Otto Energy — Update 18 February 2015

Otto Energy (OEL) is an ASX-listed E&P with interests in two operated permits in the offshore Philippines (SC55 and SC73) and two non-operated blocks onshore Tanzania (Kilosa-Kilombero and Pangani). The Philippines is a proven oil and gas province, and Otto’s Tanzanian licences lie to the south of proven basins in Uganda and Kenya. On 12 December 2014, Otto received from Nido Petroleum an offer of US$108m for its 33% share in the operated Galoc oil field in the Philippines, surpassing a previous offer by Risco Energy. The sale, completed on 17 February 2015, represents a material change in strategy for Otto and was agreed at a propitious time given the oil price decline. Following a proposed c US$58m capital return to shareholders, Otto will retain sufficient cash to fund its planned exploration activities over the next 18-24 months. In particular, the company plans to drill the 95mmbbl Hawkeye-1 deepwater oil prospect in the Philippines in Q315. In January 2015 Otto announced a deal to farm down a 15% WI in its SC55 licence to PNOC (down to 78.2% WI). It may further reduce its interests in the Philippines and in its Tanzanian blocks (50% WI) before drilling to mitigate exploration risks and fund its drilling plan.

After the completion of the Galoc sale, Otto no longer has any producing assets and offers investors pure-play exposure to exploration in the Philippines and Tanzania. The stock trades at a discount to our core NAV of A$0.11/share, based on Otto’s net cash after receipt of the US$108m divestment proceeds, minus G&A. This appears too harsh given Otto’s unusual position among small-cap E&Ps in being able to fund its drilling programme over the next 18-24 months.

Our RENAV of A$0.22/share includes the Hawkeye-1 well to be spudded in Q315 (A$0.09/share) and two wells in Tanzania (A$0.02/share given a low CoS). We assume that Hawkeye-1 net well costs are fully carried by PNOC in exchange for the 15% reduction in Otto’s WI. Otto is committed to drilling one well in each Tanzanian licence before February 2016, including the 151mmbbl Kito prospect in the Kilombero basin, which has been identified on 2D seismic. Otto can drill the two Tanzanian wells at its current 50% WI as they are relatively cheap. There could be longer-term upside from exploration assets in the Philippines, notably the 281mmboe gas/condensate Cinco prospect in the SC55 licence, and further gassy leads that we do not model.

On our estimates, Otto will have c US$52m in cash after receiving the full Galoc sale proceeds and paying the capital return, leaving it with ample means to fund its capex programme well into H216. We expect that Hawkeye-1 preparation and Tanzanian G&G work could absorb c US$15m in the year ending June 2015. We expect capex in the following year to stay around US$16m assuming Otto gets a full cost carry for its Hawkeye-1 well and drills two wells in Tanzania as planned.

Exploration success at Hawkeye-1 is critical to our RENAV valuation. The recently announced PNOC farm-out deal significantly reduces the risk of drilling delays on Hawkeye-1. We assume Otto is now fully carried on the well; however, farm-out terms with PNOC have not been disclosed and may differ. We expect Otto to contract a rig in spring 2015 and spud the well in Q315. A discovery would raise our chance of success materially from the current 13.5%.

The ongoing G&G work in Tanzania should also be watched closely ahead of drilling. Otto expects to complete seismic interpretation by end-Q115 with a view to selecting drilling targets for 2015 or 2016.

Following the Galoc sale, Otto Energy has morphed from a producing E&P to a pure-play explorer with early-stage exploration assets in onshore Tanzania and the Philippines offshore. With the sale of Galoc for US$108m and subsequent capital return of c US$58m, Otto has at least US$48m to spend on progression of the early geological and geophysical (G&G) work in Tanzania and the Philippines. This is an unusually advantageous position for a small-cap E&P.

After the divestment of its Galoc field in Q115, Otto Energy retains interests in two operated offshore licences in the Philippines: Service Contract (SC) 55 and Service Contract 73. Otto became operator of the SC55 block following the acquisition of NorAsian in 2005-06. Between them these blocks offer a range of prospectivity, covering oil and gas prospects across sandstone and carbonate reservoirs. Work on SC55 is further advanced with two drill-ready prospects, Hawkeye and Cinco, while seismic data from SC73 are being reprocessed with a view to identifying targets.

After its recent farm-out deal with PNOC, Otto holds a 78.18% WI in block SC55, located in the south-west Palawan basin offshore the Philippines and covering an area of 9,880km2. The deepwater (1,400-1,700m water depth) block sits in a proven oil and gas fairway that extends from Borneo in the south-west to the producing Philippine fields north-west of Palawan. Two drillable targets have been defined on 3D seismic: Hawkeye and Cinco, with numerous follow-on targets.

BHP Billiton funding: in May 2011 BHP Billiton exercised an option to acquire a 60% stake in SC55 and take on operatorship of the block by funding a 3D seismic survey and drilling two exploration wells. BHPB’s preferred drilling candidate at the time was Cinco. Assuming c US$48m gross well costs, the block’s implied gross valuation was over US$160m. BHPB pulled out from SC55 in November 2013 following the arrival of a new CEO at BHPB and subsequent change in strategic focus of BHPB’s petroleum unit. Otto reassumed its 60% WI and secured US$27.5m from BHPB for exploration drilling as per the termination agreement, of which US$3m has been paid and US$24.5m will be paid by BHPB on drilling the first well. This leaves Otto to disburse only c US$13m for the well at its 78.2% working interest. In addition, Otto has access to all the 3D seismic acquired in the permit.

Drilling a well in Q315: a deepwater well must be drilled on SC55 by 23 December 2015, following the 12-month contract extension granted in November 2014. Otto has ordered long-lead items and is hoping to secure a rig by spring 2015 for drilling in Q315. Although much has happened since then, it is worth noting that in 2008 Otto expected to drill its first well on SC55 in 2010. Rig availability in South-East Asia has improved markedly given the ongoing offshore drilling downturn, with deepwater rig rates coming down by 25-35% in the last year.

Following the terminated BHP Billiton deal, Otto launched a farm-out process in early 2014 to find a new partner to fund the drilling of the Hawkeye-1 exploration well. On 9 January 2015 Otto announced it had agreed to farm out a 15% WI to PNOC Exploration Company, the E&P arm of the Philippine National Oil Company, reducing its WI from 93.18% to 78.18%. The commercial terms have not yet been finalised and disclosed, and the deal is subject to approval by the Philippine authorities. Based on our risked valuation of Hawkeye alone, we estimate that Otto is fully carried by PNOC for its remaining net share of well costs. However, Otto continues to look for other farm-out partners. We understand it aims to retain a minimum 50% WI and could farm out up to 28% WI. Otto management is open to farming out to both operator and non-operator partners, as it believes it has the capabilities to operate a deepwater exploration well at Hawkeye-1.

Gas discoveries offshore Philippines would be more difficult to monetise than oil finds, but feasible. Gas from Cinco could either land on the island of Palawan, or possibly be sent to the Malampaya platform almost 400km away (although gas discoveries would need to be very significant to justify a new pipeline). Gas monetisation would be helped by high price realisations (at least for Malampaya gas) of around US$11-12/mcf, close to East Asian LNG prices. Gas consumption in the Philippines has been growing at 3.2% pa in the decade, constrained by available supply, while latent gas demand is likely much higher. The country is about to become an LNG importer: a Hong Kong-based company, Energy World Corp, is building a 3mpta LNG import terminal and gas-fired power plant expected to be operational in early 2015. Two other LNG import projects have been proposed.

In September 2013, Otto was awarded a 100% WI in block SC73 in the southern part of the Mindoro Basin-Cuyo platform. The 8,440km2 licence is covered by 3,000km2 of existing 2D seismic. The area is a proven active petroleum system, with the 1994 discovery of oil in Maniguin north of SC73 and the presence of oil seepages in the Mindoro Island region. Otto is currently working to reprocess some of the existing data over the 18-month period ending H115 with a view to identifying prospects.

On 12 December 2014, Otto announced it agreed to divest its 33% share of its operated Galoc oil field in block SC14C to Nido Petroleum for US$108m. The proposal is superior to Risco Energy’s offer of US$101.4m announced in September, which Otto had previously accepted. The deal was approved on 20 January 2015 and completed on 17 February 2015, when Otto received final proceeds from Nido.

Otto acquired an 18.3% share in the shallow-water (290m water depth) Galoc field in October 2007 with proceeds from an equity raise, a year before first oil. It became operator in September 2011 when it bought a further 14.2% WI in the licence from Vitol, raising its interest to 33%. The field underwent a major upgrade in 2012, which extended the field life to 2020. Gross production rose to c 14mb/d after start-up of Phase II in late 2013, and declined rapidly to <7.8mb/d by Q314.

Otto’s exit price achieved with Nido of US$327m for 100% compares well to the implied gross asset value of US$131m paid by Otto in August 2011, even if we account for capex spent and reserves depletion in the intervening period. It appears that the timing of Otto’s divestment, shortly after completion of Phase II, was judicious as it was agreed before the sharp decline in the oil price (with respect to Risco Energy’s initial offer in September) and maximised value to the seller. Importantly, Otto’s experience as an operator of an offshore field from 2011 to 2014 could help it to develop future discoveries in licences SC55 and SC73.

Management expects the proceeds of the Galoc sale to fund all the company’s planned exploration activities in Tanzania and the Philippines for the next two years. In addition, Otto is planning to pay a capital return of A$0.064/share to shareholders (raised from A$0.06/share initially), equivalent to c US$58m. Given that the company has historically largely been funded by equity (with a total of US$130m raised between 2007 and 2011), it is not surprising that Otto is looking to return cash to its shareholders. This will leave the company with at least US$50m to fund its exploration activities.

Otto Energy has previously held non-operated onshore licences in Turkey (Thrace Basin, gas), Italy (Po Valley basin, gas) and Argentina (Cuyana Basin, oil). The company withdrew from Argentina in 2009, followed by exits from Italy and Turkey in 2010 after unsatisfactory drilling results. It then decided to refocus its portfolio on the Philippines while searching for new opportunities, particularly in East Africa.

In the Philippines, Otto’s exploration portfolio has been streamlined in recent years after relinquishing three blocks (SC51, SC69 and SC50) after poor drilling results and/or failure to find suitable farm-out partners. In licence SC55, Otto had previously identified the 3.1bnbbl OIIP Marantao prospect based on 2D seismic data. 3D seismic shot in 2010 led to the firming up of prospects Hawkeye and Cinco, while Marantao remains a longer-term follow-up prospect.

Otto holds a non-operated 50% working interest in two licences, Kilosa-Kilombero and Pangani, covering a total area of 34,000km2 onshore Tanzania. Otto entered the licences and signed production sharing agreements (PSAs) in February 2012 through an acquisition from operator and fellow ASX-listed E&P Swala Energy after a two-year search for assets outside the Philippines. Otto and Swala identified the opportunity in Tanzania on the basis of legacy gravity and aeromagnetic data dating from the 1970s. Tellingly, the partners made the decision to enter the country in 2010-11 before Tullow’s success in Kenya, where the Ngamia-1 well found oil in March 2012.

There has been no drilling to date on either block; however, they both lie to the south of the proven oil basins of Lake Albert in Uganda and the Lokichar basin in Kenya, where around 2.3bnboe of contingent resources have been discovered over the last eight years by Tullow and Africa Oil. The blocks’ greater proximity to the coast should make oil monetisation easier than in Uganda or Kenya.

Otto and Swala acquired new aeromagnetic and gravity data in 2012 and carried out a 2D seismic survey in 2013 over the two licences. The surveys confirmed the presence of three sedimentary basins in the Kilosa-Kilombero licence and the possibility of two basins at Pangani. Results analysis suggests structural similarities in particular between the Kilombero and Lokichar basins. Otto hopes to drill an exploration well on each licence in 2015 and is committed to do so before February 2016. If Otto’s preference is to find a farm-out partner before drilling, the wells could be delayed to 2016+.

Kilosa-Kilombero contains three basins – Kilosa, Kidatu and Kilombero – stretching from north to south. The Kilosa rift is separated from the Kilombero and Kidatu rifts by an uplifted zone. The southern Kilombero basin is c 80km long and 20-30km wide, and is interpreted from seismic as a Neogene (Miocene-Pliocene) age basin with a depth to basement greater than 3,000m. The age of the sediments deposited is estimated to be similar to those in the Lake Albert and Lokichar basins.

The Kito prospect in the Kilombero basin has been identified from 2D seismic acquired in Q413, which shows a significant rift fill bounded to the west by a major fault. Seismic data show relatively flat spots close to the bounding fault, which could be interpreted as oil-water contacts. Kito has been independently assessed in a competent person’s report to contain best estimate prospective resources of 60.4mmbbl (net of 20% government back-in rights in the development phase) net to Otto, with a range of 19-170mmbbl. Gross P50 oil initially in place (STOIIP) is estimated at 596mmbbl split between two horizons, with a 25% recovery factor giving 151mmbbl of gross unrisked resources. Porosity and permeability of the sandstone reservoir rocks are expected to be good at 20-25% and 2,000mD. The deeper horizon appears to be faulted and compartmentalised; however, STOIIP is seen as high enough to allow for several injection wells if necessary.

An additional 430km2 of 2D seismic is being acquired in the Kilombero basin during Q414, with initial interpretation indicating the presence of four new structures, each 5-10km long. The structures are thought to be roll-over anticlines similar to those found in the Lokichar basin. The survey was completed in January 2015, and seismic results interpretation should be finished by end-Q115. The analysis is expected to lead to the selection of one or more drilling targets for 2015.

The CPR stresses that despite the structural similarities between these basins and the proven Lake Albert and Lokichar basins, it is too early to say if Kilosa-Kilombero contains a petroleum system analogous to these areas. The CPR assumes a geological chance of success (GCoS) of 8-9% for Kito, based on a play chance of success of 39% (including source, reservoir and seal risk) and a prospect-specific chance of discovery of 20-22% (including charge, reservoir and trap risk). We use the CPR’s GCoS of 8.5% and overlay a 50% commercial CoS, giving a 4.25% blended CoS.

Outside the Kilombero basin, seismic results indicate the presence of large structures in the Kidatu Basin close to the basin’s boundaries, as well as a significant intra-basin high of potentially 30-60km2. Since Otto and Swala are planning to focus on Kito in 2015, the first well in the Kidatu basin will probably be drilled in 2016 or beyond.

200km2 of 2D seismic was acquired in Q413 over the Moshi and Mvungwe basins in the Pangani licence. Both basins were identified on original gravity and magnetic data. The partners have made more use of the gravity data due to the presence of volcanics near the surface. According to Swala, areas of distressed vegetation could indicate hydrocarbon seepage.

The late 2013 seismic survey shows that the Moshi basin to the north of the block is a deep sedimentary basin of Neogene age, with basin fill to between 2,000m and 3,000m depth. The Mvungwe basin is shallower at less than 1,000m depth, but the Pakwach Basin in Uganda, where six discoveries have been made, shows that shallow basins can be oil-prone with the right heat flows. An additional 200km2 of 2D seismic was acquired in Q314 on the Moshi basin with a view to improving geological understanding and identifying a drillable prospect for 2015.

Otto has allowed for funding the Tanzania drilling programme at its current 50% WI in capital estimates and does not depend on farm-outs to drill the next two wells. The Tanzanian onshore wells are expected to cost around US$10m gross, or c US$5m net to Otto at 50% WI, pre-government back-in rights. We believe this makes sense, as farming down after a discovery is generally a good point to divest assets and doing so would help to maximise value for Otto.

The company has experienced frequent changes in management, with four CEOs since 2008. With the recent shift in strategy towards exploration, we would expect Otto to add G&G expertise.

Rick Crabb (Chairman) practised as a solicitor from 1980 to 2004, specialising in resources, corporate and commercial law, with considerable offshore experience. He is now a full-time director, and is chairman of uranium producer Paladin Energy and other resource companies.

Matthew Allen (CEO) was appointed CEO in February 2014 after joining Otto in 2009 as CFO. Mr Allen led Otto’s acquisition of an increased equity position in the Galoc oil field in 2011, the raising of over US$40m in project financing for the 2013 Phase II development at the Galoc oil field and numerous other acquisition and divestment transactions. He previously spent eight years with Woodside and has worked in Asia, Africa, Australia and the Middle East.

Craig Hasson (CFO) joined Otto as group financial controller in November 2012 and was appointed CFO in February 2014. He is a chartered accountant with over 12 years of resource-related financial experience in Australia, Europe, Africa and Asia. He previously held roles with Cairn Energy, Dragon Mining and Resolute Mining.

Paul Senycia (VP Exploration, New Ventures) has more than 30 years of international oil and gas business experience in Australia, North and West Africa, North America, Europe and Asia. Mr Senycia spent the majority of his career with Woodside and Shell. He was head of evaluation at Woodside and subsequently exploration manager at Oilex before joining Otto Energy in April 2010.

We generally value oil companies using an asset-by-asset NAV derived from detailed DCF modelling (see our oil & gas valuation principles). Core NAV includes production, development and contingent resources that could be developed, while exploration is valued in our RENAV only if wells are planned and funded in the next 18 months. Beyond the 18-month target timeline, we may employ other metrics or valuation techniques, or refer to farm-out scenarios to inform investors.

We may apply a risking to the values ascertained. This aims to take account of geological, technical and commercial uncertainties. For a company that lacks funding or production that may provide funding for a development, we assume the company will have to dilute its working interest in any exploration to get through appraisal/development. This dilution is impossible to accurately estimate, and so we may arbitrarily apply a further haircut in addition to our 50% CCoS for pre-FID projects. Our overall CoS applied would therefore be materially lower than any geological CoS.

For commodity pricing, we assume US$80/bbl long-term inflated for Brent, while we use local gas prices where appropriate. In this case, we assume US$12/mcf for Philippine gas, escalating in line with Brent thereafter. In Tanzania, we assume that any gas discoveries will be stranded and do not value them. For Hawkeye, Cinco and Kito, we use best-estimate prospective resource estimates given by the company and the RISC CPR, while we have assumed a 100mmboe discovery for the Pangani licence. We have modelled production start-ups in 2020-22 for all prospects.

Our core NAV is A$0.11/share, above the current share price and equal to cash (including the value of the capital return) minus G&A. Otto has now received the full proceeds from the Galoc sale. Our RENAV of A$0.22/share includes Hawkeye assuming a full cost carry and two wells in Tanzania.

The Cinco well is deemed as long-term exploration potential given its unfunded nature. We do not model the gas/condensate leads in licence SC55 at this early stage.

Otto has already farmed down part of its interest in the Philippines and may farm down Tanzania to reduce financial risk. Equity markets are pricing in little value for exploration, while industry players have been willing to ascribe greater value. Our analysis of African farm-out deals shows that farm-out valuations (on a gross block basis) differ wildly across the selection, with values ranging from under US$10m to c US$250m for onshore blocks and up to c US$400m for offshore blocks.

With cash of over US$52m after the capital return distribution and before capex, Otto Energy is well funded for initial exploration activities in Tanzania and in the Philippines well into H216. We model capex of US$15m for the fiscal year ending June 2015, roughly split 50/50 between Hawkeye-1 well preparation and G&G costs and geological studies and pre-drilling preparation in Tanzania. Expenses on the Philippines blocks in FY15 may well be lower than our assumption as the prospects are drill-ready. We see capex of US$16m in FY16, largely comprised of net drilling costs for two wells in Tanzania, and assuming that Otto is carried by PNOC for its net share of Hawkeye-1 drilling costs.

Even after the recent farm-out to PNOC, any wells in the Philippines are probably too much for the company to fund and would be too risky at 78.2%, so we expect Otto to only drill once partners are involved. If the company is successful in getting full carries for its two wells in the SC55 licence, Otto could therefore be exposed to up to four wells in the coming years, drilling for nearly 400mmboe of net unrisked resources. Any discoveries will require material funding to appraise and develop, well beyond Otto’s financial capabilities. We would thus expect a reduction in asset ownership and/or equity dilution before first production.