Tuesday, 17 November 2015

100% success rate continues offshore Mauritania/Senegal

by Elaine Reynolds

Kosmos Energy's play extending gas discovery well Marsouin-1 continues the 100% success rate seen offshore Mauritania and Senegal in the last year. Kosmos' success follows on from its Tortue gas discovery earlier this year, while Cairn Energy had back to back oil discoveries to the south in Senegal towards the end of 2014. Now both companies are undertaking full appraisal and exploration programmes that will see activity continuing in the region into 2017.Together these two programmes offer the potential of up to twelve exploration and appraisal catalysts over the next eighteen months, a rare occurrence in the current low oil price environment.
Marsouin -1 and Tortue-1 locations and Petroleum System map
Marsouin-1 has de-risked a potential resource base of 5TCF in the Marsouin Anticline. Drilling will now return to the  Ahmeyim anticline to the south containing the Tortue-1 discovery well where three appraisal wells (Guembuel-1, Ahmeyim-2 and Teranga-1) will be drilled into mid 2016 to prove up potential resources of c15TCF. Beyond this however, Kosmos will focus on targeting oil prone fairways to the north and south of Ahmeyim and Marsouin. From Q3 2016, the company is planning two exploration wells in Southern Senegal and one in Northern Mauritania with the intention of adding follow-on wells to the programme and which would see drilling continuing here to the end of 2017.
Cairn/FAR well locations

Meanwhile, this month, Cairn and partner FAR Energy spudded the first well in a minimum three well exploration and appraisal programme to further evaluate the 330mmbbl SNE-1 discovery in Senegal. SNE-2 is located 3km to the north of SNE-1, and will target the centre of the field in order to encounter  maximum hydrocarbon density. Drilling and coring is expected to take around six weeks with a further four weeks for testing. SNE-3 will then test the southern extent of the field with a similar programme of data gathering, followed by BEL-1, which will test the northern extension together with an added exploration target of 157mmbbls recoverable resources sitting above SNE. The programme has been designed to establish the continuity and connectivity of the reservoir and to demonstrate productivity as these will be key to the future commerciality of the project.






Thursday, 29 October 2015

Falklands exploration: Humpback results finally in

by Elaine Reynolds

The long anticipated results from Humpback, the only well to be drilled in the South Falkland Basin in the current Falklands drilling campaign, have been disappointing, with the well encountering non-commercial quantities of oil and gas.
 
 South Falkland Basin acreage map
Falkland Oil and Gas (FOGL), together with operator Noble Energy was targeting oil in the Diomedea fan complex in the Fitzroy sub-basin to the south and east of the Falkland Islands. Humpback was assessed pre-drill to be sitting in the likely oil window in the basin based on geothermal modelling. In addition it was hoped that good quality Cretaceous sands similar to those found in the 2010 FOGL well Toroa on the edge of the basin would be present in Humpback, as it was believed that these Toroa sands had been eroded and redeposited in Diomedea. The presence of oil and gas gives credence to the geothermal modelling approach, however the sand quality was poorer than expected, with moderate porosities being reported.The oil and gas shows were found in 40m of net sand across in a number of sandstones, including the main target ,the Lower Cretaceous APX-200, with a further 25m of sandstone below.

Drilling of the well has proven to be complex and difficult, such that the well had to be sidetracked, and it proved impossible to retrieve fluid samples from any of the hydrocarbon bearing intervals. As a result, the well will have incurred significant cost overruns. Humpback was originally scheduled to take 65 days to drill at a cost of $110m. The well has now taken over 130 days, so we expect that gross well cost could be in the region of $200m. Although an element of this should be recovered based on the unforeseen equipment failures that contributed to the long drill time, we expect that FOGL will exit this well with very little cash. The company held a 52.5% WI in the well, but was only paying 27.5% of the costs as a result of an exploration carry paid by Noble under the terms of its farm-in. In addition, FOGL farmed down 32.5% of the deeper targets only to Noble to fund the drilling of the deeper section of the well.

The rig will next move to the North Falkland Basin, where it will drill the Elaine/Isobel appraisal well.  FOGL is fully carried for its share of Elaine /Isobel (including recovering $10m from its partners as compensation for switching this well from Jayne East). However, the company will still need further funding to carry out additional activity in either basin.

FOGL and Noble will now integrate the Humpback well findings into the geological model to provide an updated view of the exploration potential of both the Diomedea area and the overall oil and gas potential of their Southern Area licences. The licences also include the Hersilia  Fan Complex to the north of Diomedea and the Cretaceous Fault Blocks adjacent to Borders & Southern's (B & S) gas condensate discovery, Darwin. Inevitably, B & S will be impacted by this result being Southern Basin focused; however the merits of the Darwin potential development itself probably remain unchanged.














Wednesday, 28 October 2015

Is the Serica deal a sign of improved North Sea co-operation?

by Elaine Reynolds

A recent transfer of equity in a Central North Sea block may herald the beginnings of a new period of cooperation in the UK North Sea that would encourage undeveloped assets to be brought onstream. Serica Energy (WI 50%), together with partners Endeavour (25%) and EOG (25%), looks set to pick up 100% of the Columbus field, mainly located in Block 23/16f. Columbus extends to the south into the 23/21a block, where partners BG and SSE have agreed to transfer their equity in the part of the block covering Columbus for a nominal sum. 



Columbus field location map

Columbus was discovered in 2006 and fully appraised by 2008, but Serica has to date been unable to finalise plans to develop the field via the BG operated Lomond platform, located 8km from Columbus. The 15.5mmboe field is a typical example of the kind of stranded asset that has struggled to be developed in the North Sea; a small accumulation operated by an independent, close to ageing infrastructure operated by a major, and with each holding separate commercial concerns.

However, the Wood Report, published in 2014 and charged with identifying ways to maximise recovery from the UKCS, has highlighted the need for a fundamental shift in commercial behaviours between operators in order to benefit UK plc. Serica could be one of the early beneficiaries of this change in approach.

Serica's deal should help to push the development of Columbus forward as it removes the need for unitisation discussions; however infrastructure access still needs to be agreed. Lomond provides production facilities for the Erskine field in which Serica has held an 18% stake since 2014, strengthening its position in negotiations with BG.  Although the platform is ageing, a recent shutdown for major infrastructure improvements appears to have significantly improved performance since Erskine production restarted at the end of May this year. If sustainable, this would provide confidence that  the platform life can be extended. 

The equity transfer points to a more pragmatic and constructive approach to commercial deals in the region. The Wood Report, together with the prevailing low oil price, appears to be concentrating minds to focus on inefficiencies and applying pressure to perform. In addition, the regulatory body set up this year to implement the Wood Report's recommendations, the Oil and Gas Authority (OGA), is now expected to be involved in facilitating a commercial agreement for Columbus, along similar lines to that already employed by NPD in tariff negotiations in Norway. If successful, this could point the way for others to progress the development of further stranded assets on the UKCS. 

Tuesday, 20 October 2015

Genel trading statement

by Will Forbes

The headline from Genel’s trading statement this morning is perhaps the downward revision of the 2015 production guidance from 90-100mbopd to 85-90mbopd and revenue guidance narrowing at the bottom of the range (was $350-400m, now $350-375m) assuming $50/bbl crude.

Following GKP’s recent receipt of payments for production, Genel expect $24.5m in the short term, which we hope will be a further step towards reliable payments from the KRG for production. As with all KRG-focussed producers, Genel is restricting its investment until it sees returns from existing production, and the sooner that payments (and back payments) for production are received the more quickly Kurdistan will see further increases in capacity.

Importantly, the export volumes from Kurdistan continue to increase, with news yesterday (Bloomberg) that exports could be running at 656mbopd (from 564mbopd in September). Even with oil prices where they are, these kind of volumes give us hope that the KRG can afford to pay its contractors.


Elsewhere, the gas project is continuing with ING appointed as mid-stream debt adviser, Genel will be participating in the Aigle well (Cote D’Ivoire), and the completion of Taq Taq’s second central processing facility (90bopd) is on track for end-2015.

Friday, 16 October 2015

Is there a link between the oil prices and deals?

by Avanish Katkoria


Analysis indicates that there is a linkage between the prevailing oil price and industry deals, but this is unsurprisingly not linear and differs between types of deals. 

Deal number correlates well
The oil price saw a steady increase from approx $55/barrel up until its peak during the years 2011 – 2013 where it stayed approximately at the $110/barrel mark.  In this time the number of deals completed has somewhat kept up with the pattern of the oil price, as 1118 deals occurred in 2011 and 1041 in 2012, which were the most in a single year since 2005. 

However, since then oil has seen a massive decline in price, with the current price being $50/barrel. As expected, during this period, the number of deals gradually dropped from the heights of 2011 in line with the oil price.
Deal value not as well correlated
Total deal value does not follow quite the same trend as the number of deals, with the values of the deals significantly less in 2011 and 2013 suggesting that even though more deals took place in those years, many of the deals would have had lower values. 

The peak in total deal value was in 2012 at approximately $300bn, a contributing reason for this could be because the deals in 2012 involved much higher proved reserves than any of the other years hence the average value of the deals were higher.
Larger deals not affected
However, with further analysis, it becomes transparent that the oil price does not affect the bigger players in the market, for example deals with values above $10bn are not too affected by the oil price as there has not been a large change over the years in these types of deals. In fact the largest deal from the last five years has come in 2015, the year where the oil prices have been the lowest; this was the deal where Shell acquired BG for $81.9bn.

Corporate M&As buck the trend
When the deals were broken down into type of fields, a similar trend seemed to have continued on the whole amongst all the types. However, the proportion of Corporate M&As decreased from 26% of all deals in 2006 to 11% in 2013, but more recently they are increasing again with the figure at 18% in 2015 up until now.

In conclusion, we can see while there may be a trend between the oil price and number of deals occurring over time, there are many other factors to be taken into consideration and with more in-depth analysis the trend starts to fade.



Thursday, 15 October 2015

Kurdistan payments ~ two payments in two months

by Will Forbes

Today’s announcement that Gulf Keystone has been paid for the second month running is good news for all concerned. Gulf Keystone gets much needed revenues, and a second payment starts to give Kurdistan companies (and investors) a taste that these payments could be the start of regular, reliable cashflows. We note Genel and DNO have yet to announce payments themselves, though we would be surprised to not see these in the near future.

Two swallows do not make a summer, but once confidence in the payments (for current and historic production) is high, the companies will be able to fund further development in their assets, whether that is offsetting potential declines (Taq Taq/Tawke) or increasing production (Shaikan) or investing in new capacity (Sheikh Adi, Ber Bahr, Peskabir, Chia Surkh).

We note Gulf Keystone’s cash balance is now $76.2m, enough to cover the upcoming bond repayments of $26.4m. This will take the cash balance below the $50m level, which under the terms of the bonds will trigger the need for GKP to talk with bondholders. We note that cash dipping below the $50m level does not trigger anything other than a need to talk to bondholders (there are no penalties), and we would expect the company to have been actively engaging with bondholders throughout this period.

Tuesday, 15 September 2015

Plexus Holdings taps subsea market

by Elaine Reynolds

The launch of Plexus Holdings' Python Subsea Wellhead at Offshore Europe 2015 is a major step for the company, allowing it to access a previously untapped market with its innovative POS-GRIP technology. 

POS-GRIP was invented and developed by Plexus founder-CEO Ben van Bilderbeek and is a patented method of friction grip engineering which the company has used to redesign wellhead systems.

The wellhead market has been dominated by large US companies such as Cameron (currently expected to be acquired by Schlumberger for around $14.8bn) and FMC Technologies. Yet Plexus currently has almost 100% of the UKCS exploration jack-up drilling wellhead market, and has also been particularly successful in HP/HT exploration applications where technical demands are greater. Until the introduction of Python however, the company did not provide a subsea system, so this should allow the company access to a much larger market. Interest in the system can be seen in the calibre of companies that have supported the joint industry project to develop Python, including BG, Shell, Wintershall, Maersk, TOTAL, Tullow Oil, ENI, Senergy and Oil State Industries. The Python Subsea Wellhead is planned to be run in a trial well during 2016.



POS-GRIP system

POS-GRIP open                                                                                         POS-GRIP closed

The system uses hydraulic devices fitted to the outside of the wellhead which, when energised, deflects the outer wellhead body onto the inner casing hanger or tubing hanger, locking them in place. POS-GRIP is a significantly more streamlined design than seen in traditional wellhead technology and offers improvements in reliability, safety and cost.  In particular:

  • The system virtually eliminates the movement between sealing parts that causes seal deterioration and failure. 
  • All well operations can be carried out through the Blowout preventor (BOP). This saves a significant amount of rig time and improves safety as the BOP is in place at all times.
  • Hangers are sealed and locked as soon as cementing is completed, preventing hanger movement under pressure (as occurred during the Deepwater Horizon incident).



Thursday, 27 August 2015

Gulf of Mexico - stepping up to the challenges

by Elaine Reynolds

The full note is available here



The Gulf of Mexico benefits from a unique combination of factors that make it a particularly attractive region for major operators, with Shell, BP and Chevron holding substantial acreage. Companies operating in the area have access to potentially large resources together with the ability to hold large positions that gives them running room to grow, while the concentration of companies with interests in the region allows flexibility to farm in and out as necessary. The Gulf is close to a centre of excellence in a range of oilfield applications from seismic to drilling technologies, and also benefits from a well developed infrastructure. Together with the predictable fiscal regime and low tax rate of the US, this makes it a good place to replace reserves and grow production. The region is technically demanding which plays to the majors’ strengths, however US independents are also active in the region, with Cobalt and Anadarko holding key positions in the inboard Lower Tertiary.

Production from the Gulf of Mexico is set to reach a new peak of 1.9mboe/d in 2016.  Activity has returned to the region following the post 2010 Macondo slowdown, and will result in an expected 18% production increase between 2014-2016 as new developments come online. Since late 2014 the Jack/St Malo, Tubular Bells, Lucius and Hadrian South developments have all commenced production, while Lower Tertiary exploration continues to throw up new discoveries, most recently in Chevron’s  Anchor discovery announced in January 2015.


Beyond 2016 however, production is currently expected to remain relatively flat as existing fields decline and the rate of start-ups falls from 15 in 2014-2016 to 8 between 2017 and 2020. Although the overall rig count in the Gulf of Mexico has dropped in the wake of lower oil prices, the deep water rig count has remained resilient, with jack up rigs bearing the brunt of the cuts. Activity does however seem to be prioritising appraisal and development, with only five rigs drilling exploration wells compared to fourteen a year ago.

Given the long lead times required to progress a project from prospect to development in the region, together with long production profiles, we expect activity to continue in the near term as operators focus on maintaining their long term outlook while looking to reduce costs. For example, Shell’s 175,000 boepd Appomatax development was given the go ahead in June 2015 having achieved cost reductions of 20%, and is expected onstream in 2020. BP is aiming for a final investment decision on its Mad Dog 2 project by end 2015/early 2016, and is now working with a reworked project cost of $10bn, significantly lower than its 2011 estimate of $22bn. And it isn’t only the majors that are continuing to invest in the region. US Independent Cobalt recently increased its stake in the Goodfellow prospect from 29.2% to 47% where it is now the operator. The company believes that costs will come down in alignment with the price environment, maintaining the attractiveness of its discoveries in the inboard Lower Tertiary.


Beyond cutting costs, companies will also need to keep innovating if they are to grow production into the next decade.  To achieve this, we see a continuing focus on developing new technologies to improve the recovery factor in the Lower Tertiary and in extending the HP/HT operating limits beyond the 15,000psi and 2500F that is currently feasible. Initiatives to tackle these issues include BP’s Project 20K and Statoil’s ‘Unlocking the Paleogene’, while new ownership structures such as the 2015 alliance between BP, Chevron and ConocoPhillips to develop the Gila and Tiber fields are designed to combine expertise and share costs in order to unlock further resources. Beyond these initiatives, the recent deepwater discoveries in the Mexican waters of the Perdido Fold Belt could point to the opening up of the next area of the Gulf for growing reserves.

Thursday, 6 August 2015

Genel Interims

by Will Forbes




This is the first interim results statement under Genel’s new management, with a new CEO and CFO taking the reins. In the near-term, we expect them to  focus on operational delivery in Kurdistan rather than seeking expansionist acquisitions in/outside the core area.

Genel’s interims add only incrementally to the overall story. Revenue, production and capex guidance all remain unchanged and operations at the fields continue, safe from ISIS. The company has disclosed capex estimates for the Miran/Bina Bawi gas condensate development, which highlights the very low development costs that KRG-focused projects benefit from. Upstream full life costs are estimated at less than $2/boe, with additional midstream capex (of $2.5bn) expected to be funded/managed by the KRG. These are extremely low by global benchmarks and underline the appeal of Kurdistan operations in a $50/bbl world.

Given the KRG statement a few days ago on starting payments to contractors (see our previous blog post here), the next few months will hopefully see positive news. Should the payments start in September (and ramp up in early 2016) as promised, we should see a marked increase in interest for Genel, DNO, GKP and others as they get paid for their production and start to recoup past profits (the Genel net KRG receivable alone now stands at $378.4m). The lack of payments visibility has been a major obstacle to the long-term story for contractors and the KRG. Once cash is flowing, the companies can start to invest more materially in other projects (for Genel this includes at Peskabir, Ber Bahr and Chia Surkh) where discoveries await appraisal and development.

African exploration has taken a back seat as expected, with relinquishment of Juby Maritime and studies continuing on the other two licences (Mir Left and Sidi Moussa). Somaliland remains a longer-term play (one we remain positive on), Ethiopia has a drill-or-drop decision due in January 2016 and the 24% interest in Cote D’Ivoire is under consideration for a farm-down before a commitment well in 2H2015.


Monday, 3 August 2015

Kurdistan ~ payments coming

by Will Forbes

The singularly most important concern for investors in Kurdistan-based companies over recent times has been the ability of the contractors to get paid on a timely basis for their production, and to a lesser extent, to recover back payments owed. This has taken a further step forward today with the publication of a statement from the MNR.


The full text of the statement is at the bottom of the post, but the important section to our minds is

"[t]herefore, from September 2015 onwards, the KRG will on a monthly basis allocate a portion of the revenue from its direct crude oil sales to the producing IOCs, to cover their ongoing expenses. Furthermore, as export rises in early 2016, the KRG envisages making additional revenue available to IOCs to enable them to begin to catch up on the past receivables due under their production sharing contracts."

A clear statement of intent from the KRG is extremely welcome, and shares in Kurdistan-based companies have all jumped today in trading. While the move to start compensating companies for back payments in early 2016 is very positive, this still leaves uncertainty for the period from September until then.  


When the KRG refer to covering "ongoing expenses", does this mean (i) just opex (ii) opex and in-country G&A (iii) opex, G&A and debt payments (iv) other? Obviously inclusion of debt payments would be more material, especially for Gulf Keystone, which does not have the cash piles that DNO and Genel enjoy (although all three have made efforts to support cash inflows through domestic sales). Non-producers such as Oryx, WesternZagros and ShaMaran should also benefit as it becomes clearer that funds invested in development will see a clear path to monetisation through sales.


In the meantime, we would expect that each are being paid regularly (GKP receives monthly payments under a direct contract with a domestic offtaker currently). 

We'll hear more at results announcements (in chronological order):
GENL - Q215 results - August 6th
DNO   - Q215 results - mid August
Oryx   - Q215 results - mid August
WZR   - Q215 results - August 13th
SNM   - Q215 results - August 14th
GKP    - H115 results - August 27th


We look forward to clarification on this point in time.



***



Statement by Ministry of Natural Resources regarding the producing International Oil Companies (IOCs) in the Kurdistan Region

From September 2015 onwards, the Kurdistan Regional Government (KRG) will on a monthly basis allocate a portion of the revenue from its direct crude oil sales to the producing international oil companies (IOCs), and as export rises in early 2016, the KRG envisages making additional revenue available to IOCs.

At the start of 2015, the KRG reached a deal with the federal government in Baghdad to export crude oil in exchange for regular payments of the Region’s 17% revenue entitlement. The arrangement was enshrined in the 2015 federal Iraqi budget.

The KRG recognizes the spirit of cooperation in which the budget deal was struck with the federal government and it remains determined to build on such progress, and through dialogue and discussion to reach a lasting agreement with Baghdad on all outstanding issues relating to oil and gas and revenue sharing.

The KRG has also been pleased with the level of technical cooperation on the ground from federal government entities such as the North Oil Company (NOC) and SOMO. The KRG will continue to facilitate oil export from NOC-operated fields in Kirkuk via the KRG’s pipeline network to Turkey.

However, due to a number of factors, the federal government has to date been unable to provide the Kurdistan Region with its monthly budgetary dues. As a result, the KRG has been obliged to introduce direct crude oil sales from Ceyhan to help pay Kurdistan Region’s governmental salaries, maintain vital government services, and of course, pay the Peshmerga and other security forces who are fighting Islamic State terrorists.

Although the revenue gained from direct sales is still below Kurdistan’s 17% share of the federal budget, it is significantly higher than the amount the federal government was able to allocate to the KRG on a monthly basis.

In this regard, the KRG acknowledges and appreciates the economic contribution to the Kurdistan Region made by the producing IOCs and their success in raising oil export from Kurdistan to record levels. They have demonstrated their commitment to the people of Kurdistan at a time when the Region has been fighting terrorism, enduring a budget shortfall from the federal government in Baghdad, and shouldering the social, political and economic burden of an influx of 1.8 million refugees and internally displaced people.

The KRG also recognizes the patience of the producing IOCs, which, despite receiving hardly any payments for their crude oil production since May 2014, have maintained operations and have continued to invest to support Kurdistan’s crude oil export.

Crude oil export is the principal revenue earner for the Kurdistan Region. But, it is also recognized that it is difficult for the IOCs to sustain oil export at its current levels, let alone increase it as planned, without receiving their financial dues.

Therefore, from September 2015 onwards, the KRG will on a monthly basis allocate a portion of the revenue from its direct crude oil sales to the producing IOCs, to cover their ongoing expenses. Furthermore, as export rises in early 2016, the KRG envisages making additional revenue available to IOCs to enable them to begin to catch up on the past receivables due under their production sharing contracts.

Monday, 27 July 2015

Petroceltic ~ Creating value in Algeria through execution

Petroceltic (PCI) is an E&P with assets in Egypt, Bulgaria and Algeria,where it is developing its flagship gas project Ain Tsila. As producing fields in Egypt and Bulgaria decline and exploration is de-emphasised, the valuation proposition in PCI shifts steadily towards Algeria. The drilling contract for Ain Tsila was awarded in April and the project is on track to be sanctioned by end-2015 and start up in Q418. Ain Tsila is fully funded until Q216 thanks to Sonatrach’s carry. The June launch of a $175m secured bond is an important step towards securing financing for H216-2018 – further progress on this front would remove uncertainty. A RENAV of 154p/share (which should grow c 16% pa over time) indicates the stock is pricing in nothing for a possible second phase at Ain Tsila or exploration.

Execution at Ain Tsila underpins value creation
PCI plans to monetise 2.1tcf of dry gas and 175mmbbls of condensate/LPG at the Ain Tsila gas field, targeting a Q418 start-up date. Ain Tsila is a transformative project for PCI, the only independent to develop a gas project in Algeria. Risks are mitigated by the use of proven technology and Algerian PSC terms, which protect returns from cost overruns and effectively guarantee a base return on investment. Key catalysts are the EPC contract awards and start of development drilling by end-2015. Given the vast gas resources in place (>10tcf GIIP), there could be further value upside from a second development phase in the long term (2022+). Ain Tsila will provide a significant production boost as Egypt and Bulgaria decline.

Exploration shifts to lower-risk plays
PCI is moving away from high-risk exploration and focusing activity on onshore licences in Egypt close to existing blocks, where discoveries could be brought onstream fairly quickly. In the medium term, exploration prospects in onshore/shallow-water Italy and offshore Egypt could offer significant upside.

Valuation: Ain Tsila value grows over time
Our core NAV is 125p/share, including Egypt, Bulgaria and Ain Tsila Phase 1. Hence at the current share price, the market is giving PCI no credit for Ain Tsila execution and upside and for  exploration in Egypt/Italy. Our RENAV is 154p/share. As the project progresses and first gas nears, its value should grow, supporting a RENAV CAGR of c 16% out to 2020. We estimate PCI requires c $580m of debt funding to get through the heavy spend phase in H216-18 until first gas. Beyond the recently announced $175m secured bond issue, we expect it to look to a mix of corporate bonds, project finance and RBLs. Progress on refinancing over the next 12 months and on strategic issues with Worldview would be a positive catalyst.

Source: Edison Investment Research





Cairn ~ Exposure to Senegal exploration, at lower risk

By Will Forbes, Kim Fustier

Cairn’s transformation over the last five years has given birth to a new full-cycle E&P company, with two projects under construction in the UK and a large exploration portfolio in the Atlantic Margin. The jewel in Cairn’s portfolio is Senegal, where it made one of the world’s largest offshore oil discoveries in 2014 (SNE). While the market will be closely watching Cairn’s Senegal drilling campaign starting in Q415, an even more material valuation lever for the stock is the outcome of the $1.6bn Indian tax dispute. In an environment where many independents are struggling to secure funding, Cairn is in the comfortable position of being fully funded until first oil from Catcher and Kraken in mid-2017. Cairn’s conservative strategy may reflect its mixed track record on past frontier exploration (outside Senegal) and M&A. Despite this, our RENAV of 216p/share offers reasonable upside at a much lower risk profile than many E&Ps.

Senegal appraisal story in the spotlight
Cairn is two years away from first oil at Catcher and Kraken (30% of our RENAV). The start-ups will turn the company into a self-funding E&P with the ability to reinvest cash flows into exploration and development. Meanwhile, investors should focus on the upcoming Senegal exploration campaign. Two appraisal wells on SNE and one exploration well (likely on the shelf edge) could raise confidence in the commerciality of the 330mmbbls SNE discovery. Senegal is key as it is Cairn’s main operated asset and only real exploration success over the last five years.

Indian tax dispute already priced in
The $1.6bn Indian tax dispute has been a thorn in Cairn’s side but has not affected its investment plans or strategy. Assuming the liability is not likely to be enforceable outside India, the maximum downside would be a write-off of the entire $530m (59p/share) Cairn India stake, which we think is already priced in by the market.

Valuation: RENAV of 216p/share
Cairn is arguably a lower-risk investment opportunity than E&P peers, as 35% of our 216p/share RENAV and 64% of our 119p/share core NAV sit in its c $700m cash pile (our estimate as of end-June 2015). Unlike many E&Ps, Cairn stands in the comfortable position of being fully funded on its $610m share of development capex and on exploration spend. In the medium term, the key levers for Cairn’s stock price are: the Senegal E&A campaign, which could add 11-24% to the shares; and an Indian tax resolution, which could theoretically add as much as 30%. Estimated future NAV growth is modest at 9-15% pa; however, this is understandable in view of the stock’s lower risk profile.


Source: Edison Investment Research

Rockhopper ~ Building a full cycle, exploration-led E&P

by Will Forbes
We belatedly publish excerpts from our recent Rockhopper initiation

The full initiation is available here


Rockhopper (RKH) is midway through a four-well exploration and appraisal campaign to explore and understand the reservoirs in its licences, including the 400mmbbl Sea Lion development, shared with Premier Oil (PMO). RKH is fully funded for Phases 1a and 1b, from which further development can be financed. This forms the majority of RKH’s core value (144p/share), which is well above the current share price. Furthermore, our analysis indicates the value should increase markedly over time as first oil approaches. Beyond Sea Lion, the Isobel Deep discovery hints at another major discovery field, once fully explored and appraised. With pre-drill estimates of over 500mmbbl, it could more than double gross resources.

Development of first oil at Sea Lion in 2019
After a planned final investment decision (FID) in mid-2016, Sea Lion should see first oil in late 2019 under Phase 1a, with two or more phases unlocking resources from PL032 and PL04 over time. Current plans are to produce around 60mb/d from an FPSO, though success in further drilling may boost these plans in the longer term.

Source: RKH


Exploration still provides upside
Recent news has de-risked potential at the Isobel Deep/Elaine complex, estimated to contain 510mmbbl pMean resources. If proven up, the complex would be a second major leg in the North Falkland’s story, and push gross recoverable resources over 900mmbbl. Further exploration and appraisal is needed and we expect the consortium to return to follow up the first Isobel Deep well to understand the potential. The well has further demonstrated RKH has good understanding of the basin with nine of 11 wells successful.

Valuation: Undervalued and should grow
The 2012 farm-out to PMO secured RKH’s financial position and put it in a rare group of fully-funded developers. Our core NAV (144p) is well above the share price, while RENAV including the Isobel Deep complex, its two upcoming Falkland wells (Chatham and Jayne East) and Faseto in Italy increases further. Of these, we are most interested in the results of any future Isobel drilling (timing yet to be firmed up), which could de-risk a complex, which is potentially as large as than Sea Lion, and unlock further value. Our analysis indicates core NAV growth of around 20%, promising strong returns for investors.

Source: Edison Investment Research



Tuesday, 14 July 2015

Wentworth Resources ~ company snapshot

Wentworth Resources ~ company snapshot
by Peter Lynch
Mkt Cap (£47.4m) Cash $5.5m (end 2014). Debt ($26m facility in place /~80% drawn)

Attendee; Katherine Roe.

In what appears to be a developing focus on Africa for our recent company snapshots, we were lucky enough to meet up with Katherine Roe last week. Katherine handles investor relations for Wentworth Resources, the East African gas company which is about to begin production and sales from their key Tanzanian gas development; Mnazi Bay.
Mnazi Bay, Wentworth 39.925% WI (exploration)/ Wentworth 31.94% WI (development and production).

Wentworth expects gas sales from Mnazi Bay to commence in Q3 2015. The Mnazi Bay Concession joint venture partners are in the final stages of agreeing payment guarantees supporting the gas sales agreement signed with the buyer; state owned Tanzania Petroleum Development Corporation (“TPDC”).  Once agreed, physical production can start with sales proceeds to begin within a few months thereafter. The first task will be to fill the transnational pipeline, expected to take around 1Bcf and take approximately one month.

Once on production, the gas is to be transported from Mnazi Bay in the south of Tanzania to Dar es Salam, the commercial capital, via the newly commissioned, government funded $1.2bn 36’ gas export line, owned and operated by TPDC. The primary purpose of the pipeline is supplying gas the domestic energy shortage in Tanzania and supporting plans for expansion of power generation within the next three to five years. The economics support the project, with electricity generated from natural gas costing 10c/Kwhr to produce vs power generation from diesel and other liquid fuels at c50c/Kwhr.

36' Dar es Salaam to Mnazi Bay pipeline
Following the successful MB-4 development well, completed in June, the Mnazi Bay field has five wells, as shown in the cross section map below; all five wells are completed as producers. Results from the MB-4 development well were positive, with the well encountering both a 43m and 24m pay interval in the Miocene. The well also confirmed Wentworth’s interpretation of the field, as pressure measurements in the well confirmed the lateral and vertical connectivity of each reservoir.

Mnazi Bay Gas Field Cross Section

Once on-stream, the 5 wells at Mnazi Bay are to be brought on production, with output expected at 80mmscf/d between the five wells during the initial testing phase. Beyond the initial ramp-up to 80mmcf/d, Wentworth targets a plateau production rate of 130mmcf/d (the rate agreed within the gas sales agreement) which the group expects to achieve in the second quarter of 2016.

Achieving 130mmcf/d may require the drilling of additional development wells which would be expected to take place in 2016. At 130mmcf/d the full field reserves of 443 Bcf would be produced of the remaining 16 year life of the Mnazi Bay Development License. Expansion beyond this level of output is dependent on further exploration success within the Mnazi Bay Concession. Wentworth has six exploration prospects identified in Mnazi Bay (shown in the map below) representing 1.5Tcf (614Bcf net) of potential resources, hence further exploration is expected.

Exploration prospects: Mnazi Bay

In terms of funding exploration, Wentworth expects future exploration wells to be funded from cash flow. Once on-stream and producing 130mmcf/d, Mnazi bay is expected to generate c$3.5m in revenue per month. Funding exploration from cash flow is effective from a tax perspective as exploration expenses, whether the activities are successful or not, are recoverable against future cash flow within the concession.



In terms of potential for expansion beyond the current 130mmcf/d featured in the GSA, Wentworth estimates in the third year of production (2017) up to  four further development wells would be required to reach 210mmcf/d production, assuming reserves can be increased with exploration success to back this growth. Beyond this, in Year 5 (2018), the Company estimates an additional three wells would be required take output to 270mmcf/d. In terms of any capacity limits for future growth, capacity of the Mtwara to Dar es Salaam export pipeline is put at around 750mmcf/d; hence Wentworth are unlikely to find production scaled back due to export constraints.

Monday, 13 July 2015

Genel operations update ~ still waiting for export payments

Genel’s trading statement has been over-shadowed to some extent by the unexpected departure of its Chairman (Rodney Chase) with Tony Hayward stepping up to Chairman and Murat Özgül taking over as CEO. While Mr Hayward’s position as Chairman of Glencore always suggested that he eventually to step back from his CEO role at Genel, the timing seems a little surprising/sudden. He is replaced by Murat Özgül , who has been at Genel since 2008 and was formerly Chief Commercial Officer, so he knows the business extremely well. His capital markets experience is reasonably limited, but we expect he will be ably assisted by new CFO Ben Monaghan, whom we met a few weeks ago. Genel now has a new management team, but we do not expect any material change of strategy in coming months - it will remain Kurdistan, Kurdistan, Kurdistan.

Operations ticking along The operations of the company continue, with record volumes of over 100mbd (net) on peak days from its Taq Taq and Tawke fields. Gross surface processing capacity at Taq Taq is now  150mbd, with Tawke gross wellhead, processing and pipeline capacity is 200mpd. 
Production guidance has been maintained at 90-100mbd with revenue guidance of $350-400m at $50/bbl.

Along with many other E&Ps, Genel has tightened its belt with the falling oil price, reducing both  its G&A and capex. The company has re-focussed on Kurdistan development and has taken a step back from exploration and as a result, capex guidance has been reduced to $150-200m (from $200-250m).

No payments for oil exports in H115
The key issue with Genel (and other KRG-producers E&Ps such as DNO and Gulf Keystone and to a lesser extent non-producing companies such as Western Zagros and Shamaran) is payment for exports. Kurdistan is incurring material additional expense by fighting against the ISIS forces, while not receiving steady payments for its oil production from Baghdad. As a result, the oil contractors are not being paid in full for their production. Genel’s trade receivables at 30 June 2015 stood at $378m (vs $230m in Dec 2014), an increase of $148m. Given H115 revenues are estimated at $200m, this implies that 75% of production (by value) has not been paid for. Volumes sold to domestic buyers and the Bazian refinery (together making up 28% of volumes) are probably being paid for, so Genel has received no compensation for its export volumes. This needs to change.

The KRG government is keenly aware that oil companies cannot continue to produce oil without being paid and is seeking to resolve the payments issue, with some reports suggesting that it will seek to market the oil independently outside the existing framework of SOMO (the central Iraqi oil marketing organisation). While this would deliver more reliable payments for the KRG and therefore contractors, it also brings up the possibility of a break-up of federal Iraq.

Elsewhere, the company continues to progress its gas projects in the portfolio; Miran and Bina Bawi (Kurdistan), with planning on mid-stream development. Discussions on FEED, EPC tender and financing options continue. 

Indexed share performance for KRG-based companies since mid-2014. Producers have done best, and balance sheet strength has dominated

Thursday, 25 June 2015

Company Snapshot ~ Sterling Energy

Sterling Energy (SEY). Mkt Cap £35m. Cash £62.5m. Debt £Zero

Attendee; Eskil Jersing (CEO)

Last week we caught up with newly appointed CEO of Sterling energy, Eskil Jersing. Our initial interest in the company was sparked by a perceived valuation gap, as Sterling’s ~$100m (£62.5m) in cash appears markedly under-represented in its current market cap of £38.5m. Of this cash the group has ~$30m (~£19m) of commitments, a $22.7m (£14.19m) abandonment liability for the Chinguetti field in Mauritania, and a further $8m (£5m) of potential stage payments in Somaliland. Post these commitments the stock remains at a discount to cash, with no value ascribed to the current asset portfolio, or indeed, any 'option value' as management holds the cash to do deals in what most view as being a buyers’ market.

Beyond the obvious balance sheet strength, Key highlights (as we see them) from an asset perspective are the group’s growing position offshore Mauritania, where Sterling added two material licences in 2015; C3 (coastal / shallow water) & C10 (deeper offshore). Both blocks were acquired at minimal cost, notably C10 has an exploration well planned to spud within 18 months. In Madagascar, worth highlighting is Sterling’s fully carried status on the current 3D seismic survey, with potential for an exploration well to be drilled in 1H 2017. In terms of ‘sleepers’ the group maintains positions in both Somaliland (security issues) and Cameroon (border dispute). Despite activity in both regions being on hold, the group’s interests could represent a windfall for investors if their respective issues can be resolved.


Mauritania

PSC B, Chinguetti

The Chinguetti field was discovered in 2001 and lies in 800m of water, 80km off the coast of Mauritania. Sterling currently holds an 8% economic interest via funding agreement with SMHPM (Mauritania national oil company) and a sliding scale royalty over 5.28% of Premier’s share of production. In 2014 these combined interests resulted in 432bopd production net to Sterling ($6.9m cash flow) from gross output from the field of 5512 bopd.





Block C-3, Sterling Energy 40.5%, position acquired (February 2015)


In February 2015, Sterling acquired (pending Government approval and completion of the transaction) a 40.5% working interest in block C-3 from Tullow in exchange for ~$2.5m towards back costs. C-3 is a shallow water exploration block, shown in the above map as running along the coast of Mauritania. The block covers an area of 9,781km2 at average water depth of under 100m. Interest holders in C3 are as follows; Tullow 49.5% (Operator), Sterling Energy 40.5% and SMHPM 10% (Mauritania’s state oil company). Block C-3 is currently in exploration phase 1, which involved a 1600km2 2D seismic survey, which was acquired in late 2014. The survey is currently in-house and under interpretation.

The second exploration phase runs from June 2016 and involves the acquisition of a further 700km2 of 3D seismic and the drilling of a single exploration well. The group are expected to make a ‘drill or drop’ decision on the block by the first half of 2016, once the results of the 2D seismic interpretation have been evaluated.

Block C-10, Sterling Energy 13.5%, position acquired June 2015.

Sterling Energy acquired (pending Government approval and completion of the transaction) a 13.5% interest in block C-10 in exchange for $50,000 of back costs. Block C-10 surrounds the Chinguetti field and was awarded to Tullow in 2011. C-10 interest holders are as follows; Tullow 76.5% (Operator), Sterling Energy Mauritania Limited (SEML) 13.5% and SMH 10%. C-10 is an offshore block covering an area of 10,725km2 with water-depth varying from 50 to 2,400m.

The C-10 licence is in the second phase of exploration (Nov 2014 – Nov 2017) which involves the drilling of a single exploration well. Tullow has identified a drill ready prospect within a multitude of additional prospects and leads. Current technical work focuses on maturation of the prospect inventory following the receipt of the recently reprocessed 3D survey covering the area. Tullow expects to drill an exploration well in 2016 at an anticipated cost of $77m ($11.55m net to SEML). Phase 3 exploration period runs from Nov 2017 – Nov 2020 and requires the drilling of a further 2 exploration wells.

Madagascar

Ambilobe Block, Sterling 50%, acquired 2004.

Ambilobe PSC was awarded to Sterling Energy in 2004. Ambilobe is an offshore block covering an area of 17,650km2.in 0-3000m water depth. Interest holders in Ambilobe are Sterling 50% (Operator) and Pura Vida 50%. Pura Vida farmed in to Ambilobe in late 2013, taking a 50% WI in exchange for carrying costs associated with a 3D seismic survey, acquisition of which completed in June 2015. The carry is expected to cover all costs of the 3D seismic survey.





A 5500km 2D seismic program had already been acquired and interpreted. CGG, who carried out the 3D survey expect interpretation, resulting in a worked up series of prospects, to be completed by early 2016, completing work commitments under the second phase of exploration. Phase 3 exploration period involves the drilling of a commitment well, which potentially could be drilled in 1H 2017.

Somaliland, 


Odewayne PSC, 40% working interest, awarded in 2005.

Sterling holds a 40% WI in the Odewayne PSC in Somaliland, for which the group has paid $17m with a further $8m of potential, staged payments. The onshore block covers block SL6 and parts of blocks SL7 & SL7 and covers an area of 22,840km2 equivalent to 100 UKCS blocks. Interest holders are Sterling 40%, Genel 50% (Operator) and Petrosoma 10%. Operations in Somalia have been interrupted by security issues; as a result of these delays a 2-year extension to the current work period (phase 3) was granted in May 2014, with the dates of subsequent periods adjusted accordingly.





Odewayne represents frontier acreage with no seismic control and no drilling to date. Sterling are carried by Genel for all costs associated with the third & fourth exploration phase, with Sterling’s expenditure in these periods limited to $8m due to Petrosoma at certain operational milestones. The PSC is currently in the third exploration period (May 2012 – Nov 2016) which involves a gravity mag survey (completed) and 500km of 2D seismic data, which remains outstanding.

The 2013 aero mag survey confirmed a broad basin over the Odewayne block thought to be of Jurassic to Cretacaous age, analogous to producing basins in Yemen. Field work on the block has shown evidence of numerous seeps, encouraging signs that the basin includes a working hydrocarbon system. The pending 2D seismic survey will be the next step to defining drillable prospects at Odewayne, exploration activity in the block is currently on hold due to security threat. Both Sterling and Genel are supporting the government in setting up an oilfield protection unit (OPU), with the hope of commencing seismic operations once safe operation of personnel can be established.
The fourth exploration period (Nov 16 – May 2018), for which Sterling costs are to be fully carried by Genel, involves a further 1000km of 2D seismic data and the drilling of a single exploration well.

Cameroon

Ntem concession, Sterling 100% WI (force majeure)

The Ntem concession is a large undrilled block covering an area of 2,319m2 in 400m to 2000m water depth. The concession has been in force majeure since June 2005 as a result of overlapping maritime border claims by the Republic of Cameroon and the republic of Equatorial Guinea.




The force majeure preventing activity in the block was lifted in January 2014, allowing drilling of the Bamboo-1 exploration well outside of the disputed border area. The Bamboo-1 well was drilled to a total depth of 4,747m in 1600m of water. The well encountered well developed high porosity sandstones but sadly no significant hydrocarbons. The block does contain additional potential, specifically the Tonga & Baobab prospects. The current exploration period re-commenced in January 2014. In May 2014 the JV partners declared force majeure once more, suspending their work obligations under the terms of the Ntem concession.