Cairn Energy's (CRNCY) CEO Simon Thomson on Full Year 2019 Results - Earnings Call Transcript

Cairn Energy PLC (OTCPK:CRNCY) Full Year 2019 Earnings Conference Call March 10, 2020 5:00 AM ET

Company Participants

Simon Thomson – Chief Executive

James Smith – Chief Financial Officer

Paul Mayland – Chief Operating Officer

Eric Hathon – Director of Exploration

Conference Call Participants

Sasikanth Chilukuru – Morgan Stanley

Al Stanton – RBC

Simon Thomson

Good morning, everybody, and welcome to Cairn’s results presentation. I’m Simon Thomson, Chief Executive. With me are James Smith, CFO; Paul Mayland, COO; and Eric Hathon, Exploration Director. So as an usual way, we’ve got a presentation to run through with you this morning, and we’d be happy to take questions at the end. It is being webcast, so there will be microphones available if you have a question, and please state your name.

For those who are listening on the webcast, we have a lower attendance than usual in the room for obvious coronavirus-related reasons. So I know that a couple of people have e-mailed in questions. And we will attempt to deal with them during the course of the presentation. But please, if there are follow-up questions, don’t hesitate to get in contact with us and we will answer them.

I guess, just a brief word before launching into the presentation in respect of the current volatile price environment. Back in 2013, after the last big return of cash when we rebuilt the company, we designed a company that had balance sheet strength and financial flexibility. We can’t predict the oil price, but we wanted to ensure that we could remain relatively strong through cycles.

And as you all know, we’ve been here before. It was the beginning of 2016, I think that the oil price hit $27 a barrel, and we were in the middle of two major developments in the North Sea, which are now obviously on stream. I think the point that we will endeavor to reiterate through the course of this presentation is that, as a company, we have the strength and the financial flexibility to remain flexible and to deliver all of our strategy through this period of price volatility.

So if we look at the first slide; 2019 was focused on three core disciplines; operational delivery, financial flexibility and capital allocation. And I’ll just deal with each of those in turn. So when we look at operational delivery, we had a strong year in terms of production. So Catcher averaged around 95%, vessel uptime through the year. And Kraken, which as you know, previously had problems with FPSO performance, started the year at uptime rates of less than 60% in Q1, but ended the year in Q4 with uptime rates of greater than 90%. And that performance for both fields has continued to date. So strong production performance on a continuing basis, and as you know, as we’ll cover off, there are additional wells in each of those projects through the course of this year.

Reached a major milestone in Senegal with the final investment decision for Sangomar, and that field now enters the build phase and James and Paul, will both provide detail on the funding and on the project schedule.

The FID resulted in a 150% 2P reserves increase for the group, added to from small additions also from the write-back in Kraken, booking of Worcester as well and also a small increase on Catcher. And whilst we didn’t have success in the North Sea, we did encounter success with ENI in Block 10 in Mexico. And as you know, we’re about halfway through our Mexican exploration program. We’ve had two wells that haven’t been successful, Alom and Bitol, which we talked about in the announcement today. And Eric will provide more detail on them, but we have had success on Saasken, which could form the potential for a commercial hub development.

Looking next at financial flexibility; as I said at the beginning, probably one of the most important things. So when we look at the period of current volatility, we remain strong in that respect. So the – that strong production performance resulted in cash flow at the upper end of guidance, just over $0.5 billion of sales revenues. In addition, we had net cash at the year-end – improved net cash position year-on-year of $150 million and another $100 million to come from the sale of our business in Norway.

Our RBL facility of $575 million remains undrawn. And James will also talk about the hedging that we’ve entered into. And that will be a continued focus for us, that fiscal discipline, throughout the course of this year and onwards. And I think also, it’s worth noting that the fiscal discipline resulted in a very rigorous approach to capital allocation through the course of 2019. So 2019 saw active portfolio management.

The sale of Norway generated from two attractively priced transactions, which is now fully completed, generated $185 million of sales proceeds, dollars, but also importantly, avoided future CapEx of $200 million. In addition, when we think about fiscal discipline, we exited exploration positions in Ireland and Nicaragua, where further investment was not warranted from our perspective on a risk-reward basis. And that will continue to be a focus for us as we look at ranking the exploration portfolio on an ongoing basis.

And a sign of, I think, continued sort of exploration focus in terms of trading, we announced today a swap with Shell on ground floor basis, 50-50 swap of blocks in South of Nelson. That leads to two exploration wells; it’s infrastructure-led, attractive NPVs, attractive region, and Eric will talk more about that. And in terms of our portfolio as a whole, and I know there’ll be questions on Sangomar. But in terms of our portfolio as a whole, we continue to look at when is the right time to trade, when is the right time to realize but to ensure that we’re in a position where we don’t have to.

And lastly, in terms of India, there is no change there. The arbitration award, we’ve been told by the panel, is expected in the summer of 2020. There isn’t a defined date. We remain confident in our position. And as a reminder, that’s a $1.4 billion claim.

Okay. Looking at the next slide, everything that we do, we do on a responsible basis as a company within a volatile world in a world where there is increasing focus on transition to lower carbon economies. Obviously, we’re not an operator of production. But as you can see there in the first bullet on the left, our production at Catcher and Kraken does fall under the EU emissions trading scheme and we monitor that along with our partners in terms of compliance. We also, along with the other members of BRINDEX are focused on supporting the government and the initiative of net zero by 2050. And we monitor and report on our own emissions and have target sets in relation to reductions of those and that’s linked directly to our KPI remuneration and also reinforced by alignment with the task force for climate-related financial disclosures.

And I think the important thing is to reiterate is that all of this for us falls within the three Rs, respect, relationship, responsibility, and it’s what we will continue to do and have done as a company throughout our existence as we look to add further value for shareholders.

And on that, adding value point, we are very conscious of the fact that in that world of volatility, in that world of transition, our portfolio needs to be resilient. For us, capital allocation has always been a competition between securing low breakeven projects, exploring where we think it’s the right thing to do and obviously looking to return money to shareholders ultimately.

And when you look at that low breakeven, we’ve had independent work carried out as we did last year in relation to our resilience as a company under the IEA Sustainable Development Scenario, less than 2-degree climate increase and the halving of global oil demand. And that contemplates a number of different scenarios from smooth to disruptive and also it takes into account oil price, country risk and cost of capital. And all projects in every scenario, delivers an IRR of at least 10%. And I think it’s important to recognize that both from a transition perspective and a volatility perspective, the portfolio as a whole remains resilient. And then, of course, we will continue to test and measure against these objectives for every project we look at on a go-forward basis.

With that, I’ll hand over to James.

James Smith

Thank you, Simon. Good morning, everyone. So, on the next few slides I’ll take you through the 2019 cash flows, an update on our guidance for this year’s program, an overview of the current funding position and then a little bit more detail on the Sangomar project, which as you know, is now in development phase.

So first of all, looking back to 2019 performance, production, as you know, was strong relative to guidance of 24,000 barrels of oil a day. That generated revenues of $503 million of an average realized crude price of $64.50 a barrel. And that average realized price was slightly above Brent for the period, so that obviously indicates strong pricing relative to benchmark for our crudes and particularly for Kraken. So the all-in production cost average net to us was $17.40 a barrel, and that delivered operating cash flow from production of $390 million for the year.

Referring briefly to the P&L; given the stronger-than-expected production from Kraken during 2019 and the stabilization of water cut in the production from that field, we have increased our reserves estimate for the field, and that means that we fully reversed the prior year’s financial impairment relating to Kraken, which you’ll see flow through the P&L. Excluding that gain flowing through the P&L and other nonrecurring items, operating profit from continuing operations, i.e., excluding our Norway business for the year was $87 million.

So looking forward now to the rest of 2020, we expect production in the range of 19,000 to 20,000 barrels of oil a day, and that takes into account scheduled maintenance shut-ins during the year. And we are targeting a production cost stable with last year of below $20 a barrel.

You can see there, it’s perhaps a little bit complex to interpret, but those are our collar structure and swap hedge positions for the year. To summarize those, it equates to about 36% of our mid-case expected production for the year hedged at fixed price or floor price of $62 a barrel. So that’s just over one-third of our production hedged at $62 a barrel for the year.

So if we look now at the current sources of funding; cash on the balance sheet – reported cash on the balance sheet was $147 million, but that was before the receipt of $108 million from the sale of our Norwegian subsidiary, which completed at the end of February. So on a pro forma basis, the opening cash position was $255 million. Our Reserve-Based Lending facility remains – was undrawn at the beginning of the year and remains undrawn, and work is now well advanced to amend that to incorporate the Sangomar project and increase the facility targeting around about $1 billion of senior debt.

And finally, on this slide, you’ll see we continue to expect a ruling on our $1.4 billion arbitration claim against India in the summer of this year. But obviously, we don’t take account of the proceeds of the outcome of that in any of these funding plans.

So the next slide shows a reconciliation of our 2019 cash flows. You can see on the left-hand side, the cash inflows in the blue blocks are the opening cash position, the UK operating cash flows, the Norwegian exploration tax rebate and then the proceeds of the first 10% sale of our – or sale of our 10% interest in Nova to Oranje-Nassau, which did complete within the year, the subsequent Norwegian sale was at the beginning of this year. And then in the orange blocks, the cash CapEx during the year, that’s a total of $228 million adjusted for tax rebates and asset sales. And that was split almost exactly equally between development activities and the exploration program, again, on a post-tax basis for the Norwegian expenditure.

So then moving to the right on the chart; if you net off new ventures, admin expense and other financial adjustments, as well as the repayment of $85 million of debt that was drawn at the beginning of 2019, but repaid during the year, that takes you to our reported year-end cash position of $147 million.

Moving on now to our CapEx guidance for this year, which remains in line with the operating update published in January. So in the UK, the near-field and infill drilling opportunities to sustain production levels at Catcher and Kraken are expected to total $65 million net to Cairn. Paul will talk about those a little bit, but that’s bringing on new production in those fields at the back end of this year and the beginning of next year. Clearly, the capital focus is very much on Sangomar and the forecast net to Cairn for this year is $400 million, and I’ll come on to talk about that a bit more in the next slide.

And then finally, on exploration, the currently expected exploration cost for the year, $150 million, which covers our ongoing drilling campaign in Mexico, the first of two wells in the South of Nelson area where we announced a deal, a swap with Shell today in the UK, our expected entry into Mauritania as well as other seismic acquisition and well planning costs across the portfolio.

So just a bit of a focus on Sangomar. First of all, at the top there of the slide, a reminder of the fiscal terms, which are codified in the production sharing contract; so the state participates in three ways, directly through Petrosen, through the government share of production, which is shown in that table on the top right-hand side and also through corporation tax. That production sharing contract has now been supplemented with a host government agreement between the parties and the Senegalese state, which ensures clarity of interpretation of all the fiscal issues for all stakeholders, providers of capital as well as the participants in the project.

And obviously, as part of the project sanction, we were granted the 25-year production license for the development area, the Sangomar development area at the beginning of this year as well as a two-year exploration period for the surrounding acreage. We expect our working interest in that development area around Sangomar to reduce from 40%, which it is currently to 36.4%, if and when Petrosen exercises its right to increase its stake from 10% to 18% as it has the right to do under the PSC.

So looking at development project itself, we’ve sanctioned Phase 1, which we expect to deliver first oil in the first half of 2023 and to ramp up to 100,000 barrels a day gross fairly quickly thereafter. Total gross CapEx for the project, in line with prior guidance, $4.1 billion, including the purchase of the FPSO. So that’s $1.5 billion net to Cairn over the full year development period. Around about one-third of that relates to the FPSO, around about one-third of it relates to development drilling. And you can see there on the slide, our current expectation of the phasing of that CapEx, which is roughly speaking, evenly spread over that full year development period.

As you can see, in terms of project economics, the production costs over the life of the field are low or very low, and that drives a competitive full cycle breakeven oil price for the first phase and indeed for subsequent phases. And then the final thing today, which Simon referred to, we have had, obviously, a significant increase to our book 2P reserves as a result of the sanction of this project. We have upgraded on a net basis, $99 million – sorry, 99 million barrels of working interest resources to the 2P reserves category, and that leaves 109 million barrels of 2C resources net to Cairn.

So before I hand over to Paul, I guess, just a few words on our resilience to the current macroeconomic challenges, really just reiterating the points that I’ve made already. Our year-end – sorry, our year opening cash position pro forma for the Norway sale was $255 million, and we have no drawn debt. We’ve hedged 36% of this year’s expected production at $62 a barrel. And our all-in production cost will continue to be below $20 a barrel. So that’s effectively a cash breakeven at $20 a barrel. Longer term, our asset base is obviously focused on Sangomar, and that has very competitive full cycle breakevens, and we’ll continue to attract capital and to deliver attractive economics even at where the forward curve sits today.

Beyond Senegal, our capital commitments are relatively light and will have some flexibility. We’ve given a budget for exploration program this year of $150 million, but our committed near-term capital relating to exploration is about $100 million whilst we continue to plan around a more active program than that, the quantum and the timing are flexible. So if you take all these things together, we do feel well placed to weather these near-term price shocks and to continue to deliver value from an attractive portfolio with low breakevens. Paul?

Paul Mayland

Thanks, James, and good morning, everyone. And I’ll talk through our development and production assets and others in more detail and there will be three main themes that will emerge. Firstly, Cairn continues to deliver production within our guidance range. Secondly, we’ve successfully moved contingent resources to reserves, more significantly in the Sangomar project in Senegal. And thirdly, we continue to critically assess project value, opportunity and risk to determine the optimum time to consider potential monetization. And obviously, Nova, as James has outlined, was an example of this in 2019 when we chose to sell down in two stages; firstly, to Oranje-Nassau Dyas then to Pharos Energy, which completed a couple of weeks ago.

So I’ll start with our strong production assets in the UK. Our equity share of Catcher and Kraken delivered group production of just above 23,000 barrels of oil per day at the top end of our guidance and we continue to receive excellent pricing for both crudes in the market. As we look out into 2020 and beyond, the main objective will be to maximize production through the FPSOs and recovery from the fields by making additional robust incremental investment on both Catcher and Kraken. We will also look jointly with the respective operators to identify opportunities for energy efficiency and emissions reduction. And overall, we’re extremely pleased with these assets and how they’re producing.

On to Catcher first. So 2019 was a fantastic production year for the Catcher field. We signed an excess production agreement with BW that allowed production to exceed the nameplate capacity of 60,000 barrels a day, supported by reservoir and well outperformance. Cumulative production from the fields has now exceeded 40 million barrels in just over two years, and the respective fields are producing below the expected water cut, as outlined in the original field development plan. Consequently, we’ve revised our year-end 2019 2P reserves on the main Catcher fields upwards by around 10% compared with the position at year-end 2018.

In addition, we’ve moved the small volumes of contingent resources associated with the Laverda and Catcher North satellites into 2P reserves. Consequently, the estimated ultimate recovery from the Catcher area is now in excess of 100 million barrels. And this summer, we will acquire 4D seismic over the Catcher area to help identify further infill and satellite opportunities, some of which are already shown on the slide.

Moving on to Kraken, on Kraken, we’ve now produced an excess of 25 million barrels and last year, it averaged over 35,000 barrels of oil per day, with particularly strong performance in the fourth quarter, which has continued into 2020. And average production for the first two months of the year for Kraken was almost 40,000 barrels a day. We completed several comprehensive sets of well tests in 2019, which has given us far greater insight into individual well behavior compared with our position in 2018.

Additionally, the overall field water cut has stabilized, albeit at a level still a little above the original field development plan. Consequently, we have returned back a significant proportion of last year’s reserves downgrade. And additionally, with the commitment of further investment in the field from the joint venture, we have moved the contingent resources associated with the Worcester area on the Western Flank, now into 2P reserves. Before we move on, I’d briefly like to return to Nova.

The Nova project progressed well in 2019, particularly the subsea scope. But we decided there was an opportunity to divest an initial 10% range Oranje-Nassau Dyas when oil sat in the $60 to $70 a barrel range and then the remainder of our Norwegian subsidiary holding the additional 10% stake in Nova Sval Energi. The sale of Sval last month and we wish the team in surviving our every success in the new company. On the development front, however, the most significant event was reaching final investment decision in late 2019 on the Sangomar Phase 1 project in Senegal. This is the seventh occasion over a seven-year period that the Cairn team as part of a joint venture has contributed to selecting the concept, maturing the project via engineering and subsurface studies to robust basis for final investment, seeking government support for entry into the execute phase.

Cairn has played a significant role in the Sangomar project, particularly during the appraisal and select phases, but we could not have done this on our own and credit is due to current operator Woodside joint venture partners, Petrosen and FAR and the respective ministries in the Government of Senegal as we progress to deliver the first offshore oil project in that country, with first oil targeted in three years’ time. On FID, as James has already outlined, we moved a significant proportion of contingent resources associated with Sangomar into 2P reserves. As you are aware, the first phase of the project will develop in excess of 230 million barrels of 2P reserves from 23 subsea wells tied back to an FPSO with 100,000 barrels of oil per day capacity.

In 2020, we have acquired the VLCC, showing here, conducting what will be its final few cargoes on the high seas. Before, it will initially undertake tank cleaning in Indonesia this summer before being prepared for conversion activities in the last quarter of this year.

Detailed engineering is ongoing for both drilling and subsea and final qualification and fabrication is progressing for key drilling and subsea project scopes. The twilight [ph] design, mooting and critical module design work continues with more deck in Houston and in Singapore. And in country, in Senegal, the operator expects to finalize the base contract in Dakar and award key logistics and aviation services in 2020 for the start-up of drilling in the first half of 2021. So overall, today, the project is in a very good place, and we look forward to outlining solid progress by the operator during this year.

So finally, during 2019, we safely included three operated drilling programs in three different countries, which was first for Cairn. And on that positive note and with the Sangomar project now fully underway I’ll hand over to Eric to discuss our exploration program.

Eric Hathon

Thank you, Paul. Good morning, everyone. We have been active in exploration, particularly in two key jurisdictions, first, Norway and now Mexico. Last month, we announced the Saasken discovery offshore Mexico, Ehecatl well’s currently drilling in Block 7 operations on the Bitol-1 well in Block 9. In addition to our Mexico wells, we participated in exploration wells in Norway and the UK. Now our exploration program has not delivered the results we desire to-date, but we continue to be a company that looks to add-value through the drill bit, when the value proposition is attractive. We have drilled a number of wells focused on either new plays or play extensions. And these are wells which have the potential to be highly material, but they were also higher risk. And this was particularly true offshore Norway, where there’s a healthy rebate for an exploration spend.

Now as Simon mentioned, we are actively managing our exploration portfolio with fewer exploration wells planned in the near term. Our Northwest Europe exposure is now focused solely in the UK. We exited the Norway with the sale of our business there, and we relinquished our exploration licenses offshore Ireland. In Latin America, we have chosen to exit the four offshore Nicaragua blocks we had entered. Now the prospectivity in this frontier it does remain intriguing, but the cost of the proposed drilling solution simply exceeded our fiscal discipline limits.

In Africa, we have entered Block 7 offshore Mauritania, where we have identified very material targets on 3D seismic. We now have a high-graded portfolio, somewhat reduced in scale, but which maintains exposure to a high-quality, very material opportunity set. And most importantly, today, we have flexibility in our exploration portfolio, as James said. We’ve satisfied our exploration commitments in Block 9 offshore Mexico and have one well each in Block 7 and Block 10 to do the same. We have flexibility in 2020 and beyond, and much of our remaining activity is limited to seismic acquisition and reprocessing. Now let me expand on our current drilling activity and the results since the last update.

In Mexico, we’re halfway through our planned six-well exploration campaign. The Ehecatl well is currently drilling ahead. It’s at about 2,500 meters depth with a projected TD of 4,400 meters measured depth. Now let me provide a little bit of color on the Saasken, Alom and Bitol wells. In Block 10 we have made a discovery in pliocene sands in our Saasken in well. The net pay was above expectations, the porosity and permeability is excellent and the oil is of good quality. Testing results on the initial wells suggests a flow potential of over 10,000 barrels a day. Now this discovery is significant, not just for Block 10, but also for Block 9, where we see similar pliocene amplitudes in other leads and prospects, which thereby increases the likelihood of hubbing together multiple discoveries here.

In Block 9, our first operated well Alom targeted pleistocene sands, which had an apparent Direct Hydrocarbon Indicator or DHI on seismic. Now that indicator proved to be a false positive, but we did find a very thick section of excellent sands, and that will have potential read through to other prospects.

Now the Bitol well has just finished logging and we’re in the process of concluding operations. So results are preliminary. But we did find a very thick miocene sand section, thicker than anticipated with thermogenic gas and oil shows, but unfortunately, no reservoir hydrocarbons. It is likely that we simply had too much sand in the reservoir target area for the fault to act as an effective trap. We are in an oil-bearing system, we did have good reservoir in the well. So these are positive attributes.

Now as I’ve said before, the Sureste Basin is in the frontier at emerging phase, with relatively few wells, particularly deep miocene test, which we targeted in both Bitol and are currently targeting in Ehecatl. Now we’ve had said some success in Saasken, and we are gaining significant knowledge with every opportunity, knowledge, which will now be applied to our future activity. And our current exploration phases extend well into 2022.

I will now briefly touch on the activities in our new and maturing licenses. In the UK, our Chimera well, which is north of the Kraken field, spud in October and it was a dry hole. Now the seismic response we modeled, which we thought was a DHI was, in fact, caused by an anomalous shale response along with a silty reservoir section in the Heimdal. Despite that, it was certainly a drillable target given the potential volumes and of course, we two farminees who agreed with us and paid to promote participate.

Now as Simon said, north of the Catcher field, we have cross assigned licenses with Shell on a ground floor basis around their operated Nelson platform to drill prospects and prolific from of our sand play. Now I really like these ILX or infrastructure-led opportunities, because while the prospects are moderate in size, say 30 million to 40 million barrels discovery here has a very short-cycle time to first production. The tieback distances are very short. And subsequently, the barrels have a very high-value.

Now Shell planned to drill in the second half of 2020, and we have until fourth quarter of 2022 to drill diadem if we wish. So we’re flexible. Now with the encouragement there, there are other opportunities to target, as you can see on the map in this area.

Now turning to Northwest Africa, we have entered into Block C7 offshore Mauritania with the operator Total and is subject to government approval. There are already four discoveries on this block, and we have identified additional significant material potential. And the next exploration phase will extend into the first half of 2023.

In Senegal, we have completed a new 3D seismic acquisition and the current plan is to drill a further exploration well when a rig returns to the field. And finally, in Côte d’Ivoire, the operator, Tullow has commenced 2D seismic acquisition over our onshore acreage. And we anticipate having seismic data interpret by midyear. As I’ve shared with you before, these rift plays can be very prolific and the path to commerciality here is very clear.

Now turning to offshore Suriname. We have identified multiple targets at very stratigraphic levels on our 2D seismic data, which a grid that covers virtually the entire block. And we are in the planning stages for 3D seismic acquisition over our most promising leads. 3D seismic acquisition will satisfy our Phase 2 commitments and we have, until the fourth quarter of 2023 to do so. And we will be looking for partners in this exciting opportunity later this year.

So look, I want to leave you with this. We’ve rationalized our exploration portfolio, but we remain exposed potentially transformational plays in emerging and frontier basins. We have further wells to drill in Mexico, both exploration and appraisal. We’ve developed a multi-well infrastructure-led exploration drilling program, whilst partnering with the operator, the infrastructure in the UK and we’re maturing opportunities in Latin America, West Africa and the Eastern Mediterranean. We have flexibility in timing with few near-term drilling commitments. We will remain true to our exploration model of high grading and targeting exciting opportunities, but let me be clear, with a laser focus on being fiscally responsible in what we drill.

And with that, I’d like to turn it back to Simon.

Simon Thomson

Okay. Thanks, Eric. So as you can see, our financial flexibility strengthened through the course of 2019 through a combination of the strong production performance that we had, our active portfolio management that we’ve touched on and as Eric has just alluded to, a continued disciplined approach to capital allocation. And as a company, our focus will remain on delivering value for shareholders from a portfolio that remains resilient in a period of volatility and a period of transition. And with that, I’d like to hand over for questions. Down the front here.

Question-and-Answer Session

Q - Sasikanth Chilukuru

Hi, it’s Sasikanth Chilukuru from Morgan Stanley. I have three questions, please. First, regarding the RBL, I was just wondering if the RBL was affected by the sale of the Norway business, and it’s still at $575 million after the sale. And the expansion of the RBL itself is there a definite time line that we should expect when would be – when would you be able to confirm that, that RBL has been increased to 1 billion levels. The second question was regarding the UK assets. I was just wondering, the CapEx levels for 2020 – 2021, 2022, what would that be? And at oil prices of around $40 per barrel, would the UK business be free cash flow generative in that context? And how much would that be? Finally, on exploration, are there any commitment wells or commitments for 2021?

Simon Thomson

Sure. James, do you want to touch on the RBL first?

James Smith

Yes. I will talk about the UK production, cash breakeven, too. So on the existing RBL facility obviously, the availability under that is a product of the – in the usual way, the borrowing base calculation, which is NPV related to the field that are included in it. So clearly, the disposal of Nova removes one of the assets from that borrowing base and the facility is re-determined every six months.

You’ll see in the notes to the financial statements that we put out today that the cash availability at year end was, I think, $317 million. Following the part sell of Nova, the – in addition to that, we use about $175 million of it for guarantee facilities and other noncash tourings. So that was the status of the reporting date.

In terms of the expansion to rolling in Sangomar we did very extensive work with banks, particularly the kind of lead banks that we had originally appointed. Remember, there was an expectation, we might do a joint venture wide financing, project financing, in the end, Petrosen and others have arranged their own financing. So we’re doing it off our own balance sheets now. But we’ve taken all the work that was done last year to support rolling Sangomar into our RBL. We’re confident that can be done. We’ve talked about upsizing to about $1 billion. Clearly, we’re in the middle of a price shock. But as of today, I can tell you that banks haven’t revised their lending decks certainly out of 2023, when we’re expecting first production from Sangomar and obviously, the forward curve is still pointing to a place where Sangomar will deliver strong returns when it comes on stream.

And clearly, we wanted to get the FID and all the project definition behind us before we close this. We obviously, in the medium-to-longer term have a decision to make about our continuing equity participation in the project as well. We’ve always said that at the appropriate time and ensuring we have the flexibility to take this decision at the appropriate time, we’ll think about a farm down of the asset. But absent that, the financing will be a Q2 event.

And then on the – you were asking about North Sea cash flows, I think. So you’ve seen our targeted all-in production cost for this year. It’s not tax-paying, so that’s effectively all of the cash costs involved in that production. You’ve seen we’ve hedged 36% of our production. So I think you have all the inputs there, you need to sensitize free cash flow. But at $60 Brent, we’re generating about $300 million, $350 million of operating cash flow, if Brent remains, let’s say, $40 for the rest of this year, we’re still generating about $200 million of operating cash flow. So that’s still a significant contributor to our funding base even at a much lower Brent.

Sasikanth Chilukuru

Exploration?

Eric Hathon

Yes. We have – now that we’ve entered into a swap with Shell, there’d be one well between now and the end of 2021, that is a commitment. Of course, we have two wells left, as I said one in Block 7 and one in Block 10 in Mexico, those exploration phases end late in 2022, but ideally, you’d like to drill them earlier. But that – the only commitment we have in 2021 would be in the UK.

Simon Thomson

On the front?

Al Stanton

Yes. Al Stanton from RBC. Firstly, a quick question for James. The collars, can I just check, they are just collars, not three way collars?

James Smith

They are just playing with another collar, yes.

Al Stanton

Okay, thank you. And then with respect to the levers you can pull to reduce your deferred 2020 spending. I was wondering if there’s any phasing guidance you could give in addition to what you have already provided. So, is Catcher and Kraken, should we assume that’s all across each half and likewise, for Senegal or the Senegal build up towards the end of the year?

James Smith

Senegal is a relatively even – you’ve been phasing during the year. Within the year, so Senegal is relatively even phasing during the year. So we’ve had the first couple of cash goal through project kicked off effectively right at the beginning of the year. The work on Catcher and Kraken is underway. Paul, I don’t know if you want to comment on the drilling program for those two?

Paul Mayland

Yes, we guess. So Kraken is predominantly – it started on cracking the Worcester, so its most of the spend is in the second quarter, which Catcher spread over more in Q2 and Q3.

James Smith

And then obviously, on the exploration side, we talked about there being more flexibility in there. I mean, that represents the program for the year, we aspire to. I think under normal circumstances, things move in and out of that, and obviously, with permitting timetables and operational charges, things can slide through right anyway. But clearly, there is the flexibility for us to drive those things out in time, if that’s the right thing to do.

Simon Thomson

Any other questions?

Simon Thomson

In the absence of other questions, let me say that, just repeat what I said at the beginning, for those who are listening in, we’re very happy to deal with any questions that you might have. For some of you for those that are here, we will be around if you’ve got any follow-up that you want to talk to us about. Meantime, for those of you who made it, thanks for coming, and nice to see you. Thanks.