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

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.

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