Andy Inglis - Chairman and CEO Brian Maxted - Chief Exploration Officer Tom Chambers - CFO Jamie Buckland - VP of IR.

Ryan Todd - Deutsche Bank Charles Meade - Johnson Rice Rafal Gutaj - Bank of America Merrill Lynch Richard Tullis - Capital One Securities Alwyn Thomas - Exane BNP Paribas Pavel Molchanov - Raymond James Niki Kouzmanov - Jefferies.

Good day everyone and welcome to Kosmos Energy's Fourth Quarter 2017 Conference Call. Just a reminder, today's call is being recorded. At this time, let me turn the conference call over to Jamie Buckland, Vice President of Investor Relations at Kosmos Energy..

Thank you, operator, and thanks to you all for joining us today. This morning, we issued a release regarding our fourth quarter earnings, which is available on the Investors page of the kosmosenergy.com Web site. On today’s call, we will review our 4Q and 2017 results as well as provide a strategy update.

And the slides that accompany the presentation are also available on the company Web site. We anticipate filing our 10-K for 2017 with the SEC later today. Joining me on the call today are Andy Inglis, Chairman and Chief Executive Officer; Brian Maxted, Chief Exploration Officer; and Tom Chambers, Chief Financial Officer.

Before we get started, I'd like to mention that this conference call includes certain forward-looking statements based on our current expectations. The risks associated with forward-looking statements have been outlined in the earnings release and in our SEC filings. We may also refer to certain non-GAAP financial measures in our discussion.

Management believes such measures are important in looking at the company's historical and future performance and these are commonly referred to industry metrics.

These measures are provided in addition to, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP and included in our SEC filings. At this time, I will turn the call over to Andy..

Thanks, Jamie, and good morning and afternoon, everyone. Before I move on to discuss the company’s strategy, I’ll start today’s presentation with a short review of 2017. Tom will follow later with the details of the 2017 financials and the guidance for 2018.

2017 was a year of strong operational and strategic delivery and one of the most successful years in Kosmos’ history. We delivered strong cash flow of more than 300 million benefitting from the BP deal in Mauritania and Senegal as well as reliable underlying performance.

We used the cash to diversify our production base with Equatorial Guinea acquisition creating another source of growth as well as paying down debt to further enhance our credit metrics.

We completed the refinancing of our reserve base lending facility earlier this month and have $1.3 billion of capacity of self-funded, new organic growth and potential inorganic opportunities.

We’ve diversified the company’s portfolio with the EG transaction which was immediately accretive and we now believe has a payback period of less than two years in the current oil price environment.

We had over 200% organic reserve replacement in the year with production growth of around 66% largely from the ramp up in Ghana, but also taking into account one month of contribution from EG.

In exploration, we completed the second phase of drilling in the emerging Mauritania and Senegal basin, a program that has discovered around 40 Tcf of gas gross at a cost around $0.20 a boe. This includes the Yakaar discovery which was the largest hydrocarbon discovery of the year in 2017 and has the potential to be a second LNG hub in the region.

Now, turning to the strategy review, we’re going to cover five topics. First, the macro environment, the importance of deepwater and meeting future supply and Kosmos’ distinctive position as a pure play deepwater company. Second, Kosmos’ strong reserve rate in Ghana and Equatorial Guinea delivering growing high-margin production.

Third, Kosmos’ pipeline of world-scale developments delivering cash flow for the long term. Fourth, Kosmos’ sustainable and balanced exploration portfolio. And finally, Kosmos’ strong financial platform. I’ll cover the first three topics. Brian will then address the exploration portfolio. And Tom will close with the financials. Turning now to Slide 3.

Kosmos is a well-capitalized, pure-play deepwater company, is ideally positioned to take advantage of the upturn in the deepwater sector. Starting from a macro level, the world needs more oil and gas to meet growing energy demand. This will come from both deepwater and shale.

The companies that were ultimately successful are those with the best acreage, the most favorable end returns and the lowest cost. In deepwater, lowest cost and reduced competition are making the sector more attractive. We have seen the majors returning, particularly in West Africa and South America.

In contrast, there’s been a consolidation on a number of players in the deepwater driven in part by a retrenchment back to the U.S. on-shore. This means there are fewer players with Kosmos playing alongside the majors in these world-class basins.

Whereas the shale companies are all starting to talk about cost inflation, we are still living in a deflationary cost environment in the deepwater and I will come on to talk about that shortly.

Kosmos has used the downturn in the energy markets over the last few years to our benefit and is well positioned to take advantage of these changing market dynamics.

Through our countercyclical approach, we have remained focus on our core strengths; consistent disciplined execution of our strategy, deployment of innovative development solutions and forming strategic partnerships where we leverage the expertise of others to deliver superior results.

As a result, we’ve built a balanced portfolio that can look forward to growth from our production assets, development projects and our exploration portfolio. We believe now is the time to invest in the deepwater and now is the time to invest in Kosmos. Turning to Slide 4, I’d like to focus on the Kosmos portfolio that we’ve built through the downturn.

We have high-margin producing assets in Ghana and EG with an operating cash flow of approximately $40 per barrel at $60 per barrel Brent. We’ve competitively positioned Tortue gas project provides the company with the next phase of growth to increase production and cash flow.

With 15 Tcf of discovered resource we believe we have the gas in place to support a 10 million ton per annum project. The $533 million carry from BP funds a substantial portion of our share of the initial phase and establishes the infrastructure for the ramp up to full development.

Initial discovered resource base from Teranga and Yakaar have the potential for a second LNG hub in the region. We have a sustainable exploration program with a balance of proven, emerging and frontier basin opportunities with multiple catalysts this year and the years to come with two to three wells expected per year.

In proven basins, like EG, we have short cycle tie-back opportunity. In emerging basins, we continue to prove up plays with significant follow-on opportunity like we’ve done in Mauritania and Senegal and expect to do in Suriname.

And in Frontier basins where we capture major acreage positions to fully explore and this includes the like of Sao Tome & Principe and Cote d’Ivoire. And behind all of this, we have a strong balance sheet and low leverage which enables the consistent execution of this strategy. Turning now to Slide 5.

The chart on the left-hand side illustrates the point I made earlier about the return of the majors to the deepwater. Kosmos is well positioned to play with and alongside these companies with one of the largest total acreage positions in West Africa and South America, excluding Brazil.

On the right-hand side, you can see how capital costs in the offshore have come down over the last few years and are still falling through 2018 before modest inflation is forecast in 2019 and 2020.

Contrast this to shale where capital costs hit a low during the downturn in 2016 and rose sharply in 2017 which is forecast to continue for the next three years. Turning to Slide 6 where we look at the competitiveness of deepwater projects versus shale. In summary, the best deepwater projects compete with the best of shale.

The chart on the left shows the breakeven price of the top quartile oil projects around the world.

You can see from the light blue bar that the best offshore oil projects have a breakeven in line or even better in the case of Jubilee and the best of shale project which include the Midland and Delaware basins in the Permian as well as Viking, DJ Basin, San Juan Basin and the Eagle Ford shale plays. The chart on the right is a reminder.

The deepwater still makes up a much larger percentage of global supply than shale today and therefore is an important source of future supply growth. Turning to Slide 8. We’ve looked at our production assets in Ghana. The Jubilee Field which Kosmos discovered in 2007 with first production in 2010 and the TEN fields we started production in 2016.

These are big fields which continue to get bigger and we have averaged a reserve replacement ratio of over 140% over the last three years.

Our production has risen steadily over 2016 and 2017 and is expected to rise further in 2018 as we resume drilling on both fields as a result of the ITLOS ruling and the Greater Jubilee Full Field Development Plan approved in 2017. Rig operations are expected to start imminently with the Maersk Venturer drillship.

The initial program is sequenced to drill one producer at TEN to one producer at Jubilee and then completion operations will begin at Jubilee. For the year we plan to drill and complete four wells in the Jubilee and TEN fields. A second rig is under evaluation by the partnership and would commence operations later in 2018.

This reflects the significant value-adding opportunity that exists in both fields. The assets we have in Ghana are high-margin barrels and we expect this to increase further as we work with the operator to drive operating efficiencies. We should deliver further margin expansion in the future.

With regard to the Turret Remediation Plan, the partnership is aligned on the engineering solution. This involves a shutdown to stabilize turret bearing this quarter followed by work to rotate the vessel to a new heading and permanently spread more of the vessel.

The Turret stabilization shutdown is being conducted in two phases, the first of which is complete and all production is back on line. The second phase is expected to commence around the end of the quarter and we anticipate the overall shutdown of oil production for both phases to be around four weeks.

It is anticipated the gas system will be shut in for slightly longer to complete non-Turret-related maintenance. We now expect the rotation of the vessel to take place around the end of the year with minimal impact to production in 2018. As a result, we expect seven cargoes from Jubilee in 2018 and four cargoes from TEN. Slide 9.

I now want to move on to our production assets in Equatorial Guinea. We announced the acquisition in late 2017 and this transaction closed at the end of November with the final consideration of $460 million gross or $230 million net to Kosmos. We’ve been very pleased with the results so far.

The acquisition gives us access to a proven oil producing basin which is well known to the Kosmos team, as Brian and a number of other colleagues originally discovered the fields in EG before they were sold to Hess in the early 2000.

We’ve identified three sources of growth; first, production optimization of the existing producing reserves base; second, the addition of new reserves to infill drilling; and thirdly, tie-back opportunities from the surrounding exploration blocks we accessed in parallel to the Hess acquisition.

Financially, the deal was highly accretive to Kosmos and we bought it at 2x EBITDAX while trading at around 7x at the time of the acquisition. We acquired more high-margin barrels to complement the high-margin production we have in Ghana. As I said, we’re pleased with the results so far.

Our acquisition case was built on gross 2018 production at 37,000 barrels of oil per day and as a result of the impact of the production optimization we’ve taken in the first two months, we are now forecasting 2018 production of 43,000 barrels of oil per day, an increase of more than 15%.

This in conjunction with a higher oil price has reduced the expected payback from around three years at the time of announcement to significantly less than two.

Operationally, we’re working in a 50-50 JV with Trident Energy whose expertise is in optimizing production and driving costs lower, an example of Kosmos using innovative partnerships to create value.

On Slide 9, looking at the year ahead in Equatorial Guinea, we expect to maximize the value of the existing resource through production optimization of existing wells, waterflood optimization and the installation of electrical submersible pumps or ESPs which should help drive further production gains in 2019.

Production on the field is currently gasless limited and the installation of ESPs is expected to enable more fluid to be lifted and as a result increase oil production. On the exploration side, Kosmos would acquire 3D seismic over the W, S and EG-21 blocks with processing expected in the latter half of the year and drilling likely in 2019.

As you can see from the chart on this slide, we will begin with infield and near field short cycle tie-back opportunity before looking at the potential of deeper, larger standalone prospects.

The slide also identifies the value added from extending field life by deferring the timing of abandonment with further opportunities currently being worked to reduce the prior operators abandonment cost estimates. Slide 11 summarizes our reserves and production across Ghana and EG, the foundational asset that underpin the base value of the company.

There are two important points to take away from this slide. First, despite material levels of production over the last three years we have continued to increase our 2P reserves with around 200 million barrels oil equivalent net to Kosmos at year-end 2017, an increase of over 35% versus year-end 2015.

Second, with the data prepared by our reserves auditor using PV-10, you can see that the 2P reserves less net debt underpins a base value of approximately $6 per share in line with our current share price. This does not include the contribution of our 3P reserves which takes a number closer to $9 per share.

This also does not include the Tortue gas development project or any future exploration success, and I’d now like to move on to those sources of growth. So turning to Slide 13 with an update on the Tortue gas development in Senegal and Mauritania where BP is leading the project.

This is a world-scale gas project which we and BP plan to develop on our accelerated timeline and it’s highly cost competitive. We’re delighted that the intergovernmental cooperation agreement was signed earlier this month which now paves the way to the final investment decision around the end of the year.

Tortue is a giant gas field with 15 Tcf resource which we expect to underpin at 10 million ton per annum LNG project with the first phase set to deliver 2.5 million tons per annum of LNG from a near shore LNG facility. First gas is confirmed by BP and their 4Q results this month is expected in late 2021.

Kosmos is largely carrier in the first phase of development through the $533 million development carry which we have in place from when BP farmed into the field. The chart on the bottom right shows this is one of the lowest cost LNG projects in the world.

The quality of the reservoir means high flow rate wells around 200 million standard cubic feet per day resulting in a low well count. This in combination with the high density of the resource which reduces the subsea footprint leads to an efficient development.

Slide 14 shows the near-shore solution, the initial phase of development with a floating LNG vessel moored alongside a jetty protected by concrete breakwater in approximately 30 meters of water 10 kilometers offshore. Gas will come from the field through our subsea pipeline onto a FPSO in approximately 100 to 200 meters of water.

The FPSO will clean the gaps, strip any liquids before a second pipeline to the FLNG vessel. With the ICA approved, the next steps towards FID include the front-end engineering which is underway and where a number of key subcontracts are expected to be awarded in the coming weeks.

The LNG marketing is also underway with gas sales agreements expected to be completed ahead of FID. At this time, I’d now like to turn the call over to Brian to review our growth prospects from our exploration portfolio.

Brian?.

Thanks, Andy. Good morning and good afternoon, everyone. Let me first turn to Slide 16. Exploration starts with strategy and driven by discipline and execution delivers results.

Our strategy is enabled by a focus on south Atlantic margin geography, deepwater petroleum systems and Cretaceous plays resulting in a concentrated portfolio with rifle shot drilling and a process maintained by organizational continuity. This focus ensures we can leverage our people and their deep knowledge to create first mover advantage.

Most importantly, this includes developing contrarian and technical ideas and pursuing countercyclical business initiatives to establish ahead of the industry wherever possible large acreage positions in selected places of choice.

In this regard and with the flexibility provided by our strong balance sheet, we have continued to consistently invest through the low commodity price cycle of recent years in contrast to industry at large as shown on the upper right image of Slide 16 and have developed a world-class portfolio of high-quality exploration opportunities.

Today, this comprises a balanced mix of proven, emerging and frontier base and assets including a key presence in each of the two recently opened giant scale, Cretaceous oil and gas petroleum systems offshore Mauritania and Senegal, Guinea and Suriname.

In drawing out this portfolio, we have firstly delivered a top quartile industry exploration success rate with an overall commercial discovery record of 1 in 5 in opening frontier basins as shown on the lower right image of Slide 16.

And secondly, through a combination of the portfolio we’ve assembled and the success we have delivered from it today, we have clear line of sight to a sustainable, high quality two to three exploration wells per year program.

I would now like to review each of the assets in the exploration portfolio starting on Slide 17 with our position in the proven inboard Rio Muni basin offshore Equatorial Guinea. As you know, we secured a 6,000 square kilometer position consistent of block EG-21, S and W alongside our recent acquisition of the Ceiba/Okume field complex.

As Andy referenced earlier, our exploration team made these basin and discoveries 15 to 20 years ago. With only limited exploration of the petroleum system undertaken since, we have the opportunity to leverage our subsequent learning and deliver further success from this underexplored basin in two ways.

Firstly to the East, the blocks include a near field exploitation opportunity comprising late Cretaceous upper slope and channel prospects as well as step-out exploration plays down sloped along trend. Together these provide short cycle time tie-back options to grow production of high-value barrels you saw in the Ceiba/Okume production facilities.

And secondly in the West, there is scope for standalone exploration of lower slope plays which provide an extension of the basin floor fan fairways we’re exploring offshore at Santonian. To progress these opportunities, a new 3D seismic survey was acquired this year ahead of drilling in 2019.

Let’s turn next to our emerging basin opportunities of Mauritania and Senegal and Guyana, Suriname. As shown on Slide 18, our exploration program today offshore Mauritania and Senegal is comprised of two phases. So far we believe we have discovered 40 Tcf of gas and delineated a further 40 Tcf of gas.

Four discoveries have been made with an exploration success rate of 60% which including the big carry is equivalent to a finding cost of $0.20 per barrel of oil equivalent. This includes 100% success rate in the first phase which tested the inboard central anticline trend and involved three discoveries; Tortue, BirAllah and Teranga.

The recently completed second phase tested four prospects with one gas discovery Yaakar, the largest hydrocarbon find in the world last year and two unsuccessful wells Hippocampe-1 and Requin Tigre-1 providing a 1 and 3 success rate on the southern Mauritania/northern Senegal gas trend.

For Lamantin-1 dry hole, we had no success with initial drilling on the northern Mauritania oil play fairway. Despite the overall success rate in opening this basin, we were somewhat surprised that the recent drilling did not fully meet our hopes and expectations and delivered even more finds, including for oil.

This was particularly the case given the positive start to the outboard basin floor fan campaign with the Yaakar discovery and each of the subsequent prospects which failed to find hydrocarbons had similar strong geophysical attribute support, including AVO.

Having matured the prospects during our extended exploration pause last year, there were all geologically valid and independent and moreover when drilled proved to be geophysically supporting our decision to drill the wells sequentially.

Notwithstanding the results, this exploration step-up campaign to test the outboard has provided us with substantial new subsurface data. These data give us competitor advantage which we can leverage on our own acreage as well as other blocks offshore Mauritania and indeed in other petroleum systems along the south Atlantic margin.

Hence, our decision to limit the amount of information shed publicly. Importantly working with BP, the interpretation and integration of these data will enable us to refine our understanding of how the petroleum systems work as well as providing calibration of our 3D seismic and its derivative products.

This will allow us to explain the exploration outcomes and observations to-date and should enhance our predictive exploration capability going forward. Furthermore, these studies are enabling us to redefine the plays and rebuild our lead prospects inventory.

We will take a second exploration drilling timeout through the rest of this year to complete this work as well as plan a third follow-on exploration campaign which we expect to start in 2019.

We anticipate this will focus on exploration appraisal in support of potential further gas ups in southern Mauritania and northern Senegal as well as continue to search for oil in northern Mauritania.

Moving on, our 2018 exploration drilling program is set to restart next quarter the testing of our other emerging basin exploration project in the current portfolio, the Guyana-Suriname petroleum system as shown on Slide 19.

As you know, this is the second of the two major Cretaceous basins that opened along the south Atlantic margin in the last three years or so. Here our 11,000 square kilometer acreage position in Suriname which is shown on the lower left image of the slide comprises two blocks which offer up to five 3D seismic defined independent play tests.

In aggregate, these are for a potential multibillion barrel potential. Two of the five play fairways will be tested in 2018. The first well will test the 700 million plus Anapai prospect in Block 45 as shown on the lower right schematic.

This involves Albian reservoirs charged from similar source rocks and trapped in an early Cretaceous combination structural-stratigraphic feature, the key risks that trap and charge migration. We plan to spud that well in early – second quarter 2018.

This will be followed by a well in Block 42 in the third quarter either on the late Cretaceous Aurora or Apetina trend. Both of these offer potential extension as Liza-type stratigraphic play as depicted on the upper right schematic.

Drilling is then expected to recommence in 2019 and beyond with follow-on exploration to test the other play fairways as well as in the event of success, early appraisal and delineation drilling of any discovery we might make this year.

Lastly, on Slide 20, we have two frontier basin exploration opportunities in the current portfolio, including Sao Tome and Cote D’Ivoire. As with Equatorial Guinea, they are based on our business theme of second cycle exploration and a reentry into the Gulf of Guinea in the Transform Margin of West Africa.

In Sao Tome where we are pursuing Cretaceous based on floor fan plays in the outboard Rio Muni basin, we had initially secured a large entry position of approximately 26,000 square kilometers in four blocks, including 5, 6, 11 and 12.

On the acquisition, processing and early interpretation of the large 3D seismic survey as well as an updated petroleum system analysis, we currently are in the process of expanding this footprint with BP, as the successful drill bit [indiscernible] for blocks 10 and 13. Initial exploration drilling in Sao Tome is scheduled for 2019.

Similarly, offshore Cote D’Ivoire in partnership with BP again, we successfully accessed five blocks at the end of last year including CI-526, 602, 603, 707, 708. These cover approximately 16,000 square kilometers as an aggregate. A 3D seismic survey is being planned for later this year. There’s hope that drilling will follow as early as 2020.

In the meantime, our new venture initiatives continue as we seek to take advantage of the current industry environment, leverage our technical leadership and strategic alliance with BP to preemptively secure large acreage positions and strategic petroleum systems and therefore enabling us to build in high grade our current portfolio, ensuring quality through choice and delivery of success.

So in summary, the disciplined execution of our strategy continues to deliver a balanced pipeline of high-quality exploration opportunities across proven, emerging and frontier basins enabling us to maintain a series of drilling catalysts continuing next quarter in Suriname and deliver exploration success.

At this time, I’ll turn the call over to Tom..

Thanks, Brian, and good morning and afternoon, everyone. As Andy began by saying and as our fourth quarter results demonstrate, 2017 was a strong year for Kosmos. In fact, it was one of our strongest driven by a full year production contribution from TEN which increased overall sales volumes to their highest level in our history.

This production level helped generate approximately 320 million of free cash flow exceeding our initial 250 million of guidance for 2017 prior to the Hess acquisition. A disciplined execution of the business plan kept costs and fourth quarter results broadly in line with guidance.

While commodity prices have recently improved, our commitment to full cycle returns, financial strength and robust liquidity remains steadfast as indicated on Slide 22.

We plan to continue living within our means using our strong free cash flow to execute our growth plan and combined with our rigorous capital allocation process this will continue to set Kosmos apart from other independent E&P operators. Our financial strength is both the result of our successful strategy execution and an enabler of it.

Through continuous and prudent balance sheet management we’ve been able to execute our growth strategy through the highest and lows of commodity price cycle. Our balance sheet strength is a true asset of Kosmos. We exited 2017 with low leverage and significant headroom on our debt covenants.

We expect this to remain the case as we execute our growth strategy going forward. We actively manage our debt maturities and have no debt coming due until 2021 when our high yield notes mature.

Recently, we refinanced our reserve base lending facility or RBL which resulted in the borrowing base increasing to 1.5 billion, up from approximately 1.3 billion as a result of incorporating our EG assets into the base.

At the same time, we included an accordion feature which allows the borrowing base to expand by up to $500 million at our choosing once the Tortue project has taken FID. In addition, the RBL maturity is extended to March 2025 and the amortization does not begin until March of 2022.

The new agreement requires only an annual borrowing base redetermination. Our $400 million revolving credit facility remains undrawn and we expect to refinance it later this year before it matures in November.

Our strategy is based upon a self-funded business model and the ability to self-fund with our dilution, particularly in a low oil price environment. It’s a testament to our disciplined capital allocation process and the ability to leverage partner funding.

In addition, the portfolio’s ability to generate consistent cash flow from our high-margin producing assets is in large part the result of an active consistent hedging program which underpins the cash flow from our key assets allowing us to fund our capital program and also generates significant value for the company since the oil price downturn.

At year-end plus recently executed hedges, we have had a total of 10.9 million barrels hedged at an average floor of $54.67 per barrel for 2018 and 9.5 million barrels hedged at an average floor of $52.63 in 2019. We expect that hedging will remain a key tool we use in our prudent balance sheet management.

Consequently, our free cash flow generation, robust liquidity has allowed us to leverage the low price environment to our advantage, enhancing our exploration portfolio with new opportunities and bolstering our production base through a significant acquisition of high-value producing assets at an attractive price.

This provides us with a balanced portfolio with growth from production, development and exploration assets. As oil prices improve, we remain committed to disciplined capital allocation and free cash flow generation.

Despite increased CapEx in 2018, the result of increased activity with growing operating cash flow and hedges in place, we still expect to be net cash flow positive in a $50 oil price environment.

Going forward, we now have a more balanced portfolio of production development and exploration opportunities and will continue our focus on the projects which generate the best return for our shareholders.

So in summary, with growing high margin production, free cash flow and a strong portfolio, Kosmos is poised to deliver continued growth and value for our shareholders. Now before I turn the call back over to Andy to summarize, I’d like to address our 2018 guidance which was included in our press release and in today’s presentation on Slide 23.

I will limit my comments primarily to our full year numbers, so please follow up with our IR staff if you have any questions. In Ghana, we expect the total of 11 liftings including four from TEN and seven from Jubilee. This forecast contemplates a four-week oil production shutdown in the first quarter which commenced in early February.

Ghana OpEx is expected to average between $14 and $17 per barrel in 2018 with quarterly fluctuations expected depending on the ratio of Jubilee to TEN liftings during the quarter, given the higher OpEx per unit at TEN which includes FPSO lease expense.

Higher OpEx in 2018 is the result of not having any LOPI insurance proceeds to cover the additional operating procedures currently in place. DD&A is expected to average between $24 and $26 per barrel and will also fluctuate quarterly depending on the number of liftings from each field.

We expect to incur approximately $100 million of G&A expense with 65% cash and 35% non-cash in 2018. The increase compared to 2017 reflects the significant credits received from the Jubilee operator during 2017 which reduced our G&A as well as the fact that we have turned over operatorship to BP in Mauritania and Senegal.

Bearing in mind the difficulties of providing guidance on taxes, at $60 per barrel Brent and excluding the impact of unrealized mark-to-mark hedging gains and losses, taxes are expected to average $3 to $4 per barrel with 100% being current.

Non-dry hole exploration expense related to seismic acquisition and G&G costs is expected to average around $30 million per quarter.

In terms of 2018 CapEx, we anticipate spending approximately 300 million consisting of approximately 110 million in Ghana which includes a provision for a second rig later this year, 180 million of exploration spending including $50 million for exploration drilling in Suriname, $80 million for seismic and processing across our portfolio to mature drilling opportunities for 2019 and beyond and $50 million for new venture activity.

And finally, we have approximately $10 million of corporate and other CapEx. Lastly, I’ll provide guidance for our Equatorial Guinea assets which because of the ownership structure are being accounted for using the equity method of accounting.

From a practical standpoint, this means that the net income from these assets appears in the equity method investment line of our consolidated income statement while the actual cash impact flows through a line under the cash flow from an investing portion of our consolidated cash flow statement as a dividend.

We hold our share of Ceiba/Okume via our 50% interest in Kosmos Trident International Petroleum Inc. or KTIPI with the exception of the gross production guidance of 43,000 barrels of oil per day for 2018, all guidance given in the table represents 100% of the share held 50-50 by Kosmos and Trident.

The 10 cargo guidance, 5 net to Kosmos is based on net entitlement volumes from cost oil and profit oil under the terms of the production sharing contract, assuming a Brent oil price of $60 per barrel. OpEx per barrel is expected to range between $13 and $15 per barrel, DD&A at $24 to $26 per barrel including bases amortization.

And taxes are expected to range between $11 and $13 per barrel or 60% cash. That concludes the guidance. And with that, I’ll now turn the call over to Andy for his closing remarks..

Thanks, Tom. So to summarize. Kosmos has a balanced portfolio of production, development and exploration with multiple sources of growth in all three of these areas. Our high-margin production assets in Ghana and EG continue to deliver growth. Our 2P reserves from Jubilee, TEN and EG underpin our current share price.

Our big fields continue to get bigger, so our 3P resource offers significant additional upside. The Tortue gas project provides the next phase of growth for Kosmos.

Following the recent ICA approval announcement and guidance by BP, we expect the project to take FID with initial phase around the end of 2018 with full field development providing further upside.

With the work we’ve been doing through the downturn acquiring new blocks in attractive geographies, Kosmos has a sustainable exploration program with the balance of proven, emerging and frontier opportunity which offer multiple catalysts in 2018, 2019 and beyond.

And finally, we can execute this activity set cash flow positive at $50 per barrel Brent in 2018 and we have the balance sheet strength and liquidity going forward. Now, operator, we’d like to open the call for questions..

Thank you. At this time, we’ll be conducting a question-and-answer session. [Operator Instructions]. Our first question is from Ryan Todd with Deutsche Bank. Please proceed..

Thanks. I appreciate all of the incremental detail on the presentation. Maybe first up one on Tortue.

What do you need to see, what does the timeline look like over the course of 2018? What are the steps that you need to achieve to reach FID later this year?.

Thanks, Ryan. I’ll pick that up. With the ICA approved, we’re now in a position to move forward with FID. That obviously involves letting the key subcontracts for the phases of the project which involves the subsea, the FPSO knocking out the liquids, the breakwater near shore and then the gas processing solution for the LNG.

And as I said in my remarks, you can anticipate seeing those contracts being let over the coming weeks. From an engineering perspective, that gets us to FID around the end of the year. And then in parallel with that, we’re working the gas sales.

We’ll shortly be putting out a request for proposals for the gas sales and anticipate again that we’ll have that work complete ahead of FID. I think the big thing about Tortue just to remind you is we got a very simple partnership. It’s BP, it’s Kosmos, national oil companies.

And therefore what typically is a problem for getting a LNG project through to FID is the complexity of the project, the complexity of the partnership and the competing interest. We have none of that here. So ultimately it’s about a very clear scheme which we’ve chosen.

It’s about a cost competitive project which works against the lowest cost gas today from North America and a world-class operator in BP that has the wherewithal now to complete that FID work in a timely fashion..

Thanks. On the gas sales, the market seems to be improving in terms of finding buyers for gas sales across the global LNG market, particularly if you look into the early time period there. Any thoughts on how you would characterize the market? I know BP can take volumes as part of the portfolio.

To FID the project, how much – is there a threshold that you would look at in terms of gas sold under contract or would you be willing to FID the project with BP’s portfolio as more of a destination?.

Yes, I think there’s a couple of follow-up comments, Ryan. I think you’re right. I think we’ve always held the view that the market was going to open up in the earlier part of the next decade rather than the middle and I think we’ve been correct on that. I think the second comment would be about the initial phase is 2.5 million tons per annum.

It’s a relatively modest amount of gas to put into the market. Therefore, it’s easily absorbed. And I think that’s an important factor.

And I think the third point is just to remind you that whilst BP are in the project and they’re a natural buyer of the gas, we are going out to compete for proposals from other trading houses, actually other IOCs, so it will be a very competitive process. But I think your overall tone is correct.

I think I felt the gas market is going to be undersupplied in the early part of the next decade.

That is the case I believe today and therefore the ability to move forward with the project that people have confidence in now because of the simplicity of the partnership, a quality operator that can execute and a low cost of gas will enable this to move forward..

Great. Thanks..

Perhaps you’ll overstay your welcome [ph]..

Maybe a quick one on Jubilee and TEN. So you’re drilling four wells I think between the two assets this year.

Can you talk about maybe the trajectory of the production of both those fields not just over the course of 2018 but I guess maybe as we look into 2019 as well? What does the timeline look like on a production ramp and as you look at full field development across both of those, I guess how should we expect that to proceed over the next couple of years? And I’ll leave it there..

Okay, great, Ryan. So what are we doing? We’re actually back to drilling. This is great news. The objective in Jubilee is actually to fill the facility. And so we’re talking about a facility we know that can run around 120,000 barrels of oil per day. And with the drilling resuming full field, that would be the objective.

And that ramp up is going to occur through '18 into '19. Same story really on TEN. We were clearly – for a couple of years we couldn’t drill because [indiscernible] back to drilling, ramp up through '18 into '19.

The only thing that I’d add on TEN is I think there is the ability to actually take the production level beyond the facility limit which is 80,000 barrels a day. How much we’ve tested at the short period of time above 80, but I think there is a potential to add well capacity that we’d ultimately do there.

So actually that’s the trajectory that you’re going to see through '18 into '19..

Thank you..

All right, thanks, Ryan..

Our next question is from Charles Meade with Johnson Rice. Please proceed..

Good morning Andy to you and the team there or maybe good afternoon as appropriate. I wanted to ask first a question about the EG assets.

I think you touched on this just briefly in your prepared remarks, but can you talk a little more about what the source or what the drivers of that uplift between the acquisition case and what you’re looking at now, I think there was 37,000 to 43,000 barrels a day.

Does that reflect just the performance of the assets and the facilities before you got your hands on them, or perhaps does that instead reflect the ESP plans that you spoke about?.

No, Charles. It’s pretty simple and I think it’s about time and attention actually. I think that one of the things we believe in strongly at Kosmos is sort of creating the right partnerships and we were clear with these assets that we needed to partner with someone who had that detailed attention in terms of running the assets on a day-to-day basis.

Trident or the ex-Perenco team, they bring that expertise. And it’s pretty simple actually. The first phase was really going into every single well looking at the distribution of gas lifts and actually optimizing it. And I think it was just a new set of eyes coming to the field with probably a slightly different mindset that created that uplift.

The second phase will be the installation of the ESPs. We haven’t started that yet. Would anticipate a program of about six ESPs in the first phase, around three this year in 2018 and three in 2019 and that will sort of sustain and offer the potential to continue to grow the production level into 2019.

And then we’re shooting the seismic over the hole of the Ceiba/Okume field which is sort of Block G plus the peripheral blocks W, S and 21 in '18, processing it back half of '18, beginning of '19 and that will allow us to start a program of drilling where we’ll be targeting first the short cycle opportunities whether they are infill wells or whether they’re wells which are separate prospects that can be tied back in a short period of time.

So as I said in the remarks, we’re really pleased with what we’re seeing today. We’ve obviously had the opportunity to drive production up higher than we thought. It’s great to have delivered that and it’s real. It’s occurred in the first two months.

We’ve got clear plans to sustain that in existing reserves base and we believe there’s significant opportunity to add value from the infill and the tie-back opportunity. Literally there was sort of no real exploration done for around 15 years. So Brian and the team are anxious to get their arms around it..

I’m sure they are. Thank you for that detail. And then the second question, I think this is for Brian. Brian, I recognize that the need to be circumspect when you consider the composition offshore, Mauritania and Senegal and also that Kosmos has data that no one else has.

But I’m wondering if there’s anything you would care to add about how your last three wells maybe have cast your earlier discoveries in a different light? And if this has changed your kind of philosophical outlook for what you’re going to do going forward versus what you’ve done to-date?.

Thanks, Charles. Listen, I think you have to stand back a moment and just maintain perspective on this basin. We’ve got nine wells, nine holes in this 50,000 square kilometer position also and we’ve just spent two exploration phases, one which was completely successful and one which was less so.

But those are just two fairways with the key prospects on those two fairways that we’ve drilled. And one shouldn’t lose sight of the opportunity set that’s in front of us now in terms of unlocking this basin which still remains very significant. Yes, we’ve drilled down some big prospects.

But interestingly and as often happen in these cases, as you learn and understand matters below the ground and you appreciate why certain things don’t work, that opens up – the reasons for those not working opens up the case for why other things that you may previously have not prioritized actually will work. And so as part of that we are rebuilding.

We’ve taken the noise that we’ve got and we’re rebuilding the lead prospect inventory as I mentioned in the script and are looking to essentially enter a third exploration appraisal phase next year.

So again, were we disappointed? We didn’t have a better than one in four success rate last year which is in of itself of course in these kind of basins is still pretty good and top quartile, but we set ourselves extremely high standards and expectations here. And it would have been nice that’s been higher, but it isn’t.

But one should not think for a moment that this basin is anywhere written off. There is still a significant amount to play for both in the gas fairways to the south in southern Mauritania and indeed in what we believe is a working oil petroleum system to the north in northern Mauritania. So that’s what we will now focus on..

Thank you, Brian, for those comments..

All right. Thanks, Charles..

Our next question is from Rafal Gutaj with Bank of America Merrill Lynch. Please proceed..

Good morning. Thank you. So on Slide 22 where you outline your leverage headroom and the slide suggest that you’ve got decent headroom there.

Could you give us a sense of how likely you are to use that to grow inorganically and would you be expanding on your core asset position if you were to use it, or whether a new country entry possibly be on the cards? And then part b of that is, if organic growth is not on the table and you’ve set yourself kind of a soft cap on exploration of two to three wells per year.

What kind of shape would your balance sheet need to be before you consider shareholder returns be it kind of regular or one-off, and is that something that would require to be online first? Thank you..

Hi. Thanks, Rafal. A lot of questions within questions there.

Look, if I just sort of stand back, what I would say first and foremost I think is I hope today we’ve demonstrated that Kosmos has multiple sources of growth and its production assets which remain strong and there’s opportunity to invest at very high margin barrels, in a development project in Tortue which is world class and can be super scale at 10 million tons per annum and then finally the exploration programs.

So we have a very strong set of assets today in which to invest. We have demonstrated our ability to do good acquisitions and EG is an example of that. We’re being very selective as we look at those opportunities. They have to be ones where we can truly add value through the right partnerships and our core expertise. We will continue to look at those.

And I think there are opportunities available but we’ll be very selective. And I think we’ve set the bar very high for you actually in terms of the quality of the EG deal. So we’re saying we have to match something which is of a similar quality that is accretive and actually has the growth prospects that EG has.

So I think my first point is really around the strength of the portfolio and our ability to invest.

And I think as you start then to look at distributions going forward, what I would say is that ultimately today we see the ability to invest at a high quality in Kosmos and those plans are clear and I think the strategy is being well laid out for you today and that will be our first call on capital.

Going forward, if you have Tortue on stream and you’re generating significant cash flow and we haven’t delivered the success we anticipate from exploration then potentially, but I think today it’s really about having a balance sheet that can ensure that the strategy of growth that we’ve laid out can be delivered.

And I think through the cycle we’ve demonstrated our prudence in managing the balance sheet and the ability for it to create opportunity for us when some of our competitors are focused entirely on repairing their balance sheet. We’re not.

We’re actually out there I believe today creating high quality opportunities that will support the growth of the company for the long term..

Great. That’s clear. Thanks, Andy..

Great. Thanks, Rafal..

Our next question is from Richard Tullis with Capital One Securities. Please proceed..

Thanks. Good morning, everyone. Andy, nice summary in the earlier remarks highlighting the attractive deepwater cost structure.

What conditions and/or commodity price do you think begins to possibly drive drilling and development costs higher in the deepwater regime?.

Yes, look, I don’t think we’re there today is what I’d say. So if you look at today’s oil price, I think you’ve got a sort of slow recovery in the activity set. I think you’re hearing that in the background commentary from the majors. And so I think you’re still in a world of relative oversupply today whether it is drilling, whether it be construction.

And I think it will take a while to work through. So we see sort of modest inflation going forward rather than a kick up. And I think to be honest the oil price isn’t really the driver today. To my mind it’s actually about the opportunity set and the people have quality things to invest in.

And I think that’s really where I think as you look at Kosmos as a pure deepwater company, it’s slightly different because we believed in the sector through the downturn, we’ve built the portfolio through the downturn and are continuing to do that and continue to have that opportunity set.

So I believe we know as we’re demonstrating, we can work in a $50 to $60 world and be very efficient in that world and I think the prospects as it were going forward in that environment are good.

So the thing that I would actually look at is rather than the inflationary pressures, it’s going to be the opportunity set who really has the quality today to be able to deliver.

And I think in a sense, the mid cap stepping back from the deepwater is a blessing for us because we have the ability now I think to be more competitive and I think we’re moving faster than some of those super majors today and ensuring that our portfolio is strong for the long term..

Thank you, Andy. And just one more. In EG, only spending minimal CapEx this year, less than 10 million. What level of yearly spending could you require to get gross production closer to that 50,000 barrel a day level that’s depicted in the slides? I guess that’s like 2019, 2020, 2021 timeframe.

What sort of spending level could get you to that level?.

We don’t often give any guidance for 2019, Richard. What I would say is the step up in capital to sort of get to that level really through the ESP program I spoke about for the six ESP conversions is relatively modest.

I think the area where you’ll see a kick up in the capital will be the back end of '19 into 2020 when we start the infill program, drilling program. So I think you can sort of – I would say we can reach that sort of 50,000 barrel a day level with a relatively modest level of capital, sort of well-worked capital.

I think in a very small font on that graph, we talk about the rates of return from that program which are very high. So I think that’s a way you should model it is a small rise but relatively modest. And then in 2019 you would see – back end of 2019 and 2020 you’d see an uptick from the infill program..

All right. Thank you, Andy. That’s helpful. I appreciate it..

Our next question is from Alwyn Thomas with Exane BNP Paribas. Please proceed..

Good morning, guys. My first question just to clarify on the free cash flow, Tom, if you could just help us out here. I think based on the 2018 guidance that you’re giving, if I give some very broad estimates, I get to about 350 free cash flow on $60 a barrel.

I’m wondering if you could just maybe clarify if there are any other moving parts in that that I might be missing. And my second question is really around Suriname. Perhaps based a little bit on sort of rebasing expectations after the Mauritania/Senegal campaign.

Looking into Suriname, Brian, could you possibly just re-clarify what you see as the key risks are and perhaps what chance of success you think we should apply to these at this stage, that would be very helpful? Thank you..

All right. I’ll let Tom do the free cash flow question first and then Brian will pick up Suriname..

So I think at $60 free cash flow, the biggest things that you want to just pay attention to are the hedges because they impact the $60 case.

But that being said, we don’t give real guidance on our cash flow targets outside to say that we are free cash flowing at $50, $55 and $60, so you can kind of assume from there we’re pretty robust from a cash flow generation perspective..

Okay. Brian, on Suriname..

Yes. Thanks, Alwyn. The way you think about our position is Suriname is as we kind of outlined in the script really is two separate bocks, two separate plays. The first one we’re going to get to is Anapai which is an early Cretaceous play. So this is essentially a non-proven play in what we believe is a proven or what we know is a proven basin.

It’s a deeper set of reservoirs charged from either the proven source rocks further north and beyond or from deeper source rocks. So charged to some extent is a risk particularly around migration. It sits on the banks of the basin. And I would say that is the key risk trap – trap is always a risk but the key play risk will be charge and migration.

In Block 42 that’s very much extensions of existing and proven plays in Guyana as the image on the slide tries to portray. And so the life of the Apetina trend, the Aurora trend are a long trend in adjacent channels to Payara and Liza and Turbot, et cetera.

And so we are pursuing very similar type of dominantly stratigraphic features which are geophysically supported.

And of course you may recall a couple of years ago, Hess joined us in Block 42 and they are bringing all of their knowledge and calibration from the Guyana area and bringing that learning to bear on our analysis of Block 42 where we have multiple prospects and the reason we haven’t got a specific one identified thus far is that we are blessed with a myriad of opportunities and we’re working through them to figure out what the right exploration strategy is and what the right well to drill first is.

But there again trap is almost certainly going to be the key. Trap and migration is going to be the key risk on any one of those prospects that is drilled..

It sounds like they’re pretty high risk wells then, so do you think 1 in 10 chance of success is appropriate?.

No, we don’t drill 1 in 10 prospects..

Okay..

The way to step back from it is to say that we’re building a sustainable program of quality exploration targets multiyear and we’re typically drilling out 1 in 4, 1 in 5 and over a course of years therefore we’re going to deliver success. And I think it’s important to look at it as a program.

And in Suriname the program will test four or five independent prospects over several years. And that’s the quality cutoff that we would apply. We don’t drill 1 in 10. We’re drilling 1 in 4s and 1 in 5s and we take the time to make sure that we mature the prospects to the quality that delivers that outcome..

Okay. Thank you, guys. I just have one very quick follow up.

At Equatorial Guinea, since you took over, have you upgraded the reserves at all from when you bought it given this sort of production profile you’re seeing obviously the immediate uplift that you’re getting?.

Yes, I think it’s a timing issue there. Obviously we believe we literally – I think we closed it on the 30th of November, so we have the prior operator’s input. We’ve obviously gone through our year-end reserve process but it hasn’t really had the benefit clearly of the production uplift we’re seeing over the last two months.

So the answer is sort of early days on that..

Okay, no problem. Thank you..

Great. Thanks. .

Our next question is from Pavel Molchanov from Raymond James. Please proceed..

Thanks for taking the question, guys.

You provided some interesting disclosure on the prospects in Suriname and I’m curious having watched what’s been going on across the board or – and obviously Liza and the other discoveries in Guyana, to what extent should we look at those past discoveries as really templates for what you guys will be doing later this year?.

All right, thanks, Pavel. Again, I’ll pass it over to Brian. We sort of talked in the last question about the nature of the tests in Suriname, but we can give a little bit more color..

Yes. Pavel, the great thing about the two blocks is that as you know in all of our projects we look for play diversity. And we mentioned in the script that we got four or five play fairways in this block that we want to explore before we can say that we fully tested it.

And in that regard and probably Anapai given its position and given its geological objective is the most distant from what has been found to-date. That said, it’s got great merits in terms of the nature of the play and the support in the prospect for potential hydrocarbons.

The Block 42 is in the same upper Cretaceous basin as the existing discoveries in Guyana which are in – all of which expect Turbot really are in one main channel system. And so we are exploring adjacent channel systems depending on the same play types, the same play elements of trap, reservoir and charge just in a separate fairway.

And so obviously the dependency between those prospects and the Liza-type features is great when it is in Anapai. And so in some respects I think some of our partners view those prospects as lower risk than for example the big prospect in Block 45.

But the good news is we’ve got play diversity in what is a working oil basin and so we got multiple shots on goal to open up our part of this basin. Of course, they’re of significant scale and you should recall in Block 45 we have 50% with Chevron in the Anapai prospect, so high-worth equity and we’ve got a third in Block 42.

So if these work, they’re going to be very material to Kosmos..

And one more following up on kind of the comparison between the two countries. Earlier this year we saw the fiscal terms on Liza contract coming out from the government and obviously it’s early days to talk about fiscal terms in Suriname.

But if you can give any compare and contrast to what you saw from the Liza contract to give a sense of what Suriname might look like?.

Yes, Pavel, what I’d say is they’re not quite as good in Suriname as Guyana but they’re very competitive in our portfolio when compared to Mauritania or Senegal, et cetera. So one of the things we’re very clear on in our world is that it has to work in a breakeven price of 30 to 50 and therefore be competitive.

We don’t enter countries unless that’s the case. Suriname is absolutely in that place and not quite as good as Liza but very competitive..

Okay, helpful. Appreciate it..

All right. Thanks, Pavel.

Operator, any more questions?.

Yes. We have one last question from Niki Kouzmanov with Jefferies. Please proceed..

Hi. Good morning and good afternoon, gentlemen. Just very quickly on Tortue, I was just wondering the 2.5 million tons per annum, does that include any domestic sales [indiscernible] international energy sales? And then Andy you mentioned that the 533 million carry from BP like you’re substantially funded.

Does that mean that you’re fully funded with gas? It seems that you’re fully funded with gas and if you’re not, what are your plans to fund the increment project financing or own balance sheet full year refinancing? Thank you..

You broke up slightly on the first question, Niki, but I think it was basically saying is it fundamentally about LNG sales? And the answer is yes, 2.5 million at LNG sales.

I think ultimately there will be some domestic gas, but it’s a small proportion given the gas-generating capacity into power in both countries is just a relatively small number of the overall throughput of the scheme. Important for the country but not actually impactful to the economics of the project.

Second question on the carry, clearly we’re at a point now where we’re going through fees, we’re getting all of the final cost estimates in. It’s a very competitive market at the moment and it’s hard to predict exactly where the number is going to come out. But I think the 533 is still our view that we’re substantially funded to first gas.

And if whatever is left, we would do from our own balance sheet. So it doesn’t need project financing which is a critical part of the project in a sense BP can pay their way, we can pay our way.

Clearly we have to work with the NOCs to get them on board, but fundamentally you have the financial capacity within the partnership to move this forward which is one of the distinctive attributes of this project..

Thank you..

Okay, great. Thanks, Niki..

[Operator Instructions]. Since there are no further questions at this time, I would like to turn the floor back over to Jamie Buckland for closing comments..

Thanks, operator. We appreciate all of you joining us on the call today and your interest in Kosmos. If you have any further questions, please don’t hesitate to contact us. Thank you very much..

Ladies and gentlemen, this concludes today’s conference. You may disconnect your lines at this time and thank you for your participation..