赫斯 (HES) 2020 Q4 法說會逐字稿

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. (Operator Instructions)

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

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 Factors section of Hess' 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.

Thank you, Jay. I would like to welcome everyone to our fourth quarter conference call. I hope you and your families are well and staying healthy during these challenging times. Today, I will review our continued progress in executing our strategy. Then Greg Hill will discuss our operations and John Rielly will review our financial performance.

Our strategy has been and continues to be to grow our resource base, have a low-cost of supply and sustained cash flow growth. Our differentiated portfolio is balanced between short cycle and long cycle assets with our focus on the best rocks for the best returns. The Bakken, deepwater Gulf of Mexico and Southeast Asia are our cash engines and Guyana is our growth engine. Guyana becomes a significant cash engine as multiple phases of low-cost oil developments come online, which we believe will drive our company's breakeven price to under $40 per barrel Brent and provide industry-leading cash flow growth over the course of the decade.

As our portfolio generates increasing free cash flow, we will first prioritize debt reduction, and then increase cash returns to shareholders through dividend increases and opportunistic share repurchases.

Turning to 2020, we achieved strong operating results, overcoming difficult market conditions and the challenges of working safely in the pandemic. I am extremely proud of our workforce for delivering production in line with our original guidance despite a 40% reduction in our capital and exploratory expenditures.

In response to the pandemic's severe impact on oil prices, our priorities have been to preserve cash, preserve our operating capability and to preserve the long-term value of our assets.

In terms of preserving cash, we came into 2020 with approximately 80% of our oil production hedged with put options for 130,000 barrels per day at $55 per barrel of West Texas Intermediate and 20,000 barrels per day at $60 per barrel of Brent. To enhance cash flow and maximize the value of our production, last March and April, when U.S. oil storage was near capacity, we chartered 3 very large crude carriers or VLCCs to store approximately 2 million barrels each of May, June and July Bakken crude oil production. The first VLCC cargo of 2.1 million barrels was sold in China at a premium to Brent in September. And the second and third VLCC cargoes have been sold at a premium to Brent for delivery in the first quarter of 2021.

We reduced our capital and exploratory spend for 2020 by 40% from our original budget of $3 billion, down to $1.8 billion. The majority of this reduction came from dropping from a 6 rig program in the Bakken to 1 rig. We also reduced our 2020 cash operating costs by $275 million.

In 2020, we strengthened the company's cash and liquidity position through a $1 billion 3-year term loan, initially underwritten by JPMorgan Chase. In addition, we have an undrawn $3.5 billion revolving credit facility and no material debt maturities until 2023.

During the fourth quarter, we closed on the sale of our 28% interest in the Shenzi Field in the Gulf of Mexico for a total consideration of $505 million, bringing value forward in the low-price environment. In terms of preserving capability, a key for us in 2020 was continuing to operate 1 rig in the Bakken. Greg Hill and our Bakken team have made tremendous progress over the past 10 years in lean manufacturing capabilities and innovative practices, which have delivered significant cost efficiencies and productivity improvements that we want to preserve for the future.

In terms of preserving the long-term value of our assets, Guyana, with its low-cost of supply and industry-leading financial returns, remains our top priority. On the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, 2020 was another outstanding year. 3 oil discoveries during the year at Uaru, Redtail-1 and Yellowtail-2 brought total discoveries on the Stabroek Block to 18. The estimate of gross discovered recoverable resources on the block was increased to approximately 9 billion barrels of oil equivalent, and we continue to see multibillion barrels of future exploration potential remaining.

In December, production from Liza Phase 1 reached its full capacity of 120,000 gross barrels of oil per day. The Liza Phase 2 development is on track to achieve first oil in early 2022 with a capacity of 220,000 gross barrels of oil per day.

Another key 2020 milestone was the sanctioning of our third oil development on the Stabroek Block in September at the Payara field. Payara will have a capacity of 220,000 gross barrels of oil per day and is expected to achieve first oil in 2024.

Turning to our plans for 2021. To protect our cash flows, we have hedged 100,000 barrels per day, with $45 per barrel WTI put options and 20,000 barrels per day with $50 per barrel Brent put options. Our 2021 capital and exploratory budget is $1.9 billion, of which, more than 80% will be allocated to Guyana and the Bakken.

Our 3 sanctioned oil developments on the Stabroek Block have breakeven Brent oil prices of between $25 and $35 per barrel, world-class by any measure. Front-end engineering and design work for a fourth development at the Yellowtail area is underway, and we hope to submit the development plan to the government for approval before year-end.

We continue to see the potential for at least 5 FPSOs to produce more than 750,000 gross barrels of oil per day by 2026, and longer term, for up to 10 FPSOs to develop the current discovered recoverable resource base. We will continue to invest in an active exploration and appraisal program in Guyana in 2021, with 12 to 15 wells planned for the block. The Hassa-1 exploration well recently encountered approximately 50 feet of oil-bearing reservoir in deeper geologic intervals. Although the well did not find oil in the primary shallower target areas, the Hassa well results confirm a working petroleum system and provide valuable information about the future exploration prospectivity for this part of the block.

In the Bakken, we plan to add a second rig during the first quarter, which will allow us to sustain production in the range of 175,000 barrels of oil equivalent per day for several years and protect the long-term cash flow generation from this important asset.

As we continue to execute our strategy, our Board, our leadership team and our employees will be guided by our long-standing commitment to sustainability and the Hess values. We are proud to have been recognized throughout 2020 by a number of third-party organizations for the quality of our environmental, social and governance, performance and disclosure. In December, we achieved leadership status in CDP's annual global climate analysis for the 12th consecutive year, and earned a place on the Dow Jones Sustainability Index for North America for the 11th consecutive year.

In summary, our priorities will remain to preserve cash, preserve capability and preserve the long-term value of our assets. By investing only in high-return low-cost opportunities, we have built a differentiated portfolio of assets that we believe will provide industry-leading cash flow growth for over the course of the decade. As our free cash flow grows, we will first prioritize debt reduction and then return of capital to shareholders, both in terms of dividends and opportunistic share repurchases.

I will now turn the call over to Greg for an operational update.

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 6 rigs to 1 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-and-perf completions, increased natural gas capture and the quality of our acreage position.

Third, in Guyana, we made significant advances on all 3 of our sanction developments on the Stabroek Block, with Liza Phase 1, reaching it's full production capacity in December, Liza Phase 2 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 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 full year guidance of 180,000 barrels of oil equivalent per day, despite dropping from 6 rigs to 1 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 2-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 cost 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 4 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 full year forecast reflects the impact of a planned 45-day shutdown of the Tioga 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 plan 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 to hurricane recovery downtime at 2 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 3 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 multibillion barrels of exploration upside on the Stabroek Block, and we are planning an active exploration program in 2021.

In March, the operator will bring a fifth drillship, the Stena DrillMAX, 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 Santonian 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 2 exploration wells and 2 appraisal wells on the Stabroek Block. The next exploration well to be drilled is Koebi-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 Carron 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 and geologic intervals. The Stena DrillMAX 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 DrillMAX.

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, to sail from the Keppel Shipyard in Singapore to Guyana by midyear.

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 interest 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; 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 noncontrolling interests, 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 price -- 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 million to $35 million in the first quarter and $170 million to $180 million for the full year 2021. The midstream tariff is projected to be in the range of $265 million to $275 million in the first quarter and $1.09 billion 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 million to $35 million for the first quarter and $80 million to $90 million for the full year 2021.

As highlighted earlier, we have purchased crude oil hedge positions for calendar year 2021. We expect noncash 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 million to $80 million in the first quarter and $280 million to $290 million for the full year 2021.

Corporate expenses are estimated to be in the range of $35 million to $40 million for the first quarter and $130 million to $140 million for the full year 2021. Interest expense is estimated to be in the range of $95 million to $100 million for the first quarter and $380 million 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.

(Operator Instructions) Our first question comes from the line of Jeanine Wai with Barclays.

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

Yes, Greg?

Yes. Thank you, Jeanine. First of all, the results of the Redtail well and the test were very positive. And so 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. And 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 of this year. So very exciting results and very exciting dividend coming forward.

Okay, great. 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 the results -- depending on the results of the appraisal at Mako that, that could get moved up in the queue. And I was just wondering what you're seeing at Mako that puts it ahead of maybe some of the other potential development areas.

Greg?

Yes, sure, Jeanine. So what we said was that, assuming good results at Mako and Uaru-2 , that, remember, is very close to Liza-2, and it's kind of in between Yellowtail and Liza-2. 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 we want to move forward.

And that could potentially be the fifth ship, basically.

Sure. Yes.

Our next question comes from the line of Doug Leggate with Bank of America.

Happy New Year, guys. Greg, let me start with Hassa and the somewhat cryptic prescription John gave of the deeper horizons. You've talked about the possibility of the 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 Hassa? And if so, why would you describe it as -- I guess, how would you describe it? Is that a successful well or is that an unsuccessful well? How have you reported it to the government?

Well, I think -- look, while the Hassa well 1 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 sections. So further evaluation of these deep results are going to be incorporated in our future exploration development plans for the area, and we'll 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 would that be reported as a discovery then to the government?

No because the well is still under evaluation.

Okay. All right. My follow-up, John Rielly, you've obviously locked-in some production. Can you talk about the -- I don't know if you missed that in your prepared remarks, but the amortization schedule, and most 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 basically, it's a free cash flow question and a balance sheet question for 2021.

Go ahead, John.

Sure. So I think first, you were saying, 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, again, this is a big year for us just to kind of complete the development of Liza Phase 2.

And as you know, when Liza Phase 2 comes on, look, it's approximately 60,000 barrels a day of Brent-based production. The cash cost of that Liza Phase 2 is going to be more around $10 pre any purchase of the FPSO versus the first one being at $12 just from the economy 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 2 comes on.

So for this year, Doug, from a cash flow stand, what were we looking to do? So 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 effectively, 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 2 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, I mean, 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, here from that standpoint. And therefore, at these higher prices, obviously, this helps with our funding program here for Guyana. So when Phase 2 comes on, depending on where prices are with our insurance now, we know we're going to have a nice cash cushion at that, and then we're going to be in the 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, 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 2 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've put ourselves in a good position with a very strong cash position, hedges, protection. Should be a nice year with prices at this level, and then a big inflection when Phase 2 starts.

And if I can make a complement to what John is saying, the priority once we get to that free cash flow inflection is to pay down our term loan. And then after that, the majority of the free cash flow will increase cash returns to our shareholders, prioritizing the dividend first.

So John, not to labor the question. So you're happy with about a $5 billion debt. Is that the implication?

With when -- if we pay down that term loan debt? Yes. 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 2x target fairly quickly. So yes, that's where we'd like to be, right, to get that term loan paid off. And then as John said, then we start increasing dividends and opportunistic share repurchases.

And our next question comes from the line of Arun Jayaram with JPMorgan.

Yes. 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 post the 60-day moratorium. And perhaps as well to John Rielly, thoughts on IDCs and how -- I know you have a pretty material NOL balances, but just thoughts on risk to IDCs as well.

Yes. No, Arun, great question. Obviously, we also understand the President will make an announcement later today on federal lands and also some points, I think about climate. I think it's important for everyone to realize that only about 2% of our Bakken acreage is on federal land.

So this announcement will not have an impact on our Bakken activities. And in the deepwater Gulf of Mexico, as you heard Greg say earlier that we have no drilling planned for this year in the deepwater Gulf. And it remains to be seen what he's going to say about existing acreage and drilling permits for the deepwater, but we have no drilling plan this year.

I think the most important point here is that the administration, as it makes these decisions to address climate change, that they have to be not only climate literate, but energy literate. And they have to realize that oil and gas are a strategic engine for the U.S. economy, especially at a time that we're trying to recover the economy from COVID. And that importance is in jobs. We have over 12 million direct and indirect jobs.

In terms of low energy costs for our working class families, our power costs, in large part because of shale gas are half what they are in Europe, and in terms of national security, where we're energy independent, in large part because of shale oil and shale gas. So it's just a question of finding the balance here. And hopefully, as the administration moves forward, they will extend the hand as well we define common ground to make sure we do everything we can to address climate change, but also that oil and gas play a key role in the economy's recovery.

And John, you want to talk about the IDCs?

Sure. So you are right, Arun. For us, so 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 UOP 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 to the IDC, that 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 you could maybe get us oriented in how or where your expectations are for Liza-1 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 Liza to with the bigger boat.

Yes, go ahead, John.

Yes. So for Liza Phase 1, it's $12 per barrel basically, and now, we're at full capacity here. That's the cash cost per barrel while we're in the rental period, and you're correct, we have it in our numbers for the whole year. Post an FPSO purchase, it will drop down into the $8 to $9 type range for Liza Phase 1.

As I mentioned, Liza Phase 2, actually, 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, by the way, going to help our DD&A rates.

So right now, Liza Phase 1, the current DD&A rate is below our portfolio average, again, due to the low F&D costs. So when Liza Phase 2 comes on, ultimately, when it's up full and running here and you get to the full scale, again, 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.

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

I wanted to start on the Bakken. You've highlighted that the beats on production, on a BOE a day basis, has come from -- in part, from gas capture and then some of the impacts of pricing on NGL contracts and percent of proceeds contracts. On a forward-looking basis, I wondered, 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 capturing?

Greg?

Yes. So let me start with flaring, Brian. So 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 together as much gas as we possibly can.

Now if we talk about the oil, so the decline in oil is purely related to the wells online. So in Q3, we had 22 wells online. In Q4, we had 12 wells online. And in Q1, we only added -- in Q1 of this year, we will only put 4 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 with that second rig.

So again, it's really just a mix issue of gas that changes your percentage on a total company basis. And then the oil is purely a function of the wells online. But that will stabilize, the company will stabilize 175,000 barrels a day flat for a number of years.

Great. And then, second question goes back to Guyana. Now that you've gotten Phase 1 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 2 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?

Greg?

Yes, Brian, thanks for that. Certainly, I would expect the ramp-up of Phase 2 to go faster because, as you say, all of those learnings have been incorporated into the ramp of -- into Phase 2. 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 2.

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

Just as a follow-up question to the Bakken, I'm sorry if I just missed this. But when you guys start to stabilize around the 175,000 range or around there, what does the production mix look like or does that still kind of change on a quarterly basis, just based on some of the well timing?

Greg?

Yes. So of course, you'll always get -- there's 2 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, of course, the bigger thing when I'm talking about total production on a barrel equivalent basis is really all the gas we're gathering, including third-party volumes, which remember, a portion of that is subject to a 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 a 2-rig program. And then for the whole company, the 175,000 barrels a day equivalent would be flat with the 2 rigs.

Got it. Understood. And then just curious on the balance sheet and asset sales. Obviously, you sold Shenzi late last quarter to help support the cash balance there and Guyana development. I know some of this will be opportunistic, but these are cash flowing engines of the company. 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 had the -- looked at as an asset for sale. So just curious if there will be some ongoing divestiture program as Guyana ramps up.

Yes. Obviously, in the normal course of business, as we've shown, we always look to optimize our portfolio, where we see value opportunities, where there are opportunities to sell assets that meet our value expectations. Obviously, that was the case in Shenzi. And there are maybe a few cases where there are some assets -- other assets, as you mentioned, that may meet that criteria as well. So if they meet our criteria for value expectations, we'll move forward, but commenting more than that would be inappropriate.

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

Maybe one follow-up on the Bakken to start. I mean, can you provide any additional color on the expected trajectory, at least in general, of 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 an exit rate that's closer to the 175,000 barrel a day long-term target?

Yes. Greg?

Yes. I think that's fair, yes, 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, will be a function of NGL prices, right? 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. 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 2 and Phase 3 developments in Guyana, can you talk a little bit about expectations for FPSO 4, whether resource density and our infrastructure requirements would kind of lean more one way or the other in terms of implications for the CapEx budget going forward?

Yes, Greg, you might talk about the reservoir and oil quality there and the attractiveness of the economics.

Sure. Yes. So -- and then I'll give the capital to John Rielly. But Yellowtail, again, very high-quality reservoir, and we would expect it to be between Liza-2 and Payara in terms of it's breakeven oil price, right? So somewhere between that $25 and $32 breakeven is where we anticipate Yellowtail will come across because, again, this is an extremely high-quality reservoir and very high-quality fluids. So that's one of the reasons it's jumping forward in the queue and really being kind of the next cab off the ranking, if you will, because it's very high-value development.

Brian, I wanted to add one thing to my Bakken comment last time. Also remember, in the third quarter, we had 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 signed.

And our next question comes from the line of Roger Read with Wells Fargo.

Just wanted to ask one question on Guyana. In reference to the expectation that Phase 2 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 debottlenecking, and maybe just a more broad sort of understanding of how the wells themselves have been performing?

Greg?

Yes. So thanks for the question. First of all, the wells are performing extremely well. I mean, 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 as a result of the top sides.

Now for the last week, we've been operating at around 127,000 barrels a day, pretty steady in Phase 1. And as you mentioned, the operator now is conducting studies to put a project in place to further increase some of that capacity. Plans are to do that in the third quarter, so we'll have a shutdown period to be able to do that. That's going to be piping changes and basically just kind of debottlenecking some tight spots that you might have in the facility.

So that's why our forecasted volumes for the year 2021 are 30,000 barrels of oil net to us because you get some pick up 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.

Meaning this year and next year, right, Greg?

Yes. Sorry, '21. Sorry, John. You got me again.

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

You're talking about the Yellowtail, it's good quality and all that, that's wonderful. Can you make some preliminary expectation, what is the unit development cost? Is that comparable to Liza-2 or more like Payara?

No. As I said, Paul, I think this development is probably going to fall between Payara and Phase 2. So somewhere closer to -- we believe it'd be closer to Phase 2. And so you could assume development costs be very similar, somewhere between Phase 2 and Payara.

These are very good reservoirs, very high deliverability, very high-quality crude oil. That's why that breakeven is in between the 2. It really comes down to just how much infrastructure will you need, but won't need as much as Payara. May need a little bit more than Phase 2.

Okay. And you mentioned about the 2 rig Bakken program. Two questions on there. First, what is the oil production that you would 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 whether that, based on where you see today, yes, we need the program that you expect for the next several years that even with the change in the commodity prices, how that impact that program?

Well, let me start with your second question first, Paul. As we've said, our plan is to hull 2 rigs through 2021. Now assuming oil prices improve in the future, what we'd like to do is eventually get the rig count to 4 in the Bakken. By getting the rig count to 4 will not only generate significant amount of cash flow, but we'll also be able to hold production in the Bakken broadly flat at around 200,000 barrels a day equivalent for almost 10 years. Why would we want to do that? Because we have 1,800 well locations left that, at current prices, generate very high returns.

Now then if I look at this year's program, in particular, remember, I'm going to bring 45 wells online this year. The program is very similar to last year at the IP180s will be the same as last year, 120,000 barrels of oil IP180, very good wells. And at current returns, if you look at the IRR of that program this year of those 45 wells, it's 95% rate of return.

And so I've got another -- after this year, I'll have another 1,750 wells that are in those very high returns that, of course, I want to get -- I'd like to develop. But I think, as we've said before, Paul, the role of the Bakken in the portfolio is to be a cash generator. So the rate at which we invest in the Bakken will be a function of corporate cash flow needs. But you can see the pent-up potential in the Bakken is very large, with some very good return opportunities.

And to be clear to everyone on the phone, the oil cut at the wellhead really has not changed. The oil cut changes is downstream, how much cash 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. What changes in the corporate accounting is due to what happens downstream, as I mentioned.

And Greg, so what is that oil production that you expect the 2-well program can do?

Well, I think broadly, once this level is out, I think broadly, you can expect oil around 90,000 barrels a day in the third and fourth quarter.

Okay. And the next one is for John Rielly. John, your DD&A expectation for the year is really low. Comparing to your fourth quarter, your fourth quarter (inaudible), you probably do close to $16. And you're expecting it going 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 unit DD&A?

John?

Sure, Paul. Yes. Thanks, John. The driver of this is the increase in our year-end 2020 proved developed reserves. So you saw our reserve replacement. But I guess another aspect of this is that our proved developed reserves are up to about 70% of our proved reserves. So it's up 13% over -- year-on-year, excluding the asset sales.

So you've got Bakken, obviously, proved developed reserves adds still net even after price revisions. You have Guyana, again, picking up proved developed reserves here as as more and more wells in the performance from Phase 2. And then you've got a good amount of transfers from puds that moved into proved developed reserves, approximately 100 million barrels there. And it's offset, obviously, 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 year-over-year production mix. So as I mentioned, Guyana, right now, it 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 that you currently in-hand? Do you have any?

Paul, we don't need any permits this year at all. We are not planning any activities this year.

I understand -- Greg, I understand that you're not going to do anything, but I just want to see that if you have any permit that in-hand, given that the permit can last for 2 years, and then possible that for extensions?

No. Let's see where the President comes out on what his drilling regulations are. And then right now, we don't have any permits in-hand because we don't have any need for the next year.

Your next question comes from the line of Bob Brackett with Bernstein Research.

I'll risk a bit of a long-winded question. So the Liza FPSO Destiny had a midyear 2019 departure from Singapore and a single installation campaign, which resulted in first oil on December 20, 2019, the same year. You've mentioned the Liza Unity FPSO has a midyear 2021 departure from Singapore. It has 2 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?

Go ahead, Greg.

Yes. So Bob, you're right. I mean, there's 2 installation programs. That's why officially, first oil is early 2022. Now because of those 2 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, right?

So all going very well, as I said in my remarks, project is 85% complete. Vessel due to sail away early in the summer, get it on location and then do that very active hookup program that will put a square of little bit the first oil in the early part of 2022.

Now the ramp, as I mentioned earlier, we anticipate that ramp will go much smoother of course, than Phase 1, and that's because all of the learnings, which were in the gas system, remember, all of the learnings have been applied to the gas system on Phase 2 because of very similar up equipment as in Phase 1.

So very much expect the ramp broadly would occur over, say, a 3-month period because you're going to -- you bring things on and you measure dynamics. You've got vibration sensors everywhere. That's a pretty normal cadence to bring something like that on is over a 3-month period.

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