the full year 2021. Interest expense is estimated to be in the range of $95 to $100 million for the first quarter and $380 to $390 million for the full year 2021. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

Thank you. Ladies and gentlemen, if you have a question, please press star then 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.

Hi, good morning everyone. Thanks for taking my questions.

My questions are on Guyana. My first one is the Stena Karen drillship completed appraisal work at the Red Tail well. Do you have any color on the appraisal results? And I think it was supposed to include a drill stem test, but I'm not sure on the status of that.

Yeah, thank you, Jainne. First of all, the results of the Red Tail well and the test are very positive. What it does is it really confirms our excitement about the large volume of very high quality reservoir and reservoir fluids in and around what I call the greater Yellowtail area. That's a big reason why Yellowtail now is going to be the focus of the fourth development, which we said in our remarks we hope to submit a plan of development to the Guyanese government by the fourth quarter this year. So very exciting results and a very exciting development coming forward.

Okay, great. Thank you. And my follow-up is also on Guyana. I loved all the details about where you're going for exploration and appraisal this year. You mentioned depending on the results of the appraisal at Mako, that could get moved up in the queue. I was just wondering what you're seeing at Mako that puts it ahead of some of the other potential development areas. Thank you.

Yeah, sure, Jainne. What we said was that the Uaru and Mako area is one of several areas that we are evaluating for future developments. The success at Uaru 2 and Mako 2 could move it forward in the queue, but we will make that determination as we get results.

Assuming good results at Mako, and remember it is very close to Lisa II and it's kind of in between Yellowtail and Lisa II, so we know that the reservoir quality and the crude quality is going to be very high in that region. So that's why it will move up further in the queue because if it's what we think it is, that will be very high value barrels that will want to move forward.

Sure, basically, yep.

Thank you. Our next question comes from the line of Doug McGady with Bank of America.

Well, thanks. Good morning. Happy New Year, guys. I appreciate you getting my questions. Greg, let me start with Hasa on the somewhat cryptic description John gave of the deeper horizons. We've talked about the possibility of this Santonian and a number of other tests extending the life of some of the early phases. So I'm just wondering, is this a continuation of that Santonian trend that you saw in Hasa, and if so, why would you describe it as... I guess how would you describe it? Is it a successful well or unsuccessful? How have you reported it to the government?

Well, I think, look, while the Hassel well didn't encounter commercial quantities of hydrocarbons in the primary campaign objective, as we mentioned, Doug, in our opener, it did encounter approximately 50 net feet of pay in the deeper Santonian section. So further evaluation of these results is going to be incorporated in our future exploration and development plans for the area and will provide some very useful calibration for prospects and developments in the surrounding areas. So the petroleum system is working. We found 50 net feet of good oil in the Santonian, so now we need to process on what that means. But I think it's a very positive sign for the Santonian.

So it would not be reported as a discovery line for the government?

No, it's still under evaluation.

Okay, all right. My follow-up, John Rielly, you've obviously locked in some protection. Can you talk about the amortization schedule? And what's really behind my question is it looks to us that you're going to be pretty close to cash breakeven including dividends this year. How would you characterize that statement? Does that sound reasonable to you with what you know today? And if so, what is the incremental priority for free cash in terms of where you want the balance sheet to be? So it's a free cash flow question and a balance sheet question for 2021.

Great. So I think first, for the hedges themselves, for our 100,000 barrels a day of WTI put options that we have at $45, and then the 20,000 barrels a day for Brent production that we have at $50, the amortization of that is going to be $37 million per quarter. So we like it. We've got nice protection on the downside because, obviously, this is a big year for us just to complete the development of Lisa Phase Two. And as you know, when Lisa Phase Two comes on, it's approximately 60,000 barrels a day of Brent-based production. The cash cost of Lisa Phase Two is going to be more around $10, you know, free any purchase of the FPSO versus the first one being at $12 just from economies of scale. So you can put any type of Brent price in there and take out the $10 cash cost and you can see there's going to be a significant inflection for us on cash flow once Phase Two comes on. So for this year, Doug, from a cash perspective, what were we looking to do? The first thing we were looking to do was to get the hedges in place so we have insurance on the downside. Coming into the year, as I mentioned, we have $1.74 billion of cash at year-end. And as I said in my remarks, we're going to complete the sales of the two VLCCs, and it's going to give us cash flow of approximately $150 million in the first quarter. So on a pro forma basis, we basically have $1.9 billion of cash going into the year. So what I want to say is, I don't want to guess on oil prices, but we've got the downside protected. We're coming in with a very strong cash balance from that standpoint. And therefore, at these higher prices, obviously this helps with our funding program here for Guyana. So when Phase Two comes on, depending where prices are, with our insurance now, we know we're going to have a nice cash cushion at that point. And then we're going to be at this significant inflection point of getting much higher cash flow. And depending on prices there, the portfolio can just continue to generate free cash flow. Or if for some reason prices go back down in that period, as I said, Guyana will still be generating free cash flow even at very low prices once Phase Two comes on — like $40 type prices. And then when Payara comes on, if it was really low prices, we'd still be generating free cash flow. So we put ourselves in a good position with a very strong cash position, hedge protection. Should be a nice year with prices at this level, and then a big inflection when Phase Two starts.

So John, not to labor the question, you're happy with about a $5 billion that balances out your implication of when we pay down that term loan debt?

Yeah, so as we pay down that term loan, our debt to EBITDA, when the Guyana FPSOs keep coming on, we're going to drive under our two times target fairly quickly. So yes, that's where we'd like to be — to get that term loan paid off. And then as John said, then we start increasing dividends and opportunistic shareholder purchases.

Understood. Thanks for giving us.

Thank you. And our next question comes from the line of Arun Jairam with J.P. Morgan.

Yeah, good morning, gents.

Yeah, John, I wanted to start off with your thoughts on the evolving regulatory landscape post the election and maybe get your perspective on potential implications to Hess from the anticipated executive orders later today on canceling new lease sales. And if the government takes a more restrictive stance on permits opposed to the 60-day moratorium. And perhaps as well, to John Rielly, thoughts on IDCs. I know you have a pretty material NOL balance, but just thoughts and risks to IDCs as well.

Sure. So yeah, you were right, Arun. For us, obviously if they change what they're doing with the IDC, there will be an alternative period of recovery. I don't know over how many years or a different year term. For us, though, while it's negative for U.S. oil supply in general, it's not going to have a material impact to us due to our NOL position. We do have a significant net operating loss position here, so for us, paying cash taxes anything in the near term regarding the IDC will not change our profile.

Great. And my follow-up is, John Rielly, the cash cost guide was a little bit lower this year than our model, so I was wondering if he could maybe get us oriented how or where your expectations are for Lisa One kind of cash operating costs. I think you still are paying the rental fee on the FPSO, but would love to hear what those costs are and any expectations around Lisa Two with the bigger boat.

Yeah, go ahead. For Lisa Phase One, it's $12 per barrel basically. And now we're at full capacity here. That's the cash cost for about while we're in the rental period, and you're correct, we have it in our numbers for the whole year. Post-FPSO purchase, it'll drop down into the $8 to $9 type range for Lisa Phase One. As I mentioned, Lisa Phase Two, the cash cost will be approximately $10 per barrel while the FPSO is being leased, and then it's going to drop to $7 to $8 per barrel post the purchase of the FPSO. So again, for us, every time an FPSO comes online, it's going to help our cash costs, and it's also going to help our DD&A rates. So right now, Lisa Phase One, the current DD&A rate is below our portfolio average, again due to the low F&D costs. So when Lisa Phase Two comes on, ultimately when it's up and running at full scale, that F&D is very low, and that's going to continue to drive our DD&A down. So again, we look forward for every FPSO to come on in Guyana.

Thanks, gents.

Thank you. And our next question comes from the line of Brian Singer with Goldman Sachs.

Thank you. Good morning.

Good morning.

I want to start on the Bakken. You've highlighted that the beat on production on a BOE a day basis has come in part from gas capture and then some of the impacts of pricing on NGLs contracts and percent of proceeds contracts. On a forward-looking basis, I wonder if you could provide some color on what you expect the oil production outlook to be in the first quarter and the full year, where you stand in terms of gas flaring, and what the upside could be from further gas capture.

Yeah, so let me start with flaring, Brian. We're well below the 9% required by the state. In 2020, we achieved that, in particular in the fourth quarter, and that's why our gas capture volumes increased. This year, we plan to gather more gas and get our flaring down even lower. So as part of our continued focus on sustainability, we want to drive that gas flaring as low as possible, obviously. So you will see us continue to add infrastructure with our partner in the midstream to gather as much gas as we possibly can. Now, if we talk about the oil, the decline in oil is purely related to the wells online. So in Q3, we had 22 wells online, and Q4 we had 12 wells online. And in Q1 of this year, we will only put four wells online. So naturally, you're going to get some oil decline associated with that. However, as that second rig kicks in, which you really see the effects of in the second half of the year, that's when oil will begin to stabilize and be flat from then on. So again, it's really just a mix issue of gas that changes your percentage on a total company basis, and the oil is purely a function of the wells online. But that will stabilize. The company will stabilize at 175,000 barrels a day flat for a number of years.

Great, thanks. And then a second question goes back to Guyana. Now that you've gotten Phase One ramped up to the 120,000 barrels a day and it seemed like you're hinting that that capacity could actually be raised this year, can you talk about how you're planning Phase Two and the potential speed at which that could be ramped up to full capacity, knowing some of the lessons of 2020 in terms of gas capture, et cetera?

Yeah, Brian, thanks for that. Certainly, I would expect the ramp up of Phase Two to go faster because, as you say, all of those learnings have been incorporated into the ramp of Phase Two. So I would expect it to go much smoother because remember, all of our issues were associated with the gas system, and those have been fixed in Phase Two.

Great, thank you.

Thank you. And our next question comes from the line of Josh Silverstein with Wolfe Research.

Hey, good morning, guys.

Good morning.

Just a quick question. I'm sorry if I just missed this, but when you guys start to stabilize around the 175,000 range, what does the production mix look like? Or does it still kind of change on a quarterly basis just based on some of the well timing?

Yeah, so of course, you'll always get, there's two factors going on. One which I mentioned, which is yes, it is a function of when wells come online, so you get some minor changes associated with that. But then the bigger thing, when I'm talking about total production on a barrel equivalent basis, is really all the gas gathering, including third-party volumes, which remember a portion of that is subject to the percent of proceeds contracts. So a lot of times when you see those numbers moving around, particularly on the percentage of oil versus gas, it's all related to that gas gathering including third party and NGL prices, which affect your POP contracts. But oil will be flat with the two-rig program. And for the whole company, the 175,000 barrels a day equivalent will be flat with the two rigs.

Understood. Thanks for that. And then I'm just curious on the balance sheet and asset sales. Obviously, you sold Shenzhen late last quarter to help support the cash balance there in Ghana development. I know some of this will be opportunistic, but these are cash-flowing engines of the company, and I'm just wondering how much of the remaining portfolio you guys may want to divest or maybe market right now. I know in the past Denmark has been looked at as an asset for sale. So just curious, will there be an ongoing divestiture program as Guyana ramps up?

Okay, I understood. Thanks, guys. Thank you.

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

Good, thanks. Maybe one follow-up on the Bakken. Can you provide any additional color on the expected trajectory, at least in general, production in the Bakken over the course of the year? Should we expect some amount of modest decline during the first half before the second rig stabilizes production, and then a rate that's closer to the 175,000 barrel a day long-term target?

Yeah, I think that's fair. Because really, the impact of the second rig does not kick in until the second half of the year. So you will have some very moderate decline in oil. And then as I mentioned before, on a total production basis, it will be a function of NGL prices. We fully expect NGL prices to normalize in the second quarter, so you get some pickup in the second, third, fourth quarter as NGL prices normalize.

Okay, thanks. And then maybe one in Guyana. I know it may be early, but given the differences in both development plan and capital budgets for Phase Two and Phase Three developments in Guyana, can you talk a little bit about expectations for FPSO4, whether resource density and infrastructure requirements would kind of lean more one way or the other in terms of implications for the capex budget going forward?

Sure. And then I'll give the capital to John Rielly. But Yellowtail is again a very high quality reservoir, and we would expect it to be between Lisa Two and Payara in terms of its breakeven oil price. So somewhere between that $25 and $32 breakeven is where we anticipate Yellowtail will come across because this is an extremely high quality reservoir and very high quality fluid. So that's one of the reasons it's jumping forward in the queue and really being the next cab off the rank, if you will, because it's a very high value development.

Ryan, I wanted to add one thing to my Bakken comment last time. Also remember, in the third quarter we have the Tioga gas plant turnaround, so you will see a dip in production in the third quarter. But that's all gas primarily. Oil is going to be rocking along just fine.

Okay, perfect. Thanks, Greg.

Thank you. And our next question comes from the line of Roger Reed with Wells Fargo.

Yeah, thank you. Good morning.

Good morning.

Just wanted to ask one question on Guyana in reference to the expectation that Phase One can maybe move above nameplate. I know earlier in 2020 there were some surface issues, and so as you look at the ability to go above, can you kind of give us an idea of how much of this is subsurface outperformance, how much of it is surface de-bottlenecking, and maybe just a more broad understanding of how the wells themselves have been performing?

Yeah, so thanks for the question. First of all, the wells are performing extremely well. These reservoirs are some of the best in the world. The wells continue to do as good or better than we thought. So any constraints, if you will, that have occurred in 2020 have purely been a result of the topsides. Now, for the last week, we've been operating around 127,000 barrels a day pretty steadily in Phase One. And as you mentioned, the operator now is conducting studies to put a project in place to further increase that capacity. Plans are to do that in the third quarter. So we'll have a shutdown period to be able to do that. It's going to be piping changes and basically just de-bottlenecking some tight spots that you might have in the facility. So that's why our forecasted volumes for 2021 are 130,000 barrels of oil met, because you get some pickup from that optimization that the operator is planning to do, offset a little bit by the shutdown time required to do it. But this vessel will definitely have higher throughput next year.

Okay, great. Thank you. Meaning this year and next year, right? Great. Yeah, sorry. 21. Sorry, John. You got me again. Okay, thanks.

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

Thank you. Good morning, guys.

Good morning.

Thank you. You talked about Yellowtail being good quality and all that, that's wonderful. Can you give some preliminary expectation, what is the unit development cost? Is that comparable to Lisa 2, or more like Payara?

No, as I said, Paul, I think this development is probably going to fall between Payara and Phase Two. So somewhere closer to Phase Two. You could assume development costs be very similar, somewhere between Phase Two and Payara. These are very good reservoirs, very high deliverability, very high quality crude oil. That's why the breakeven is in between the two. It really comes down to just how much infrastructure you will need. But it won't need as much as Payara, maybe a little bit more than Phase Two.

Okay. And you mentioned about the two-rig drilling program. Two questions on there. First, what is the oil production that you will be able to do based on that? I mean, we understand the gas will swing due to the capture rate, but you're saying that oil will be pretty steady, so what's that number that you expect? And with that, based on where you see today, the program that you expect for the next several years, even with a change in the commodity prices, how would that impact that program?

And to be clear to everyone on the phone, the oil cut at the wellhead has not changed. No, what the oil cut changes is downstream — how much gas we capture, how many wells we're bringing online, and what the NGL prices are. So the quality of oil at the wellhead is the same. That percent hasn't changed. Now what changes in the corporate accounting is due to what happens downstream, as I mentioned.

Yep, a great show. What is that oil production that you expect the two-rig program can do?

Okay. And the next one is for John Rielly. John, your DD&A expectation for the year is really low compared to your fourth quarter. Your fourth quarter ex-NMB you probably did close to 16, and you're expecting it to be at 12 to 13 for the first quarter as well as for the full year. So where are we seeing that big drop in your DD&A?

Sure. The driver of this is the increase in our year 2020 proved developed reserves. So you saw our reserve replacement, but another aspect of this is that our proved developed reserves are up to about 70% of our proved reserves, so it's up 13% year on year excluding the asset sales. So you've got Bakken, proved developed reserves still net even after price revisions, you have Guyana again picking up proved developed reserves as more and more wells and the performance from Phase Two. And then you've got a good amount of transfers from PUDs that moved into proved developed reserves, approximately 100 million barrels there, offset by current production. So it's really the driver of proved developed reserves increasing significantly from last year. And then you have a combination of a year-over-year production mix. So as I mentioned, Guyana right now is below our portfolio average, and so Guyana's production is increasing, so that's going to overall drive down the DD&A rate. And again, Bakken's DD&A rate, while still higher, is coming down from 2020 just due to the proved developed adds. So again, a good year for reserve adds.

A final question on the Gulf of Mexico. How many permits do you currently have? If you have any.

I understand you're not going to do anything, but I just want to see if you have any permits in hand given that the permit can last for two years and then possible extension. You know, let's see where the President comes out on what drilling regulations are.

Right. Okay. Thank you.

Thank you. And our next question comes from the line of Bob Brackett with Bernstein Research.

Good morning, all.

Good morning, Bob.

I'll risk a bit of a long-winded question. So the Lisa FPSO Destiny had a mid-year 2019 departure from Singapore and a single installation campaign, which resulted in first oil on December 20th of 2019, same year. You've mentioned that Lisa Unity FPSO has a mid-year 2021 departure from Singapore, it has two installation campaigns, and obviously more risers and umbilicals. How should I contrast the timeline of hookup, integration, commissioning, and then ultimately the shape of the production ramp for Unity versus Destiny?

Yeah, so Bob, you're right, there's two installation programs. That's why officially first oil is early 2022. Now, because of those two programs, there is still some contingency in the project. So if everything goes right, you could maybe get that vessel on just a little bit earlier. All going very well. As I said in my remarks, the project is 85% complete. The vessel is due to sail away early in the summer, get it on location, and then do that very active hookup program. That will put first oil squarely in the early part of 2022. Now, the ramp, as I mentioned earlier, we anticipate that ramp will go much smoother than Phase One, and that's because all of the learnings, which were in the gas system, have been applied to the gas system on Phase 2 because of very similar equipment as in Phase 1. So we very much expect the ramp would occur over say a three-month period because you bring things on and you measure dynamics, you got vibration sensors everywhere. That's a pretty normal cadence to bring something like that on — over a three-month period.

Great, thanks for that. Thank you.

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