oil _gas_review_-_february_2012

February 2012

Oil & Gas AIM Initiations

This is a marketing communication. It has not been prepared in accordance with legal requirements designed to promote the independence of investment research and is not subject to any prohibition on dealing ahead of the dissemination of investment research.

Dr. Dougie Youngson Research Analyst +44 (0) 20 7107 8068 [email protected]

Sam Wahab Research Analyst +44 (0) 20 7107 8094 [email protected]

ACA

Seymo

ur Pierce

Oil & G

as AIM

Initiations | February 2012

Seymour Pierce Limited20 Old Bailey, London EC4M 7EN

Switchboard +44 (0)20 7107 8000Corporate finance fax +44 (0)20 7107 8100Research and Sales fax +44 (0)20 7107 8102

www.seymourpierce.com

Seymour Pierce equity research 1

Oil & Gas AIM Initiations February 2012

Table of Contents

Introduction 3 Top picks 4 Bayfield 4 Borders & Southern 5 Gulf Keystone Petroleum 6 Xcite Energy 7

Top regions 8

Oil and gas price outlook for 2012 11

Valuation methodology 12

Exploration 12

Production 12

Companies

Aurelian Oil & Gas 13 Borders & Southern Petroleum 27 Chariot Oil & Gas 37 Faroe Petroleum 51 Frontera 67 Gulf Keystone 77 Gulfsands Petroleum 91 Xcite Energy 107 Bayfield Energy 115 Gold Oil 129 Independent Resources 143

Glossary of terms 156

2 Seymour Pierce equity research

Oil & Gas AIM Initiations |February 2012



Introduction

In this oil and gas sector report we are initiating on 11 AIM listed companies. The core of the note focuses on companies which we consider have interesting investment cases. We believe that key criteria investors should focus on are:

• Strong management teams

• Assets which can be commercialised

• A deliverable strategy which will yield shareholder value within a reasonable timeframe

AIM suffers from a great number of companies that tick none of these boxes. However, we believe that the companies covered in this report tick most if not all of these boxes and should be worth your consideration.

We have highlighted what we believe are likely to be some of the best performing stocks in 2012. We have also identified what we consider are likely to be the core regions for oil and gas activity in the short term.

We have highlighted what we feel are likely to

be some of the best performing stocks in 2012..



Top pick overview

Bayfield Proposition Bayfield’s recent operational update provided the first opportunity post-IPO to evaluate progress across its portfolio. The company continues to make positive in Trinidad with the spudding of the East Galeota exploration well at the end of January which is expected to take 42 days to drill. A further two exploration wells will be drilled at East Galeota which could provide additional upside resource potential.

At the Trintes (Trinidad) field the company successfully drilled two appraisal wells: B10 & B8. These have de-risked the management’s production projections for the field and should also increase the upside potential for the field, once production has stabilised.

Catalysts The company has several near-term exploration (EG8 well) and appraisal targets which could provide share price triggers during 2012 on the assumption of positive results. Despite production being pushed back (due to operational and weather reasons) it should reach our previous production target of c.4,000boepd in 2H2012. This will enhance financial performance in the latter part of this year and provide a strong production and financial basis for the company as it moves its 2013.

Valuation

SOTP valuation matrix

£ million p/share

Production 96.9 45.1Reserves 90.3 42.0Net cash* 28.1 13.1Less: G&A (20.0) (9.3)Core Value 195.4 90.9Contingent resources 36.8 17.1Target Market Cap 232.1 108.0 Source: Seymour Pierce Ltd *We have assumed a post placing cash balance using managements FY12E guidance of c.$55m

Our core valuation comprises a revised DCF analysis of Bayfield’s producing assets, the company’s externally verified reserve estimates, and the FY12E net cash balance. We also attribute a discounted general & administrative (G&A) charge for field related expenditure in relation to the Trintes play. On this basis our revised valuation indicates that Bayfield is currently trading at c.50% below its core asset value alone. We reiterate our Buy recommendation and target price of 108p.

SOTP waterfall chart

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Borders & Southern

Proposition 2011 was the turn of the northern Falkland players (RKH & DES) and in 2012 the activity heads south with both BOR & FOGL drilling. Whilst these companies share common issues such as regional politics, BOR stands out amongst its peers in terms of the potential size of its drilling targets as well as the expertise of its management team.

Catalysts Drilling at the first prospect is underway. The company forecasts that it will take 90 days to drill both Darwin and Stebbing. The key price drivers will be the well results from these two wells. We highlight that the two wells are testing two different types of play. Failure (or success) at the first well does change the risk profile of the second.

Valuation


NAV £m p/share

Darwin 199 46Stebbing 227 53Net cash 116 27Core value 542 126

Source: Seymour Pierce Ltd & Company data

We have valued Borders in terms of a risked exploration net asset appraisal of their near term assets. The company intends to drill two wells in Q1 2012 (Darwin and Stebbing), and we feel it is appropriate to value it on this basis.


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Gulf Keystone Petroleum

Proposition 2011 saw substantial resource upgrades across its assets in Kurdistan. 2012 will see the company move into export production for the first time, resulting in the first significant cash inflows for GKP. The entrance of ExxonMobil and Total into the region has enhanced its credibility as a potential major future oil producing province. We feel that the persistent take over rumours are premature, but likely to be accurate in the longer term.

Catalysts The company is in the process of drilled several wells across it acreage, the results will provide the key share price drivers in 2012. The company has now opened the data room for the sale of its Akri-Bijeel asset for which we have a risked valuation of c.$200m. We estimate that this process could take up to three months to complete. Short term share price drivers are: well testing results from the Shaikan-4 well (due imminently) and the well result at the Ber Bahr-1 exploration well (due end of February/early March).

Valuation


£ million p/share

Production 268 31 Discovered 2C 2,708 317 Gross Value 2,975 348 Less: G&A (40) (5) Net Value 2,936 344 Net Cash 256 30 Target Market Cap/ Price 3,191 374 Source: Seymour Pierce Ltd

We have valued Gulf Keystone in terms of its discovered resource base under the low estimate scenario stated in the most recent CPR, and have not included estimates for yet-to-find resources. In addition, we have included a discounted cash flow (DCF) valuation of GKP’s current and forecast production (2012: c.10,000bopd ramping up to 2014: c.40,000bopd) from its Shaikan field in Kurdistan.


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Xcite Energy

Proposition In 2010, a mis-communicated reserve report, delayed clarity on funding against a backdrop of weak market conditions resulted in Xcite losing the majority of its 2010 share price gains. The rig on site awaiting delayed DECC approval and development drilling due to start in February, are we about to see resurgence in this stock? We think so, but it may prove to be another turbulent year for investors should initial drilling results fail to deliver.

Catalysts The company is awaiting overdue DECC approval for drilling to start as part of Phase 1A. Once this has been approved (which we assume in the very short term) the company can begin drilling the first batch of development wells at Bentley. This will provide the first significant share price driver for the company. The resultant well flow test results will then provide guidance as to the level of production we can expect from the field. It should also result in the conversion of contingent resources into reserves, which should also enhance valuation.

Valuation


NAV by activity £ million p / share

Confirmed CPR reserves/resources 822.4 227 Plus net (debt)/cash 30.78 15 Core NAV 853.2 242


We have based our valuation of Xcite solely on the company's latest Reserves Assessment Report (RAR) for the Bentley field.


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Top regions

We have identified three key regions which we believe are likely to see significant positive momentum in 2012

Kurdistan

Activity in Kurdistan has been steadily increasing in recent years with the entrance of several small and medium independent E&Ps. However, the region finally got the “seal of approval” following the announcement that ExxonMobil was to acquire significant acreage in six exploration blocks in late 2011. More recently, speculation has mounted that Total were planning a similar move, although this has yet to be formally announced.

Many commentators have suggested that the absence of the majors was due to fractious relationship between the Iraqi Central Government and the Kurdistan Regional Government. The absence of resolution on the new Iraqi oil laws (which were drafted in 2007) continues to hold back the region from making an impact on the export market and continues to prevent major capital investment in projects other than for licence acquisition and exploration.

Outlook The USGS has estimated that Kurdistan has c.40bn bbl of oil and c.60tcf of gas with low geological exploration risk. However, this attractiveness is countered by the high (and some would say increasing) geopolitical risk as well as tangible commercial risk should the issue surrounding the oil law not being resolved in the short to medium term.

The one key benefit of operating in Kurdistan versus the rest of Iraq is security. Kurdistan continues to be a much safer operating environment and has been one of the key drivers for investment in the region.

We believe that the increasing influx of foreign oil companies into Kurdistan and the increasing capital expenditure they bring is the most likely driver for resolution of the oil law. Increases in production outside Kurdistan have been disappointing so far and if Iraq is to see any tangible increase in production in the short to medium term we believe that this will come from Kurdistan.

Companies on our watchlist Gulf Keystone Petroleum has been a long term player in Kurdistan and has seen considerable exploration success so far. It has discovered c.15bn bbl of oil in place so far and continues to explore during 2012. The company is aiming for oil exports starting in 2013 and is seeking to develop an oil export pipeline to Kirkuk with a capacity of 440,000bopd. There has been considerable speculation that it is a takeover target ahead of moving into full scale commercial development. Price drivers in 2012 are likely to come from further resource upgrades and increases in production from Shaikan.

Heritage Oil & Gas has had a mixed experience in Kurdistan. Initially positive drilling results at the Miran West field, which was identified as an oil discovery, changed when follow up drilling discovered large quantities of gas instead. Heritage’s share price collapsed at this point and it has struggled to recover since. The company is examining options for gas export and continues to explore at Miran and positive results from this programme could boost the share price in 2012.

A recent and unexpected entrant is Afren, who made their first investment outside Africa last year. The company is targeting first oil from its assets in 2012 and this is likely to provide upside from this part of the portfolio in 2012. The company also has exploration planned in Kurdistan later this year.

We have identified three key regions which we

feel are likely to see significant positive

momentum in 2012.

The USGS has estimated that Kurdistan has

c.40bn bbl of oil and c.60tcf of gas with low

geological exploration risk.



East Africa

The highly competitive operating in western Africa and increasingly in central Africa has seen a migration of companies towards the east of the continent. As is typical for frontier regions, small E&Ps have made the initial exploration efforts to prove up resources. We have now entered the phase where successful explorers are attracting interest from larger independents as well as the majors.

Outlook We believe that 2012 will continue to see exploration success from the minor companies in the shallow water and hopefully in the deeper water from the new entrant majors. M&A on a greater scale is also likely to be a prominent feature. Cove Energy, for example has already put up the “for sale” sign and we can expect further consolidation in the region.

Exploration has tended to yield large gas discoveries in the shallow water blocks of a size which could potentially support a LNG development. However, given that the LNG market is oversupplied with more capacity due to come onstream in Australia and the Middle East, we see this a a longer term prospect than other commentators.

Companies on our watchlist Afren entered east Africa via its acquisition of Black Marlin. During 2011 the company has been working up these assets with a view to start exploration in 2012 and 2013. Afren’s strategy has mainly been on developing already discovered assets. It exploration exposure has been limited to date, but the company hopes to deliver 250mmbbl of 2P/2C resources over the next three years. East African exploration in 2012 will focus on Kenya and Tanzania.

Cove Energy recently put the for sale sign up following a very successful exploration campaign in recent years. This company is very likely to attract interest in the majors who are keen to potentially develop domestic and export gas projects in the region. Share price performance will continue to be driven by its drilling campaign, resource upgrades and potentially its acquisition.

North Sea – UK & Norway

The UK North Sea saw a record investment of £7.5bn in 2011, driven by high oil prices. This level of investment is forecast to continue until at least 2015. The emphasis of this investment was skewed towards development rather than exploration and appraisal which saw a decrease in activity. The sector also saw its most active period in terms of transactions since 2005, with c.$4bn of assets switching hands during the year. This is a trend which we expect to be a continuing theme as the region sees more consolidation, particularly amongst the smaller players.

Following the successes of Statoil, Xcite Energy and Nautical Petroleum in heavy oil, we would expect these types of projects to become more attractive throughout the region. The fiscal terms for such projects will also improve project commerciality and hopefully reduce the decline in oil production from the UK sector.

The Norway North Sea is seeing increased activity from a number of AIM listed E&P’s as they look to exploit the attractive fiscal terms offered by the Norwegian government. Currently, exploration companies will receive 78% of their drilling expenditure back the following year to facilitate further growth in the region. The state owned company, Petoro AS, is also undergoing transactions with foreign entities operating in the region to acquire previously undeveloped licences, thus stimulating future production from the region.

The highly competitive operating in western

Africa and increasingly in central Africa has seen

a migration of companies towards the east of

the continent.

The UK North Sea saw a record investment of

£7.5bn in 2011, driven by high oil prices. This

level of investment is forecast to continue until

at least 2015.



Companies on our watchlist Faroe Petroleum has a robust mix of production growth and high impact exploration, and continues to execute value accretive transactions on both sides of the Continental Shelf, most notably its recent asset swap with Petoro AS. The company has a strong balance sheet with sufficient cash reserves and debt facilities to fund its progressive drilling, appraisal and development activities.

Xcite Energy moves into the development phase this year which should yield production in 2Q onwards. However, we do anticipate a volatile period during the initial drilling phase as we see the initial drilling and flow test results being announced. There is a huge amount of expectation relating to conversion of resources to reserves.



Oil and gas price outlook for 2012

Geopolitics were a major price driver during 2011, as concerns driven by the Arab Spring caused concerns as to the stability of the Middle East and what this could mean for security of supply, particularly for Saudi Arabia and Iran. Despite not being a significant oil producer, Syria continues to cause instability in the region. Similarly, despite making progress Egypt has still not fully resolved its many issues and is likely to remain unstable until after the elections are concluded.

Iran’s commitment to its nuclear programme will continue to antagonise the West and remains a cause for concern. The recent sabre-rattling on the potential closure of the Straits of Hormuz seems to have just been posturing. However, the reality is that this major (a fifth if all traded oil passes through here) oil transit route for the region could be closed within a matter of hours. Although unlikely, an escalation like this would not only result in a major increase in the oil price, but could quickly escalate to another war in the Middle East.

Brent averaged $110/bbl in 2011 and we forecast the price to average $100/bbl in 2012.

Now that winter has finally arrived in Europe, we have seen the spot gas price increase by 30%, driven in part by Gazprom’s inability to increase supplies. Gazprom currently supplies c.25% of the European market, but its pricing is the highest at c.$410/mcm. Consequently it is seeing more competition from LNG and domestic sources of gas in some countries. Such an aggressive pricing structure has resulted in demands from gas users for Gazprom to move away from long-term contracts and increase the spot market contribution to such contracts.

The success of the shale gas industry in the US is has driven the gas price to a new low of c.$2.50/mcf. The success has been so large that the US may move back into gas exports rather than being a net importer. We are now seeing an increase in shale gas activity throughout Europe, particularly in Poland, and so far the results have been mixed. We are therefore comfortable that the gas price will remain high and that shale gas will have little impact on the supply/demand situation in the medium term.

Geopolitics were a major price driver during

2011, as concerns driven by the Arab Spring

The success of the shale gas industry in the US is

has driven the gas price to a new low of

c.$2.50/mcf.



Valuation methodology

Petroleum companies are valued in terms of their portfolio of exploration and production assets. Our overall target price comprises a core valuation for the producing and near term production assets and a risked net asset value (RENAV) for the exploration assets.

Exploration

Prior to drilling, a huge amount of work has been done to de-risk a prospect. We apply a simple arithmetic approach to attempt to value such prospects ahead of drilling. The calculation is:

RENAV = Gross resource estimate x Company Interest x Chance of Success x NPV/bbl

The company provides most of this data, the chance of success (CoS) is probably the most important factor and is very company and country specific. Some companies are better at exploration than others. Also, some countries have more hydrocarbons than others. The CoS tends to be higher in mature exploration than in frontier regions. The NPV per barrel varies from country to country and reflects the prevailing fiscal terms and transaction values on a per barrel basis.

Production

We write an operational model for the company’s producing assets. This reflects historic data and our assumptions for the future. We model production, prices and costs and overlay the fiscal terms of the country where the asset is located. From this model we derive a DCF which is then used to value the asset. See the valuation section for the assumptions used for this company.

Resource Classification Framework

Source: SPE

We write an operational model for the

company’s producing assets. This reflects

historic data and our assumptions for the future.



Let it flow 2011 was a disappointing year for Aurelian, with its key asset Siekierki representing a much larger and complex challenge than initially anticipated. Following a comprehensive review, the company has provided the market with a clear strategy to develop its entire portfolio, which we feel represents a strong buying opportunity for investors, given current trading levels.

Strategy shift Aurelian has now concluded a comprehensive review of its assets following the disappointing multi-fracced horizontal appraisal wells drilled in 2011. The data acquired during the appraisal phase has improved the company’s understanding of Siekierki, and as such, a revised development plan has been designed comprising 32 wells recovering 296bcf of gas (previously 348bcf) to commence in 4Q 2012.

Near-term exploration programme Aurelian plans to take advantage of the flexibility in its work programme and preserve capital by prioritising its exploration targets. In line with the strategic review, the company has deferred several exploration targets, to focus instead on near-term value play unlocking wells. The programme is budgeted to cost €25.6m net to Aurelian targeting 67.3mmboe of net unrisked prospective resources, which, while less than previously indicated, potentially offers material upside.

Unlocking Siekierki The company intends to enter into negotiations for a potential farm-in to its 90% interest in Siekierki. The asset is surrounded by IOC operated acreage, most notably Connoco Phillips, Exxon Mobil, Total and Chevron, all of which have the technological knowledge base and financial backing that is required to fully develop the project. We feel that a farm-in partner of sufficient expertise and financial resource base will act as a positive share price trigger for investors in Aurelian.

Valuation and recommendation Our core valuation comprises exploration and development activities, and cash; which yields a base value of 20p. Our exploration upside assessment contributes a further 10.8p. On this basis we initiate coverage with a BUY recommendation and set a price target of 31p.

1 Please see regulatory disclosure notes at the end of this document

A draft of this research has been shown to the company following which minor factual amendments have been made.

10 February 12 | Initiation of coverage | Oil & Gas exploration and production

Aurelian Oil & Gas ( AIM:AUL)F

BUY Share price 17p

Target price 31p 84% Upside

Market cap (£m) 82.8

Net cash (£m) 80.0

Enterprise value^ (£m) 82.8

No. of shares (m) 494.3

Average daily vol ('000, -3m) 3,488

Dividend yield (%) 0.0

PER at Target price (Y1) 147.2

12 month high/low (p) 92/16

(%) 1m 3m 12m

Absolute -2.9 -27.2 -79.3

FTA relative -6.9 -31.9 -78.9

Price & price relative (-2yr)

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Share price as at close: 9 February 12

Next news Operational updates

Business Exploration in Central Europe with licences in

Poland, Slovakia, Romania and Bulgaria

www.aurelianoil.com

Year end December

Revenue(€m)

EBIT*(€m)

PBT*(€m)

Tax(%)

Adj. EPS* (c)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 0.0 (1.9) (2.3) 0.0 (0.2) (88.1) (51.8) 0.02010A 0.0 (9.0) (9.7) 0.0 (4.9) (4.0) (11.0) 0.02011E 0.0 1.3 2.5 0.0 0.2 80.1 76.4 0.02012E 0.0 (5.3) (4.5) 0.0 (0.9) (21.7) (18.7) 0.02013E 0.0 (0.1) 0.4 0.0 0.1 261.4 (985.9) 0.0

* excludes exceptional items and amortisation of acquired intangibles.

^ EV calculation adjusted for core cash, investments etc.



Sam Wahab ACA Research Analyst +44 (0) 20 7107 8094 [email protected]



Valuation and recommendation

We value Aurelian on its core exploration and development assets in Poland, Slovakia, Romania and Bulgaria. The company has a clear development plan to bring their key asset, Siekierki, to first stage production in 2016 (delayed by three years due to technical issues experienced during flow testing in March and September 2011). However, this development plan will require additional financial and technological resources through a potential farm-out down. On this basis, we do not currently provide a valuation of future discounted cash flows arising from Siekierki in 2016, until the company has adequate resources in place to fulfil their strategy.

Our valuation incorporates the following assumptions:

Valuation assumptions

Metric Assumption

NPV/boe - Oil $5/boe NPV/boe - Gas $3/boe Realised gas price $7.5/mcf Long-term $/£ 1.65 Long-term $/€ 1.39 Long-term £/€ 1.16 Discount rate 10% Shares outstanding (million) 500.8


These assumptions have been implemented into our risked exploration net asset valuation as follows:

Risked net asset valuation

Status Country Project Interest CoS/CoD Resources (mmboe)

NPV 10% US$ / boe

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Gross Net Development Poland Siekierki 90.00% 25% 49.30 44.37 3 133.11 33.28 81 20.17 4.0 Exploration Poland Siekierki NW 90.00% 20% 11.5 10.35 3 31.05 6.21 18.82 3.76 0.8 Exploration Poland Siekierki SW 90.00% 20% 3.3 2.97 3 8.91 1.78 5.40 1.08 0.2 Exploration Poland Kalisz 50.00% 10% 5.3 2.65 3 7.95 0.80 4.82 0.48 0.1 Exploration Poland Cyb. & Ty. 45.00% 10% 97 43.65 5 218.25 21.83 132.27 13.23 2.6 Exploration Poland Bieszczady 25.00% 10% 272.8 68.2 5 341.00 34.10 206.67 20.67 4.1 Exploration Poland Karpaty East 80.00% 10% 28 22.4 3 67.20 6.72 40.73 4.07 0.8 Exploration Poland Karpaty West 60.00% 10% 19 11.4 3 34.20 3.42 20.73 2.07 0.4 Exploration Poland Wetlina 100.00% 10% 31.6 31.6 5 158.00 15.80 95.76 9.58 1.9 Exploration Slovakia Svidnik 50.00% 10% 180.2 90.1 3 270.30 27.03 163.82 16.38 3.3 Exploration Romania Brodina 33.75% 10% 50 16.875 5 84.38 8.44 51.14 5.11 1.0 Exploration Romania Cuejdiu 45.00% 10% 16 7.2 5 36.00 3.60 21.82 2.18 0.4 Exploration Romania Brodina 33.75% 10% 8 2.7 3 8.10 0.81 4.91 0.49 0.1 Exploration Bulgaria Golitza Block 30.00% 10% 12 3.6 3 10.80 1.08 6.55 0.65 0.1

784.00 358.07 1,409.25 164.89 854.09 99.93 20.0 Source: Seymour Pierce Ltd

We value Aurelian on its core exploration and

development assets in Poland, Slovakia,

Romania and Bulgaria.




£ million p/share

Siekierki (Development) 20.2 4.0 Siekierki (Exploration) 4.8 1.0 Other Polish exploration 50.1 10.0 Slovakia exploration 16.4 3.3 Romania exploration 8.4 1.7 Gross Value 99.9 20.0 Net Cash 54.2 10.8 Target Market Cap 154.1 30.8 Source: Seymour Pierce Ltd


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Recommendation and target price

Our gross valuation comprising exploration and development activities yields a base value of 20p, whilst net cash adds a further 10.8p/share. In our view, Aurelian is severely undervalued and is currently trading well below its core value.

On this basis we initiate coverage with a Buy recommendation and set a price target of 31p.

In our view, Aurelian is severely undervalued and

is currently trading well below its core value.



Strategic overview

Aurelian has now concluded a comprehensive review of its assets following the disappointing multi-fracced horizontal appraisal wells drilled in 2011. The company arrived at three key conclusions which we have analysed in detail to support our investment case:

Siekierki is an attractive project and initial problems are now well understood and a clear plan forward has been developed.

The cash position at the year-end 2011 was €63m which allows the company to carry out its planned exploration and appraisal activities for the next 18 months.

Unlocking the full upside within the company is likely to require additional technical and financial resources.

We feel that it is important to analyse these three conclusions in detail to address existing shareholder concerns, as well as to illustrate to potential shareholders the possible upside arising on successful development of Aurelian’s acreage in central Europe.

How attractive is Siekierki now?

The well tests on Siekierki have been completed and incorporated in a comprehensive technical and commercial review led by a group of independent consultants (AGR-TRACS). From this, gas initially in place of 1.1tcf is now estimated in Block 207 (company guidance prior to appraisal was 1.6tcf). However, we do highlight that this does not include gas potentially in Blocks 206 and 208 or the Krzesinki discovery.

Siekierki location map

Source: Company

Following the strategy update and conference call, we feel it is clear that the data acquired during the appraisal phase has improved the company’s understanding of Siekierki, and the company has now constructed a new reservoir model. The new model now illustrates that the layered Rotliegendes sandstone sequence in Siekierki has a wide range of ambient porosity and permeability properties spanning 6-18%, with higher permeability layers dominating well performance.

The company also maintains that the Krzesinki-1 well test result supports Aurelian’s new reservoir model, in terms of the presence of higher porosity zones within the gas

The well tests on Siekierki have been completed and incorporated in a comprehensive technical and commercial review led by a group of independent consultants



legs of the Krzesinki and Siekierki fields, with an un-fracced well test producing 0.2mmscf/d. This represents the first successful un-stimulated gas well flow test on Block 207 to date.

As such, a revised development plan (see forward plan section) has been designed, comprising 32 wells recovering 296bcf of gas (previously 348bcf), indicating an average recovery of 9.25bcf/well. To support these estimates, the company intends to release an updated CPR covering both appraisal and exploration assets in March/April 2012.

Nevertheless, following the comprehensive technical and commercial review supported by AGR-TRACS and the new reservoir model, the company maintains that Siekierki is an attractive project which offers material upside to investors.

Funded exploration programme

Aurelian plans to take advantage of the flexibility in its work programme and preserve capital by prioritising its exploration targets. In line with the strategic review, the company has deferred several exploration targets, to focus instead on near-term value play unlocking wells.

Aurelian will initially drill the Sosna-1 well within the Torzym reef oil play in March 2012 targeting up to 35mmbbls gross. In addition, the company intends to undertake further geological and geophysical surveys to de-risk the prospects identified in their 2011 seismic data including Cybinka-Torzym , Slovakia and Romania (Brodina).

The high impact Carpathian well drilling campaign will now be deferred to Q4 of this year. This will include Kaparty East, which the company now believe to be gas rather than oil with internal estimates suggesting a recoverable resource of 170bcf, representing an additional 1p/share of our risked target valuation.

2012 drilling programme

Well Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec WI Max Cap (€m) Target mmboe p/shareKrzesinki-1 90% n/a n/a n/aNiebieszczany-1 25% n/a n/a n/aSosna-1 45% 2.6 3.1 0.4Cierne-1 50% 6.4 19.4 1.4Bieszczady-2 25% 3.7 23.1 2.8Kaparty E-1 80% 10.2 14.5 1.1Cuejdiu-1 45% 2.7 7.2 0.9

RotliegendesZechstein Reef Oil PlayCarpathian Thrust fold Belt

Source: Seymour Pierce Ltd, Company

In addition to the above five wells, four contingent wells are also being considered for Aurelian’s 2013 drilling schedule.

The programme is budgeted to cost €25.6m net to Aurelian although it aims to reduce this by bringing in partners to the Romanian, Slovakian and Karpaty East & West licences. In aggregate, the five wells are targeting 67.3mmboe of net unrisked prospective resources, which while less than previously indicated, offers material upside potential.

Unlocking the full value of the company

Analysis of Trzek-2 and Trzek-3 Aurelian’s share price has been severely impacted by the two multi-fracced horizontal wells drilled in 2011. The company has reviewed the data from these wells to implement a comprehensive plan to develop the asset using cost efficient and technologically advantageous methods.

Aurelian plans to take advantage of the flexibility

in its work programme and preserve capital by

prioritising its exploration targets.



Aurelian has confirmed that the Trzek-2 horizontal well had mechanical issues with the completion which reduced fracture effectiveness; whilst the Trzek-3 well was mechanically well executed with better completion. However, the hydraulic fractures were not fully effective and the well bore did not make contact with the high permeability zone encountered in the pilot hole. As such, the combination of the reservoir’s permeability to gas and water, and the poor frac effectiveness explains why the Trzek-2 and Trzek-3 flow rates of 3mmscfd and 3.2mmscfd were significantly lower than expectations.

Subsequent geological and geophysical analysis of the wells have provided Aurelian with a comprehensive understanding of the geology of Siekierki. This is best illustrated through their pre and post drill knowledge conceptual knowledge of the basin.

Pre and post drill understanding Aurelian’s pre-drill strategy understood that the multi-frac horizontal well would produce dry gas when fracced above the free water level.

Pre-drill concept

Source: Company

This was supported by the belief that Siekierki was a tight reservoir with moderate variation porosity. However, subsequent analysis has confirmed that the tight reservoir contains zones of significantly higher permeability and a much larger variation in porosity. In addition, gas is produced with water as relative permeability effects are important.

Post-drill concept

Source: Company



From the above illustrations, we note that Siekierki is very different geologically from the company’s original assumption. That assumption had only moderate variation in porosity and permeability in the tight aeolian sandstone matrix Aurelian now understands that the reservoir has streaks of higher permeability (yellow in the diagram) within that tight matrix, which will dominate well performance On this basis, management’s expectations of GIIP has been reduced by c.31% to 1.1tcf (previously 1.6tcf), however, the company re-iterates that the multi-fracced horizontal wells implemented continues to be the correct technology application for the field and significant operational lessons and insights have been learnt.

Forward development plan Aurelian will now seek to implement the next stage of its development plan to achieve first gas sales in 2016This will initially involve the continuation of long-term testing of Trzek-2 and Trzek-3 and commercialising gas from these two wells using a low pressure and low methane tie-in, as well as a gas to wire option as a smaller pilot development. First gas arising from this is expected to be achieve in 4Q 2013 costing in the region of €12m net to Aurelian.

Development plan to 2016

Source: Company

The above development plan will also incorporate a potential farm-in partner to the Siekierki license. The company currently holds a 90% working interest in the block, which is surrounded by IOC operated acreage, most notably Connoco Phillips, Exxon Mobil, Total and Chevron, whom all have the technological knowledge base and financial backing that is required to fully develop the Siekierki project.

In our view, a substantial farm-down of Siekierki would have always been an attractive proposition for Aurelian even if the company had successfully flowed commercial volumes of gas in 2011. The key difference in undertaking one now is that the company has not proved up as much value of the asset as it would have liked and in effect, its hand is being forced through a lack of financial resources.

Nevertheless, we feel that the introduction of an experienced farm-in partner in the near term would be a strong share price trigger for investors, given the improved technological understanding of the asset achieved through extensive data analysis.

Aurelian will now seek to implement the next

stage of its development plan to achieve first gas

sales in 2016.



Key assets

Core area 1

Poznan The Siekierki field was originally discovered over 40 years ago close to the city of Poznan, but the tight reservoir was found to exhibit low porosity and permeability, which meant commercial flow rates could not be achieved with the technology available at the time. Aurelian was awarded the Poznan East licence in 2003 and drilled the Trzek-1 well in 2007 to appraise the field, confirming the original findings but providing improved quality reservoir data using modern technologies. Significantly, the well flowed at an initial 7.5mmcfd before being choked back to a stable 2.5mmcfd. Aurelian’s latest CPR estimates 640bcf net to the company on a mid-case scenario (including Siekierki SW and Siekierki NW) representing this largest asset, by confirmed resources, in the company’s portfolio.

Poznan blocks

Source: Company

Cybinka and Torzym These fields are located nearby to the German border and were acquired in 2008. They link to recent oil discoveries in the north, and the basin extends from the prolific UK North Sea. Existing data is being evaluated and has been followed by 3D seismic. The combined volume of hydrocarbons net to Aurelian is 34mmbbls and the company anticipates starting drilling in Q4 2011.

Cybinka & Torzym

Source: Company



Core area 2

Aurelian has continued to develop its second Core Area and has executed its strategy of applying modern 2D seismic to explore thrust fold areas. During 2010, the company successfully acquired 776km of 2D seismic across its acreage here.

Bieszczady

In the Polish Carpathians, the first of a three well programme in the company’s Bieszczady concession, Niebieszczany-1, was spudded in October 2010. The well is being drilled to target depth of 4,800 metres targeting an oil prospect of up to 100mmbbls (gross). A number of reservoirs, all of which are proven producers in the region, are being targeted by this well and there are several other similar-sized prospects on trend, which would be de-risked in the event of a successful outcome. Using existing 2D seismic data covering approximately 20% of the concession area, prospects totaling up to 680m barrels of un-risked prospective resources have been mapped. The acquisition phase of a second 300km 2D survey covering a further 20% of the concession size was completed in March 2011. The future work programme for the concession is to complete the processing and interpretation of this second 2D survey, and then, following the drilling and testing of Niebieszczany-1 and the reprocessing of the first 2D survey, prepare a revised prospect inventory and drill two further wells.

Kaparty

At East Karpaty, the acquisition of 136km of 2D seismic has been completed. This survey will cover approximately 25% of the concession and the results of the survey are expected later this year. A two well, fully-funded programme is planned for the concession, with the wells being targeted for late 2011 and 2012. It is also anticipated that the company will seek further farm-outs on this acreage, after the drilling of the first or second well in the programme. Also, in the Polish Carpathians Aurelian has been awarded a 100% interest in the Poreba concession which is adjacent to the West Karpaty concession. This new concession gives the company additional scale and prospectivity to launch a new Carpathian Conventional Gas business covering 2,562km2, which will target shallow gas to potentially commercialise quickly. In addition, Aurelian’s Lachowice Gas project on the West Karpaty concession is its first project in this new business where it will carry out a relatively low cost “work over” process targeting a prospect of 20bcf (gross) and target first gas by the end of 2012.



Financial model

Income Statement

Year end December (€m)

2009A 2010A 2011E

Group revenue 0.0 0.0 0.0Cost of sales 0.0 0.0 0.0Gross profit 0.0 0.0 0.0Total operating expenses (1.9) (9.0) (5.6)EBIT (1.9) (9.0) (5.6)Net interest/financial income/(cost) (2.3) (9.7) 2.5Associate and Other non-op. income/(cost) (0.4) (0.7) 1.2PBT (2.3) (9.7) 2.5Tax 0.0 0.0 0.0Effective tax rate (%) 0.0 0.0 0.0Minorities 0.0 0.0 0.0Earnings (0.4) (16.9) 1.2 EBITDA (0.4) (8.1) (4.1)Adjusted EBITDA* (0.4) (8.1) 2.7Adjusted EBIT* (1.9) (9.0) 1.3Adjusted PBT* (2.3) (9.7) 2.5Adjusted earnings* (0.4) (16.9) 1.2 DPS (c) 0.0 0.0 0.0EPS (c) (0.2) (4.9) 0.2EPS [F. Dil.] (c) (0.2) (4.9) 0.2EPS [Adj.]* (c) (0.2) (4.9) 0.2EPS [Adj. F. Dil.]* (c) (0.2) (4.9) 0.2Weighted average no. shares (m) 189.5 341.7 490.2Fully dil. w. ave. no. shares (m) 189.5 341.7 500.8Year end no. shares (m) 189.5 341.7 490.2


Source: Company data, Seymour Pierce Ltd



Cashflow Statement


2009A 2010A 2011E

Operating income (1.9) (9.0) (5.6)Amortisation of acquired intangibles 0.0 0.0 0.0Amortisation of other intangibles 0.0 0.0 0.0Depreciation 1.5 0.9 1.5Net change in working capital 1.2 (5.7) (0.6)Other 0.0 7.8 0.2Operating cash flow 0.8 (6.0) (4.5) Capital expenditure (8.5) (20.3) (62.3)Investment in Other intangibles 0.0 0.0 0.0Net interest/financial income/(cost) 0.4 0.7 (1.2)Tax paid (0.0) (0.0) 0.0Net acqns./disposals 0.0 0.0 0.0Dividend paid 0.0 0.0 0.0Other (0.0) 0.2 0.1Cash flow before financing (7.3) (25.4) (67.9) Proceeds from shares issued 12.8 132.4 2.5Investments 0.0 0.0 0.0Other 0.0 0.0 0.0Net movement in cash/(debt) 5.5 107.0 (65.4) Opening net cash/(debt) 6.0 14.0 114.7Adjustments (Forex, etc.) 0.0 0.0 0.0Closing net cash/(debt) 14.0 114.7 63.3 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E

Property plant and equipment 5.0 0.2 0.0Goodwill and Acquired intangibles 0.0 0.0 0.0Other intangibles 0.0 0.0 0.0Other fixed assets 40.2 56.5 117.0Non current assets 45.2 56.7 117.0 Stocks & WIP 0.0 0.0 0.0Trade receivables 4.7 11.0 10.1Cash 14.0 114.7 63.3Other current assets 0.0 9.0 0.0Current assets 18.6 134.7 73.5 Total assets 63.9 191.4 190.5 Trade creditors 3.4 13.2 11.9Short term borrowings 0.6 1.2 0.0Long term borrowings 1.6 0.0 0.0Other liabilities 0.0 2.0 0.0Total liabilities 5.7 16.4 11.9 Net assets 58.2 175.1 178.6 Issued share capital 15.5 30.4 30.7Share premium account 65.9 183.4 185.2Retained earnings (15.8) (32.7) (31.4)Other reserves (7.4) (6.0) (5.9)Minority interests 0.0 0.0 0.0Total equity 58.2 175.1 178.6




Target Price & Recommendation History

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Feb 10 Apr 10 Jun 10 Aug 10 Oct 10 Dec 10 Feb 11 Apr 11 Jun 11 Aug 11 Oct 11 Dec 11 Feb 12

Share Price Target Price Recommendations

Source: Datastream, Seymour Pierce Ltd


A natural selection

2011 was the turn of the northern players (RKH & DES) and in 2012 the activity heads south with both BOR & FOGL drilling. Whilst these companies share common issues such as regional politics, BOR stands out amongst its peers in terms of the potential size of its drilling targets as well as the expertise of its management team.

Drilling is underway – high risk, but potentially high reward The Leiv Eiriksson rig started drilling at the beginning of February and will drill the Darwin and Stebbing prospects before moving on two drill two wells for FOGL. Darwin and Stebbing will test two different play types, therefore success or failure at Darwin means nothing for Stebbing. Darwin and Stebbing have 15% and 10% chances of success respectively and each have billion barrel potential. Assets of this sort of size drive development and attract buyers.

Drilling success does not equal commerciality – a long way to go Rockhopper's success at Sea Lion has led the company and some commentators to discuss the field’s commerciality. We acknowledge that it is a large field, which if located in many locations would be easy to develop. However, the geopolitics and absence of infrastructure may yet prove too much to overcome. Argentina’s escalating use of regional and international politics has been a smart move and should not be underestimated when investors are thinking about development options and potential asset sales.

Valuation and recommendation Our core valuation comprises three elements – near term exploration at Darwin 46p; and at Stebbing 53p; and the pre-drill cash (c.$192m on 31/12/11) per share which contributes 27p. This cash component will obviously decrease significantly post drilling which we estimate will cost c.$150m. We initiate coverage with a Buy recommendation and set a pre-drill target price of 126p.

However, given the market’s reactions to both Rockhopper and Desire’s news flow last year, Borders looks likely to have a very volatile ride during drilling. We would therefore advise investors to have a pro-active response to their position rather than riding out the inevitable peaks and troughs.



Borders & Southern Petroleum(LSE:BOR)5

BUY Share price 67p



Net cash (£m) 102.3





(%) 1m 3m 12m

Absolute -5.9 +18.5 +3.5

FTA relative -9.8 +10.9 +5.2


30405060708090

100


Price Relative

Source: Datastream


Next news FY Results

Business Oil exploration focusing on frontier or emerging

basins where there is potential to identify and

commercialise high value prospects.

www.bordersandsouthern.com/



Year end December

Revenue($m)

EBIT*($m)

PBT*($m)

Tax(%)

Adj. EPS* (c)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 0.0 (1.2) 3.2 0.0 1.5 69.1 (243.2) 0.02010A 0.0 (1.5) (0.2) 0.0 (0.0) (2,755.4) (195.6) 0.02011E 0.0 (1.9) 1.3 36.4 0.2 563.9 (152.3) 0.0





Borders & Southern Petroleum | 10 February 12 Valuation and recommendation


We have valued Borders in terms of a risked exploration net asset appraisal of their near term assets. The company intends to drill two wells in Q1 2012 (Darwin and Stebbing), and we feel it is appropriate to value it on this basis. We have incorporated the following assumptions into our valuation:


Metric Assumption

Long term $/£ exchange rate 1.65 Discount rate 10% Darwin CoS 15% Stebbing CoS 10% NPV/bbl ($) - Oil 7.50 NPV/bbl ($) - Gas 2.00


We have valued Borders in terms of its confirmed resources as per the Competent Persons Report, issued in May 2005 by Scott Pickford Ltd for Darwin and Stebbing using the low case scenario.

Potential resources at Darwin

Recoverable resources (mmboe)

Prospect Target P90 P50 P10 CoS Darwin (base) Anomaly 230 300 380 15% Darwin (upside) To spill point 580 760 980 15% Total 810 1,060 1,360

Source: Scott Pickford

Potential resources at Stebbing

Recoverable resources (mmboe)

Prospect Target P90 P50 P10 CoS Stebbing (base) Tertiary 390 710 1,120 10% Stebbing (upside) Upper Cretaceous 410 570 930 10% Total 800 1,280 2,050

Source: Scott Pickford


P90 - Low case NPV/bbl Darwin Stebbing Total NPV/shr (p)

Oil 7.5 $259 $293 $551 78 Gas 2.0 $69 $82 $151 21 P90 - High case NPV/bbl Darwin Stebbing Total NPV/shr (p) Oil 7.5 $653 $600 $1,253 177 Gas 2.0 $174 $160 $334 47 P10 - High case NPV/bbl Darwin Stebbing Total NPV/shr (p) Oil 7.5 $1,103 $1,538 $2,640 373 Gas 2.0 $294 $410 $704 100


In our view, it is prudent to assume a low case in our valuation given that this basin has not been drilled previously and exploration in the Falklands overall is still at a fairly early stage.

We have valued Borders in terms of a risked

exploration net asset appraisal of their near term

assets.


Valuation and recommendation Borders & Southern Petroleum | 10 February 12


NAV £m p/share

Darwin 199 46 Stebbing 227 53 Net cash 116 27 Core value 542 126



27

46

53

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Net Cash Darwin Stebbing

p/sh

are



Our core valuation comprises three elements – near term exploration at Darwin 46p; and at Stebbing 53p; and the pre-drill cash ($194m on 31/12/11) per share which contributes 27p. This cash component will obviously decrease significantly post drilling which we estimate will cost c.$150m. We initiate coverage with a Buy recommendation and set a pre-drill target price of 126p.

However, given the market’s reactions to both Rockhopper and Desire’s news flow last year, Borders looks likely to have a very volatile ride during drilling. We would therefore advise investors to have a pro-active response to their position rather than riding out the inevitable peaks and troughs.

We would therefore advise investors to have a

pro-active response to their position rather than

riding out the inevitable peaks and troughs.


Borders & Southern Petroleum | 10 February 12 Asset overview

Asset overview

Borders has a 100% interest and is operator of five Production Licences which cover c.20,000km2 of the South Falkland Basin. The acreage is located approximately 150km south-east of the Islands and were awarded on 1 November 2004.

Southern Falklands Basin

The basin has had only one unsuccessful well test, but the geology and stratigraphy in Borders’ acreage is expected to be similar to the adjacent Magallanes and Malvinas sub-basins located to the west of the Falkland Islands. These sub-basins have been proven to have working petroleum systems. It is also anticipated to be similar to geology recorded in DSDP boreholes 511 and 330 drilled to the east of the Falkland Islands in the Falkland Plateau sub-basin.

This regional geological data helps provide a high degree of confidence on the occurrence of a good oil prone source rock. Late Jurassic to Aptian aged organic rich shales have been well documented both to the east and west of Borders & Southern’s acreage. Further afield the source rocks are noted off the coast of South Africa and the Antarctic peninsula. This indicates that the source rock is regionally extensive and therefore likely to be present within the Company’s licensed area.

Falkland Islands drilling prospects

Source: Company data

Drilling strategy

Borders will test the hydrocarbon potential to the east–west trending fold belt c.150km to the south of the Falklands. This fold belt trend contains numerous large simple structures (up to 150km2 in area), including thrust cored anticlines and tilted fault blocks. The definition of these structures has been achieved by acquiring 2,862km of 2D seismic and 1,492km2 of 3D seismic - this was in excess of the licence obligations.

The 3D seismic data has identified potential reservoirs in the Tertiary, Upper Cretaceous and Lower Cretaceous as well as the presence of a working hydrocarbon system.

Borders will drill the Darwin prospect first, then Stebbing. These first two prospects are geologically independent, other than they require the same source rock to be present. Therefore, success (or failure) at the first well will therefore have no impact


Asset overview Borders & Southern Petroleum | 10 February 12

on the second. Depending on the outcomes, the company has multiple follow up prospects which it can drill. These include look-a-like folds and tilted fault blocks and also alternative play types such as stratigraphically trapped basin floor fans.

Cross section of the Darwin and Stebbing prospects


Rig mobilisation - Leiv Eiriksson

The Leiv Eiriksson rig will arrive in late January and is a fifth generation semi-submersible drilling rig, and can drill in water depth down to 3,000m. Given the possible weather and sea conditions, the rig remains stable due to its advanced dynamic positioning system. This should reduce the risk of weather delays. However, analysis suggests that the South East Falklands actually has less volatile conditions than comparable oil regions.

Comparison of offshore wave conditions

0

2

4

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8

10

12

14

16

Winter Spring Summer Autumn

Sign

ifica

nt w

ave

heig

ht (m

etre

s)

West of Shetlands Central North Sea SE Falklands

Source: FOGL

The rig can operate year-round in harsh weather environments (e.g. offshore Canada, northern Norway) and prior to mobilising to the Falklands had been used in Greenland for Cairn Energy. The combined two well programme is estimated to last approximately 90 days (depending on potential well tests), after which the rig will move drill two wells for Falkland Oil and Gas. Borders and FOGL are working together sharing resources where possible to reduce costs for both companies.


Borders & Southern Petroleum | 10 February 12 Asset overview

Fiscal regime

The Falkland Islands have Concession (i.e. tax and royalty) Fiscal Terms. These high level terms are:

• A variable acreage rental

• 9% royalty on production

• 26% corporation tax on profits

This results in an effective government take of c.33%, which is one of the most favourable regimes globally.

Global Government takes

23%

33%

43%

51%

52%

53%

55%

57%

62%

70%

73%

73%

74%

76%

76%

78%

78%

81%

85%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

French Guiana

Falkland Islands

US Gulf of Mexico

Ghana

Colombia

Brazil

Mauritania

China

UK (Non PRT)

Nigeria

Indonesia

Trinidad and Tobago

Gabon

Uganda

DRC

Angola

Norway

UK (PRT)

Malaysia

Source: Wood Macenzie


Financial model Borders & Southern Petroleum | 10 February 12

Financial model

Income Statement

Year end December ($m)

2009A 2010A 2011E

Group revenue 0.0 0.0 0.0Cost of sales 0.0 0.0 0.0Gross profit 0.0 0.0 0.0Total operating expenses (1.2) (1.5) (1.9)EBIT (1.2) (1.5) (1.9)Net interest/financial income/(cost) 4.4 1.3 3.2Associate and Other non-op. income/(cost) 0.0 0.0 0.0PBT 3.2 (0.2) 1.3Tax 0.0 0.0 (0.5)Effective tax rate (%) 0.0 0.0 36.4Minorities 0.0 0.0 0.0Earnings 3.2 (0.2) 0.8 EBITDA (1.2) (1.5) (1.9)Adjusted EBITDA* (1.2) (1.5) (1.9)Adjusted EBIT* (1.2) (1.5) (1.9)Adjusted PBT* 3.2 (0.2) 1.3Adjusted earnings* 3.2 (0.2) 0.8 DPS (c) 0.0 0.0 0.0EPS (c) 1.5 (0.0) 0.2EPS [F. Dil.] (c) 1.5 (0.0) 0.2EPS [Adj.]* (c) 1.5 (0.0) 0.2EPS [Adj. F. Dil.]* (c) 1.5 (0.0) 0.2Weighted average no. shares (m) 204.6 428.6 428.6Fully dil. w. ave. no. shares (m) 204.6 428.6 428.6Year end no. shares (m) 204.6 428.6 428.6




Borders & Southern Petroleum | 10 February 12 Financial model

Cashflow Statement


2009A 2010A 2011E

Operating income (1.2) (1.5) (1.9)Amortisation of acquired intangibles 0.0 0.0 0.0Amortisation of other intangibles 0.0 0.0 0.0Depreciation 0.0 0.0 0.0Net change in working capital 0.1 (1.8) 4.1Other 0.0 0.0 0.0Operating cash flow (1.1) (3.3) 2.2 Capital expenditure 9.4 (10.5) (6.4)Investment in Other intangibles 0.0 0.0 0.0Net interest/financial income/(cost) 4.4 1.3 3.2Tax paid 0.0 0.0 (0.5)Net acqns./disposals 9.7 (10.0) (6.0)Dividend paid 0.0 0.0 0.0Other (0.0) (0.0) 0.0Cash flow before financing 22.3 (22.4) (7.5) Proceeds from shares issued 183.9 0.0 0.0Investments 0.0 0.0 0.0Other 0.0 0.0 0.0Net movement in cash/(debt) 206.2 (22.4) (7.5) Opening net cash/(debt) 9.5 206.3 194.1Adjustments (Forex, etc.) (0.2) 0.8 1.5Closing net cash/(debt) 206.3 194.1 192.1 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E

Property plant and equipment 0.0 0.0 0.0Goodwill and Acquired intangibles 0.0 0.0 0.0Other intangibles 36.6 37.7 44.1Other fixed assets 0.0 0.0 0.0Non current assets 36.6 37.7 44.2 Stocks & WIP 0.0 0.0 0.0Trade receivables 0.1 11.3 9.9Cash 206.3 194.1 192.1Other current assets 0.0 0.0 0.0Current assets 206.4 205.4 202.0 Total assets 243.1 243.2 246.1 Trade creditors 0.2 0.3 2.4Short term borrowings 0.0 0.0 0.0Long term borrowings 0.0 0.0 0.0Other liabilities 0.0 0.0 0.1Total liabilities 0.2 0.3 2.6 Net assets 242.8 242.9 243.6 Issued share capital 7.7 7.7 7.7Share premium account 238.0 238.0 238.0Retained earnings (3.2) (3.4) (2.6)Other reserves 0.4 0.6 0.5Minority interests 0.0 0.0 0.0Total equity 242.8 242.9 243.6



Financial model Borders & Southern Petroleum | 10 February 12


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Financial model Chariot Oil & Gas | 10 February 12

Swing low?

2012 may prove to be a pivotal year for Chariot as the company looks to probe its substantial resource base with the first of its two well programme commencing in Q2. Namibia is under-explored and has proven to be gas prone so far. Also the company does not currently have the financial flexibility to weather the capital requirements of unsuccessful drilling.

Namibia – large fan base, but few results Namibia remains hugely under-explored due to a legacy of exploration and political history. The country’s offshore blocks have recently come into focus due to surrounding geology and prospectivity, yet continued exploration and subsequent appraisal in such a frontier region will require sufficient capital that exceeds Chariot’s capabilities.

Two year strategy Chariot maintains a strategy of drilling four to five wells through to the end of 2013 - however we feel this will largely depend on successful drilling at the company’s first two wells (Tapir South and Nimrod). As such, 2012 will prove to be the pivotal year for the company with an exploration well in each of their Northern and Southern blocks expected – despite issues in obtaining a rig at present. It is on this basis that we feel it would be rash to provide value for the company’s subsequent assets at present.

Resource upgrades – but not driven by drilling 2011 saw the company increase its resource base by a further 40% to 14bnbbls of gross unrisked prospective resources. Nevertheless, we feel that Chariot must now focus its efforts on exploiting these resources rather than seeking further upgrades. By comparison GKP (BUY TP 374p) has upgraded its resource base post drilling.

Valuation and recommendation Our SOTP valuation is based on a risked assessment of Chariot’s first two exploration targets, given that at present, the company only has sufficient funds to drill these two wells. Our valuation illustrates that Chariot is currently overvalued as the market seems to be attributing value to its remaining portfolio prior to successful initial drilling. We initiate coverage with a Sell recommendation and set a pre-drill target price of 75p – representing c.41% downside risk.



Chariot Oil & Gas ( AIM: CHAR)

SELL Share price 126p

Target price 75p 41% Downside


Net cash (£m) 10.3





(%) 1m 3m 12m

Absolute +21.2 -6.3 -48.1

FTA relative +16.2 -12.4 -47.3


050

100150200250300350


Price Relative

Source: Datastream


Next news FY2012 Results

Business Independent oil and gas exploration company

with interests in Namibia.

www.chariotoilandgas.com/



Year end February

Revenue($m)

EBIT*($m)

PBT*($m)

Tax(%)

Adj. EPS* (c)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 0.0 (10.8) (28.6) 0.0 (0.2) (922.6) (32.0) 0.02010A 0.0 (3.2) (3.1) 0.0 (0.0) (9,016.9) (107.3) 0.02011E 0.0 (7.3) (7.3) 0.0 (0.1) (3,946.0) (47.1) 0.0





Chariot Oil & Gas | 10 February 12 Valuation and recommendation


We value Chariot on a risked net asset value basis, assessing its near term exploration targets specifically. The implicit assumptions used in our risked valuation are as follows:


Metric Assumption

NPV $/mmboe 1.06 Long term exchange rate $/£ $1.65/£1 Number of shares outstanding (m) 340.43 Chance of exploration success Nimrod - 24%, Tapir South - 25%


When assessing an appropriate NPV/bbl to apply in our RENAV calculation, we have relied on the derived market value of Namibian prospective resources taken from the UNX/HRT transaction in February 2011. HRT offered $721m to acquire UNX Energy which had c.645mmboe of net risked resources and c.$35m of cash. The derived $/mmboe of this transaction infers $1.06/bbl ([$721m-$35m]/645mmboe) and acts as a benchmark for valuing Chariot's assets.


Scheduled Project Interest CoS/CoD Prospective Resources (mmboe)

NPV 10% US$ / boe

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Gross Net 2012 Tapir S 100% 25% 451 451 1.06 478.1 119.5 289.7 72.4 21.3 2012 Nimrod (Albian) 25% 24% 2,524 631 1.06 668.9 160.5 405.4 97.3 28.6 Total 2012 2,975 1,082 1,146.9 280.0 695.1 169.7 49.9 2013 Delta 1 90% 11% 438 394 1.06 417.9 46.0 253.2 27.9 8.2 Total 2013 438 394 417.9 46.0 253.2 27.9 8.2 Not Specified Tapir N 100% 21% 298 298 1.06 315.9 66.3 191.4 40.2 11.8 Not Specified Tapir 100% 21% 188 188 1.06 199.3 41.8 120.8 25.4 7.5 Not Specified Tapir NE 100% 14% 61 61 1.06 64.7 9.1 39.2 5.5 1.6 Not Specified Zamba N 100% 12% 23 23 1.06 24.4 2.9 14.8 1.8 0.5 Not Specified Zamba 100% 15% 633 633 1.06 671.0 100.6 406.7 61.0 17.9 Not Specified A (Albian) 25% 10% 149 37 1.06 39.5 3.9 23.9 2.4 0.7 Not Specified B (Albian+Barremian) 25% 18% 146 37 1.06 38.7 7.0 23.4 4.2 1.2 Not Specified C (Albian+BDO) 25% 9% 423 106 1.06 112.1 10.1 67.9 6.1 1.8 Not Specified D (Albian) 25% 10% 47 12 1.06 12.5 1.2 7.5 0.8 0.2 Not Specified Dora North 25% 13% 186 47 1.06 49.3 6.4 29.9 3.9 1.1 Not Specified K (Syn-Rift) 25% 10% 248 62 1.06 65.7 6.6 39.8 4.0 1.2 Not Specified L (Albian) 25% 10% 120 30 1.06 31.8 3.2 19.3 1.9 0.6 Not Specified Isabel (BDO) 25% 14% 58 15 1.06 15.4 2.2 9.3 1.3 0.4 Not Specified Mary (BDO) 25% 15% 100 25 1.06 26.5 4.0 16.1 2.4 0.7 Not Specified Dora South 25% 13% 174 44 1.06 46.1 6.0 27.9 3.6 1.1 Not Specified Klipspringer 90% 7% 587 528 1.06 560.0 39.2 339.4 23.8 7.0 Not Specified Hartebeest 90% 7% 502 452 1.06 478.9 33.5 290.2 20.3 6.0 Not Specified Oryx 90% 6% 157 141 1.06 149.8 9.0 90.8 5.4 1.6 Not Specified Springbok 90% 12% 58 52 1.06 55.3 6.6 33.5 4.0 1.2 Not Specified Springbok East 90% 12% 58 52 1.06 55.3 6.6 33.5 4.0 1.2 Not Specified Eta 90% 10% 68 61 1.06 64.9 6.5 39.3 3.9 1.2 Not Specified Springbok North 90% 10% 74 67 1.06 70.6 7.1 42.8 4.3 1.3 Not Specified Delta 2 90% 11% 131 118 1.06 125.0 13.7 75.7 8.3 2.4 Not Specified Delta 3 90% 11% 107 96 1.06 102.1 11.2 61.9 6.8 2.0 Not Specified Reef 1 90% 9% 161 145 1.06 153.6 13.8 93.1 8.4 2.5 Not Specified Reef 2 90% 9% 225 203 1.06 214.7 19.3 130.1 11.7 3.4 Not Specified Lead A 90% 8% 402 362 1.06 383.5 30.7 232.4 18.6 5.5 Not Specified Lead B 90% 8% 312 281 1.06 297.6 23.8 180.4 14.4 4.2 Total not specified 5,696 4,174 4,424.0 492.5 2,681.2 298.5 87.7 Total overall 9,109 5,650 5,988.7 818.5 3,629.5 496.1 145.7


We value Chariot on a risked net asset value

basis, assessing its near term exploration targets

specifically.


Valuation and recommendation Chariot Oil & Gas | 10 February 12

When valuing Chariot’s exploration portfolio, we have utilised the resource estimates provided in the company’s Competent Persons Report undertaken by NSAI, as well as subsequent management guidance for specific lead assets. Due to the early nature of Chariot’s operations, we have taken a prudent approach to their resource volume estimates, and valued the portfolio at the ‘low’ categorisation as specified in their resource audit.

In spite of what we feel are overly favourable recommendations from the majority of analysts covering Chariot, we will only provide a value for the company’s near term exploration assets. We feel it is worth highlighting that Chariot is a relative newcomer to the market and is yet to undertake any drilling. On this basis, to attribute value to all of its assets (some of which cannot possibly be drilled for many years) is somewhat generous – especially given that Namibia remains an unproven province.


£ million p/share

Tapir S 72.4 21.3 Nimrod 97.3 28.6 Net cash 84.6 24.9 Core value 254.3 74.7


Our pre-drill valuation of 75p consists of near term exploration targets (Tapir South and Nimrod) and the company’s net cash position at 1H2011. If the company progresses to Delta 1 in 2013, we will include this in our overall valuation.


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Our SOTP valuation illustrates that Chariot is, in our view, overvalued at present as the market seems to be attributing value to its assets prior to successful drilling. The company has benefited from a series of significant resource upgrades since listing on AIM. However we continue to await the implementation of its long term development plan to exploit those assets.

Chariot has also experienced delays in drilling its Tapir South prospect (scheduled for Q4 2011) due to issues obtaining the necessary rig, and recent news flow suggests the market will need to wait until Q2 2012 until the company can spud its first well. On this basis, we initiate coverage with a Sell recommendation and set a pre-drill target price of 75p – representing c.41% downside risk.

In spite of what we feel are overly favourable

recommendations from the majority of analysts

covering Chariot, we will only provide a value for

the company’s near term exploration assets.


Chariot Oil & Gas | 10 February 12 Strategy overview

Strategy overview

Current issues Chariot has communicated a clear exploration plan which covers the next two years and sets out the company’s initial targets. However, the plan has had to deviate somewhat from the original strategy due to issues with suitable rig availability, which has to some extent highlighted Chariot’s relative inexperience in operating in the region.

Originally, the rig was anticipated to be available for a 4Q2011 spud at the Tapir South prospect, but was contracted by another operator for a longer programme. Subsequently, the market for deepwater rigs offshore West Africa has tightened markedly, making it more challenging to secure an appropriate rig particularly to carry out a one-well programme in Namibia without paying a significant premium.

Nevertheless, Chariot is currently in active negotiations regarding a number of other available rigs and now expects to spud the Tapir South exploration well in 4Q2012, although we are yet to receive official confirmation of this. In our view, failure to secure a rig for this expected date will again detrimentally affect market sentiment towards the company.

Forward drilling Chariot's Tapir South prospect is drill ready, with all long lead items now delivered and all service contracts signed, the support base secured and the drill permit granted. If this well goes ahead as planned in 2Q, the company plans to move on to Nimrod in the Southern Block targeting over 1bnboe net (mid case).

In our view, 2012 will be a pivotal year for Chariot with an exploration well in each of their Northern and Southern blocks expected. In addition, the impending results of the 3D seismic survey currently underway on the company’s Central blocks (recently farmed out to BP) will go some way in identifying further structures and increasing the company’s understanding of the geology at the block.

Chariot aims for a strategy of drilling four to five wells through to end 2013, however we feel this will largely depend on the outcome at Tapir South and Nimrod.

Chariot's two year exploration plan

Drill Zamba prospect

Process data for Delta-1

Spud first well at Delta-1

Process data for Nimrod

Process data for Tapir South

Spud first well at Nimrod

Spud first well at Tapir South

Take possession of required rig

Interpret 3D seismic on Central Blocks

Progress farm-out discussions for Northern

Blocks

Process data for Zamba

2012 2013 2014

Source: Company


Strategy overview Chariot Oil & Gas | 10 February 12

As illustrated above, the company’s 2013 strategy will highly depend on successful drilling at Tapir South and Nimrod. This plays an important role in how we formulate our valuation.

In our view, if both of Chariot’s near-term prospects are dry holes, and the company decides to stay in the acreage (if it is still deemed prospective), commitments to drill do not arise until October 2014 in licenses 1811A and B in the North, and August 2015 in license 2714 in the South. This situation may see the shares languishing until drilling restarts, and in the absence of a successful farm out, may also put the company in jeopardy regarding access to financing for a second or third well.

To illustrate this, the company currently has c.$140m, and expects to spend c.$72m on drilling its first exploration well at Tapir South and c.$55m at Nimrod. If drilling proves unsuccessful, which the company’s reserve auditor deems likely (25% and 24% chance of success respectively), the company will only have $13m remaining – insufficient to drill a third well. The company’s assets will still be classed as prospective resources, and not adequate to use as collateral for debt finance; so the only options remaining in our view will be to raise funds through equity or enter into a farm out process. Both of which reduce the company’s value, which would be unattractive for existing and new investors.

Chariot’s position on any final farm out deal will have to ensure that the timing behind any drilling campaign is in the company’s interest, with an element of at least one well carry (i.e. one well carried by the partner for every two wells drilled by Chariot) incorporated in order to keep drilling costs down. The company has been clear that this is an approach they intend to adopt, however they will potentially need to sacrifice a large working interest to secure this if initial drilling proves unsuccessful.

Resources Chariot has positioned itself to exploit the potential of their blocks, which are situated in three geologically distinct settings:

Chariot's positioning offshore Namibia

Source: Company

The Namibe Basin forms part of the West African “salt basin”, bounded to the south by the Walvis ridge. Prior to the Atlantic Ocean opening, the basin lays adjacent to the Santos Basin of Brazil, in which recent substantial oil discoveries have been made. The Luderitz and Walvis Basins are virtually unexplored with only four wells drilled to date, in an area similar in size to the UK North Sea.


Chariot Oil & Gas | 10 February 12 Strategy overview

Chariot’s acreage

Volumetric pot Northern Block Central Block Southern Block

Resources in place (bnbbls) 2.8 4.3 9 Location Namibe Basin Walvis Basin Orange Basin Depth (m) 700 – 2300 500 – 3000 100 – 1500 Work performed to date 1500km² 3D seismic (2008/9)

Processing complete July 2010 Processing and Interpretation completed March 2010. 3000km2 2D seismic (2008).

3000km² 3D acquired in 2008/9. Petrobras farmed into Block 2714A for a 50% interest and BP for 25%.

Targets 4 prospects and 2 leads identified to date

3 leads identified to date 11 prospects identified to date

Source: Company

Recent upgrades Chariot has also benefited from a series of resource upgrades since listing, which has generated interest from the market; as well as larger E&P players with a view to farm in to the company’s acreage.

Resource upgrade waterfall chart

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bnbo

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Source: Company

In 2011, the company announced an increase of 4bnboe in its estimate of gross unrisked mean prospective resources in its Southern licence 2714A after it identified a mega-structure at Nimrod. In addition, continued technical work undertaken on 3D seismic data acquired across all blocks led to an improvement in the chance of success.

Nevertheless, we feel that Chariot must now focus its efforts on developing these resources rather than seeking further upgrades – a notion shared by the market and illustrated by the share price falling c.108% since the last upgrade, suggesting a high amount of profit taking prior to drilling.


Namibia Overview Chariot Oil & Gas | 10 February 12

Namibia Overview

Namibia is a large and sparsely populated country (2.3m) on Africa's south-west coast. It has enjoyed stability since gaining independence in 1990 after a long struggle against rule by South Africa.

Namibia country map

Source: World Travels

The economy is heavily dependent on the extraction and processing of minerals for export. Mining accounts for 8% of GDP, but provides more than 50% of foreign exchange earnings.

The country has firm macroeconomic policies, efficient political structures, growing financial institutions, and its corruption index is also much better when placed in comparison with other African countries. In addition, Namibia’s currency is directly linked to the South African Rand and is therefore not as much affected by currency fluctuations as neighboring countries.

After many years of intensive data acquisition in Namibia, oil and gas exploration operations have reached a stage where information is available on the location of drillable targets.

Namibia is a large and sparsely populated

country (2.3m) on Africa's south-west coast. It

has enjoyed stability since gaining independence

in 1990 after a long struggle against rule by

South Africa.


Chariot Oil & Gas | 10 February 12 Namibia Overview

Oil & Gas industry Namibia does not have a significant history of oil or gas production, but is believed to hold a great deal of potential. Located immediately to the North is Angola, a major oil producer and member of OPEC.

The main areas of activity are all located offshore in the Atlantic Ocean to the west coast of the country. Offshore Namibia is considered largely under-explored. Only 14 exploration wells have been drilled so far in an area that covers c.500,000km2.

Five of the wells are located in the Kudu Gas Field which has c.1.4tcf of proven reserves and a potential upside of 20tcf. Nevertheless, Kudu is the only commercial hydrocarbon discovery in Namibia to date.

As a result, Namibia has a currently fledgling yet growing upstream industry with an estimated higher gas than oil potential. As outlined above exploration success has been intermittent with the Kudu gas field representing the only commercially viable find by Chevron in the 1970’s. The field is located c.120km from Chariots Southern block, which although somewhat de-risks the company’s acreage here, also provides an indication of hydrocarbon type for Chariot’s Southern Blocks.

Positioning of Chariot's acreage

Source: Company

Given the proximity of Chariot’s Nimrod prospect (to be drilled in Q2 2012) to the Kudu gas discovery in the Orange River basin, there is a risk that Nimrod and potentially others in the southern blocks are be gas-filled structures. This would reduce valuation given that the company maintains that it believes the asset is predominantly oil based, although if gas, the implied size of a discovery would represent a prime target for LNG development.

Fiscal Regime Namibia has a 35% federal tax, a flat 5% royalty, and 25% additional profits tax (with three tiers built in, with the first tier applying when the IRR of the project exceeds 15%). There are no petroleum sharing agreements or petroleum sharing commitments currently in place. We feel that this currently represents a favorable fiscal regime and somewhat acts as an incentive for continued investment into Namibia’s oil exploration industry.

Namibia does not have a significant history of oil

or gas production, but is believed to hold a great

deal of potential. Located immediately to the

North is Angola, a major oil producer and

member of OPEC.


Namibia Overview Chariot Oil & Gas | 10 February 12

West African government tax take comparison

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CongoBrazzaville

Nigeria Angola EquitorialGuinea

Namibia Mauritania Ghana

Source: Company

As illustrated above, the fiscal terms offered to Namibian oil operators are amongst the lowest of the West African countries. As the tax is concession based, with additional profit tax (APT) on top of corporate tax, the lack of a PSC structure could leave such a system open to changes to tax laws, thus impacting Chariot’s valuation. This risk also extends to increased state participation, which was highlighted in the Namibian Minister of Mines’ 2011 speech regarding new legislation for the mining industry, which may potentially set a precedent for the oil industry in the country.

The fiscal terms offered to Namibian oil

operators are amongst the lowest of the West

African countries.


Chariot Oil & Gas | 10 February 12 Asset overview

Asset overview

Namibia remains hugely under-explored due to the legacy of political history (offshore exploration did not get underway until independence in 1990) and exploration history. Oil companies traditionally focused on the salt basin whilst frontier exploration such as in Namibia was almost entirely conducted on a low investment basis without 3D seismic control.

Chariot's licence location map

Source: Company

Northern Blocks – 100% The Northern Blocks are situated to the north of the Walvis ridge and are similar in geology to the Santos basin in Brazil. The existing inventory in this area consists of five prospects and two leads, with a total mean unrisked prospective resource of 2.8bnbbls.

It is here where Chariot’s first well will be drilled at Tapir South, which has been formed by a rotated fault block. The Tapir trend contains three separate prospects where success at one will go some way in de-risking the other prospects and potentially unlock additional leads.

Central Blocks – 90% The Central Blocks are located within the Luderitz and Walvis Basins and cover an area of 16,801km2. Following reprocessing and reinterpretation of the existing 2D seismic data, Chariot and PGS have agreed to focus the 3D seismic acquisition programme in the north-eastern area of the blocks. The attraction of this part of the acreage is the recognition of multiple target levels and numerous leads including analogues to the "Nimrod" feature in Chariot's Southern acreage (see below) with potentially two active oil prone source intervals.

Overall these elements increase the likelihood of maturing multiple drilling targets within the 3D acquisition area. To capture as many of the high-graded leads as possible the survey has been extended to cover 3,500km2 from the originally planned 2,500km2.

An additional benefit for the company is that the new 3D seismic area covers water depths ranging from 750-1,750m (significantly shallower than the depths in the originally proposed acquisition area) which will potentially result in a considerable reduction in expected well costs.


Asset overview Chariot Oil & Gas | 10 February 12

Southern Blocks – 25% In the Southern Blocks, located in the Orange River basin, Chariot has identified 11 prospects with a gross unrisked mean prospective resource estimated at 8.507bnbbls.

Chariot’s second well target (Nimrod) is situated in these blocks and is the company’s largest prospect with gross mean unrisked resource estimate of 4.6bnbbls. In addition, the chance of success is also the highest at 25%.

Underlying the Nimrod prospect is a large basement arch which is progressively overstepped by Barremian sediments. Stratigraphic traps are formed in this position where sands are interbedded within shales or volcanics that can provide seal. This trapping configuration is believed to be the form of the nearby Kudu field which is the same reservoir age and directly along trend.

The Southern licences are located in shallower water depths and as a result an older generation semi-submersible rig will be used.


Chariot Oil & Gas | 10 February 12 Financial model

Financial model

Income Statement


2009A 2010A 2011E

Group revenue 0.0 0.0 0.0Cost of sales 0.0 0.0 0.0Gross profit 0.0 0.0 0.0Total operating expenses (10.8) (3.2) (7.3)EBIT (10.8) (3.2) (7.3)Net interest/financial income/(cost) (17.8) 0.1 0.1Associate and Other non-op. income/(cost) 0.0 0.0 0.0PBT (28.6) (3.1) (7.3)Tax 0.0 0.0 0.0Effective tax rate (%) 0.0 0.0 0.0Minorities 0.0 0.0 0.0Earnings (28.6) (3.1) (7.3) EBITDA (10.8) (3.2) (5.0)Adjusted EBITDA* (10.8) (3.2) (5.0)Adjusted EBIT* (10.8) (3.2) (7.3)Adjusted PBT* (28.6) (3.1) (7.3)Adjusted earnings* (28.6) (3.1) (7.3) DPS (c) 0.0 0.0 0.0EPS (c) (0.2) (0.0) (0.1)EPS [F. Dil.] (c) (0.2) (4.9) 0.2EPS [Adj.]* (c) (0.2) (0.0) (0.1)EPS [Adj. F. Dil.]* (c) (0.2) (0.0) (0.1)Weighted average no. shares (m) 132.3 141.2 144.3Fully dil. w. ave. no. shares (m) 132.3 141.2 144.3Year end no. shares (m) 132.3 141.2 144.3




Financial model Chariot Oil & Gas | 10 February 12

Cashflow Statement


2009A 2010A 2011E

Operating income (10.8) (3.2) (7.3)Amortisation of acquired intangibles 0.0 0.0 0.0Amortisation of other intangibles 0.0 0.0 0.0Depreciation 0.0 0.0 2.4Net change in working capital (0.6) (8.5) (0.2)Other 1.8 0.0 0.1Operating cash flow (9.5) (11.7) (5.1) Capital expenditure (31.5) (17.3) (4.1)Investment in Other intangibles 0.0 0.0 0.0Net interest/financial income/(cost) 2.0 0.1 0.1Tax paid 0.0 0.0 0.0Net acqns./disposals 0.0 16.0 0.0Dividend paid 0.0 0.0 0.0Other 0.0 0.0 0.0Cash flow before financing (39.0) (12.8) (9.1) Proceeds from shares issued 88.8 0.0 2.1Investments 0.0 0.0 0.0Other 0.0 0.0 0.0Net movement in cash/(debt) 49.8 (12.8) (7.0) Opening net cash/(debt) 3.5 28.9 16.2Adjustments (Forex, etc.) (19.8) 0.2 0.0Closing net cash/(debt) 28.9 16.2 9.2 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E

Property plant and equipment 0.2 0.5 0.4Goodwill and Acquired intangibles 0.0 0.0 0.0Other intangibles 87.0 88.6 92.7Other fixed assets 0.0 0.0 0.0Non current assets 87.2 89.1 93.1 Stocks & WIP 0.0 0.0 0.0Trade receivables 0.1 0.7 1.0Cash 28.9 16.2 9.2Other current assets 0.0 0.0 0.0Current assets 29.0 16.9 10.3 Total assets 116.2 106.0 103.3 Trade creditors 8.4 0.5 0.6Short term borrowings 0.0 0.0 0.0Long term borrowings 0.0 0.0 0.0Other liabilities 0.0 0.0 0.0Total liabilities 8.4 0.5 0.6 Net assets 107.8 105.5 102.7 Issued share capital 2.8 2.8 2.9Share premium account 133.2 133.2 135.4Retained earnings (31.4) (34.2) (38.3)Other reserves 3.2 3.7 2.8Minority interests 0.0 0.0 0.0Total equity 107.8 105.5 102.7



Chariot Oil & Gas | 10 February 12 Financial model


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Take on me Faroe Petroleum has a robust mix of production growth and high impact exploration, and continues to execute value enhancing transactions on both sides of the Continental Shelf, most notably its recent asset swap with Petoro AS. The company has a strong balance sheet with sufficient cash reserves and debt facilities to fund its progressive drilling, appraisal and development activities.

Petoro assets yielding growth for 2012 Faroe’s transformational asset exchange with Petoro AS served to increase net production fourfold by the end of 2011. Importantly, the transaction has now been legally concluded, allowing Faroe to fully recognise cash flows from its share of production. Furthermore, the significant tax advantages arising from the deal will now also be exploited, which includes a pro et contra settlement of up to £80m receivable from the state owned company.

Production - short term sacrifice for long term rewards Faroe has undergone an extensive review of its Norwegian assets post exchange, and intends to shut in a number of production wells at one of its fields (Njord) to implement a riser replacement programme, and to ultimately tie in the new Hyme field. Faroe expects this to increase long term production as well as prolonging the life of the combined fields, which will contribute c.30% of overall production net to Faroe.

Fully funded strategy Faroe is fully funded to pursue their strategy of drilling at least five potentially high impact wells a year, targeting 175mmbbls, representing 21% of their current portfolio, and 39p/share of our target valuation on a risked basis. The company expects to record cash in the region of £100m on their balance sheet at year end, and has also secured a number of debt facilities which ensures that share capital dilution to fund expansion is kept to a minimum.

Valuation and recommendation We have valued Faroe on a DCF basis for its forecast NPV arising from its producing assets, and with cash and tax receivable yields a core value of 119p. We have also included a risked exploration NAV for the other early stage assets which yields an additional 187p. We therefore initiate coverage with a Buy recommendation and set an overall target price of 306p.


10 February 12 | Company Note | Oil & Gas exploration and production

Faroe Petroleum( AIM:FPR)1

BUY Share price 169p



Net cash (£m) 24.3



Free float (%) 75.0

Average daily vol ('000 3m) 888


(%) 1m 3m 12m

Absolute +5.5 +9.8 -16.0

FTA relative +1.2 +2.7 -14.7


80100120140160180200220240


Price Relative

Source: Datastream


Next news FY results

Business Oil & Gas exploration and production

www.fp.fo/



Year end December

Revenue(£m)

EBIT*(£m)

PBT*(£m)

Tax(%)

Adj. EPS* (p)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 7.0 (28.6) (11.8) 41.4 (6.6) (25.6) (10.6) 0.02010A 15.1 (25.2) (26.0) 21.9 (13.3) (12.7) (12.0) 0.02011E 159.7 18.3 16.4 28.6 5.5 30.7 16.6 0.02012E 141.8 15.9 15.1 25.0 5.3 31.6 19.1 0.02013E 153.3 22.3 21.5 24.0 7.7 21.9 13.6 0.0

* excludes exceptional items and amortisation of acquired intangibles.^ EV calculation adjusted for core cash, investments etc.



Faroe Petroleum | 10 February 12 Valuation and recommendation


We have valued Faroe both in terms of its producing assets as well as its future risked exploration portfolio in the UK North Sea and Norwegian North Sea.

We have employed the following assumptions for our discounted cash flow (DCF) analysis of the company’s production profile:

• Oil Price: 2012: - $100/bbl, 2013+: - $90/bbl

• Discount rate: 10%

• Production decline: 10% (UK) 15% (Norway – see ‘Strategic Overview’)

• Long term $/£: 1.65/1

In addition, we have incorporated the following assumptions in determining the value per mmboe for Faroe’s exploration assets at both the firm and expected level:

Resource assumptions

Hydrocarbon type Classification $/mmboe

Oil/Gas Reserves 6.00Oil/Gas Resources 3.00


These assumptions have been assimilated into our risked net asset value appraisal as follows:


Country Stage of development Resources/Reserves (mmboe)

NPV 10%/ bbl NPV ($m) NPV (£m) Net risked

Gross Net Unrisked Risked Unrisked Risked p/share UK Exploration/ Appraisal 1507.0 176.4 3 529.1 89.4 320.7 54.2 26 Norway Exploration/ Appraisal 6384.5 568.5 3 1705.5 389.4 1033.7 239.7 113 UK Production 175.2 12.7 6 76.4 76.4 46.3 46.3 22 Norway Production 181.6 15.4 6 92.3 92.3 55.9 55.9 26 773.0 2403.3 647.5 1456.6 396.1 187



£m p/share

UK 57.1 27 Norway 68.8 32 Less: G&A -23.4 -11 Add: Net cash 104.8 49 Norway tax losses 46.0 22 Core NAV 253.3 119.3 Exploration upside 396.1 187 Risked NAV 649.4 306 Source: Seymour Pierce Ltd

Our core valuation comprising discovered assets, cash and investments contributes 98p per share, and our risked exploration valuation adds a further 187p illustrating a large degree of potential exploration upside to investors.


Valuation and recommendation Faroe Petroleum | 10 February 12

SOTP valuation

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We have valued Faroe on a DCF basis for its forecast NPV arising from its producing assets, and with cash and tax receivable yields a core value of 119p. We have also included a risked exploration NAV for the other early stage assets which yields an additional 187p. We therefore initiate coverage with a Buy recommendation and set an overall target price of 306p.


Faroe Petroleum | 10 February 12 Strategic overview

Strategic overview

Faroe’s portfolio comprises over 47 licences located in the West of Shetlands, offshore the Faroe Islands, the UK North Sea and Norway. In addition, the company now has interests in 10 producing oil and gas fields in the UK and Norway.

Faroe's acreage

Source: Company

Exploration

Faroe has employed a progressive exploration plan which targets at least five additional wells a year. This strategy remains unchanged, and the company’s 2012 exploration drilling programme will include the Kalvklumpen, Clapton, Cooper and Santana prospects in Norway and the North Uist prospect in the UK, west of Shetlands.

Targeted 2012 exploration

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The above campaign illustrates that Faroe will target 175mmbbls of unrisked resources in 2012 (representing 21% of their current portfolio) and c.39p/share of our target valuation on a risked basis.


Strategic overview Faroe Petroleum | 10 February 12

Recent additions to Norwegian asset base

In addition to an aggressive exploration programme, Faroe continues to grow its asset portfolio in Norway. The company recently announced that it has secured seven new prospective exploration licenses on the Norwegian Continental Shelf under the 2011 Norwegian APA License round. In addition, Faroe has been awarded operatorship in three of these licenses with working interests ranging from 20% to 75%, demonstrating the company’s growing ambitions for exploration in the country.

The award of these licences also strengthens Faroe’s working relationship with Centrica (with whom they have made three discoveries in the past two years) as they continue to partner on four of the additional licences.

Additional Norwegian licences

Licence Location Partners

Novus Norwegian Sea, Halten Terrace Area Faroe 50% (operator), Centrica 40%, Skagen 10% Aerosmith Norwegian Sea, Halten Terrace Area Faroe 20%, OMV 30% (operator), Repsol 20%, Centrica 20%, Skagen 10% Oksen Northern North Sea Faroe 20%, Det Norske 40% (operator), Noreco 20%, Bayerngas 20% Shango Northern North Sea Faroe 20%, Total 40% (operator), Centrica 20%, Det Norske 20% Darling Northern North Sea Faroe 20%, Bridge 40% (operator), Concedo 20%, Centrica 20% Epsilon North Sea, Egersund Basin Faroe 75% (operator), Noreco 25% Lola North Sea, Egersund Basin Faroe 50% (operator), Noreco 25%, Edison 25% Source: Company

We feel that Faroe’s focussed growth in Norwegian exploration is particularly encouraging when placed in context with the wider trend on this side of the Continental Shelf. The Norwegian Petroleum Directorate (NPD).estimates that the number of exploration and appraisal wells to be drilled off Norway in 2012 will remain flat compared with the 52 spudded last year. This compares with a 27% increase in wells drilled in 2011 from 2010.

In terms of exploration success, Norway achieved a find rate of 51% last year, making a total of 22 discoveries across the North, Norwegian and Barents seas. This compares to Faroe’s success rate of c.80% in the country in 2011 – further highlighting the company’s growing operational strength.

Faroe will target 175mmbbls of unrisked

resources in 2012 (representing 21% of their

current portfolio) and c.39p/share of our target

valuation on a risked basis.



Field Development Faroe has also embarked on an extensive field development programme at its Norwegian assets to stimulate further production. Although this results in a temporary reduction in production for 2012 (outlined below), the long term benefits of increased production and extended field life clearly outweigh the short term sacrifice.

The company is currently in the process of drilling infill wells at Brage and Njord. Faroe has collated a comprehensive amount of data, including 4D seismic, which supports the strategy of drilling high impact infill wells to increase production, which has been proven in recent years. In addition, the company expects that continuous infill drilling at the sites will unlock additional producible reserves throughout 2012 and 2013.

Faroe has also sanctioned two infill wells at Ringhorne East, operated by Exxon Mobil, throughout 2012. This comparatively low operating cost field is expected to contribute 20% (with Jotun) to Faroe’s net production in 2012.

Expected drilling programme

Prospect Interest Operator Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4Butch 15.0% CentricaT-Rex 30.0% MaerskKalvklumpen 20.0% DetNorN.Uist/Cardhu 6.3% BPClapton 40.0% FaroeCooper 30.0% CentricaRodrigues/Santana 30.0% WintershallButch Appraisal 15.0% CentricaFreya Appraisal 50.0% FaroeMilagro 30.0% NorthKnorke 30.0% WintershallSamson Dome 20.0% BGGrouse 37.5% FaroeFieldBrage infill 13.4% StatoilNjord Infill 7.5% StatoilHyme development 7.5% StatoilRinghorne East infill 7.8% ExxonGlitne 9.3% StatoilSchooner 6.9% Tullow

Firm 12Expected 7Drilled 19

ExplorationAppraisal

Development

2012 2013

Source: Company

Production

In 2011, Faroe negotiated a transformational asset exchange with Petoro AS to swap its 30% interest in the Maria oil discovery in Norway for non-operated interests in a number of producing oil and gas assets in Norway, namely in Brage, Njord, Ringhorne East and Jotun. This ultimately served to increase overall net production to Faroe four-fold from 2,500boepd to 10,100boepd by the end of 2011.

Faroe net forecast production profile

0

2,000

4,000

6,000

8,000

10,000

12,000

FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015

boep

d

Topaz gas field Wissey gas field Schooner gas fieldBlane oil field Enoch oil field Glitne Oil FieldNjord Brage Ringhorn East & Jotun Field

Source: Company


Strategic overview Faroe Petroleum | 10 February 12

The company expects to produce in the range of 6,000 to 8,000boepd in 2012 due to reduced production primarily from the Njord field. A riser replacement programme is currently underway which will continue throughout 2012, and will tie in the new Hyme field to Njord. The Njord riser replacement programme has necessitated the shutting in of production wells on the Njord field and as the risers are replaced the wells are progressively being brought back on stream.

The Hyme field development (see below) is scheduled for installation in 2012, and will necessitate the shutdown of the entire Njord field for approximately three months while the field is tied in to the Njord platform. As a consequence, average 2012 production from Njord will not reflect full field capacity; however 2013 production is expected to benefit from the Njord wells being back on stream as well as the new Hyme production wells. Njord and Hyme are expected to contribute c.30% to Faroe’s net production in 2012. 2013 production is expected to be significantly higher as Hyme is brought on stream, as riser replacement work ends and new infill wells (outlined above) begin to contribute to overall production.



Hyme

In May 2011, a Field Development Plan (FDP) was submitted for the Hyme oil field, which has since been approved by the Norwegian Ministry of Petroleum and Energy. Faroe has a 7.5% net interest in the Hyme development located to the east of Njord. First oil from Hyme is expected in 2013.

Hyme location map

Source: Statoil

The field will be developed with one dual-lateral producer and a water injector sub-sea tied back to the Njord field. In addition, the Njord partnership has sanctioned a project to allow continued production at lower pressure and extended field life. These two projects are expected to add over 3mmboe of 2P reserves net to Faroe, in addition to the 14.2mmboe reported from the initial transaction outlined above.

The capital requirement of the above development programme will amount to £37m net to Faroe, of which approximately £12m has been spent. The company expect the field to come on stream in 2013 at a rate of 900boepd net to the company, thus increasing production by a further 10% from current levels. In terms of the additional operating expenditure associated with the field, the company maintains this will be marginal given that it will be tied in to existing infrastructure and capacity at Njord.


Financial overview Faroe Petroleum | 10 February 12

Financial overview

Funding the strategy

Faroe is fully funded to embark on their multi-well exploration programme, wilth internal projections estimating a 2011 year end cash position in the region of £130-135m including a pro et contra settlement of c.£80m (pre tax). Although Faroe historically raised funds through the equity markets, the company now benefits from a strong cash inflow position predominantly arising from its producing Norwegian assets (outlined above) as well as robust lending facilities secured in 2011. This progressive financial approach ensures that share capital dilution is kept to a minimum when financing the company’s multi-well drilling campaign.

Faroe undertook a refinancing of its bank facilities in July and now includes a revolving credit facility of NOK500m (c. £55m), as well as a further uncommitted facility of NOK500m. This has been set up to finance 75% of the company’s Norwegian exploration costs net of Norwegian profits, such that no more than 25% of exploration expenditure in Norway is funded from equity sources. At the company’s last interim results, £30.8m was outstanding on the current Norwegian exploration facility, which is drawn against the Norwegian tax rebate receivable in December 2011 and 2012.

In addition, Faroe has increased its reserve based debt facility to $125 million (c.£78m) and secured a further uncommitted facility of $125 million. This represents a significantly larger facility than the previous reserve based debt facility of £20m, and is currently undrawn.

It is also important to note that the combined debt capacity of Faroe’s Blane and Petoro assets exceed the current reserve based lending facility cap of $125m (c.£78m), ensuring that the company is well placed financially with excess funding headroom if necessary.

Petoro impact on financial capability

Faroe is due to undertake an active investment programme in 2012 (costing in the region of £60-80m) at its producing Norwegian assets acquired through this transaction. This will be funded entirely through cash flow and the above mentioned debt facilities.

In our view, this transaction was beneficial in both financial and strategic terms to Faroe. The increased production revenues significantly enhance cash flow and debt capacity to fund further exploration and expansion of the company. In addition, the capital requirement (amounting to c.£250m) due from Faroe in respect of the Maria field is now the responsibility of Petoro. The company also benefits from no capital gains tax falling due on the transaction. In addition, the transaction also transfers to Faroe pro-forma tax balances (an asset) with an undiscounted future tax value in excess of NOK 400m (c.£46m) as of the effective date.

The fiscal terms offered to E&P companies operating in Norway should not be understated; the benefits of the tax asset received from Petoro as well as an exploration expense rebate, creates a strong fiscal environment for the company.


Faroe Petroleum | 10 February 12 Financial overview

Norwegian tax system

The Norwegian tax regime governing oil and gas exploration and production has become more favourable in recent years. Given the recent transition, we feel that the current system can be poorly understood by potential investors and it is therefore important to provide an outline of the terms. It is also significant given Faroe’s increased exposure to the country after the Petoro asset swap transaction.

From 2003, the government introduced multiple initiatives to stimulate resource exploitation in the region to fuel long term investment.

Exploration

In 2004, the Norwegian government outlined the new fiscal regime for oil and gas exploration, the biggest incentive being 78% of expenses relating to exploration up to PDO are refunded year after spend. This has subsequently made it easier for smaller companies to fund their operations as exploration can be financed through bank facilities with pledge in the tax refunds. In addition to this refund, a further 30% uplift is recognised over four years (7.5% p.a) for capital expenditure on development projects. This is subsequently depreciated on a straight line basis over six years. In addition, companies not in a tax position can carry forward their losses and the uplift with interest.

Production

Norway taxes oil profits at 50%, on top of a regular business tax of 28%, so that oil companies pay 78% tax. The country recognises 30% of its tax revenues from its off-shore oil. Early on after the discovery of oil, the nation made the decision to prevent the kind of private profligacy and boom and bust cycles of the other oil-rich nations.

Faroe impact

The biggest impact to Faroe arises on the acquisition of three ex-Petoro assets through last year’s asset swap transaction. Faroe inherited Petoro’s historic tax balances which have been back calculated on the basis that Petoro does not pay tax given that it is state owned. The total undiscounted tax value equates to NOK476m (c.£46m), which Faroe can financially take advantage of through recognising the straight line depreciation. Capital expenditure is typically depreciated on a straight line basis over six years, with an uplift of 30% applicable against the special tax, which is taken over four years. In total, 93% of the capital expenditure is recovered through the tax system over a six year period.


Financial overview Faroe Petroleum | 10 February 12

Depreciation of inherited tax balances

0

20

40

60

80

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120

140

160

FY2011 FY2012 FY2013 FY2014 FY2015

NO

K (m

)

Depreciation Uplift

Source: Company

Tax is paid in six tranches, with 50% payable in the current year and 50% in the subsequent year. The 78% E&A cost is refunded in the year after it is incurred, limited to the current year’s net tax loss. The upshot of this is that Faroe is expected to pay between £34m-38m in 2012 relating to 2011.

Faroe had a tax receivable at their last interims of £36.3m being 78% of exploration expenditure, net of production profits, in Norway for the last 18 months. The amount relating to 2010 was paid to Faroe in December 2011. Following completion of the Maria/Petoro swap, with the benefits of the Petoro assets for the full year accruing to Faroe, the company is likely to have a small 2011 Norway tax charge. Of the tax rebate for the expenditure to June 2011, a credit of £1.3m has already been recognised in the income statement, the balance being credited to deferred tax liabilities. At June 2011 Faroe had unrelieved UK tax losses of approximately £52.9m. The unrelieved tax losses are available indefinitely for offset against future taxable profits in the UK, with the potential to materially enhance ongoing net results.


Faroe Petroleum | 10 February 12 2012 exploration programme

2012 exploration programme

As outlined above, Faroe is specifically targeting c.175mmbbls in 2012 through six exploration wells. We illustrate this on a risked basis as follows:

Risked 2012 targeted net asset valuation

Prospect Working Interest

CoS% Prospective gross

(mmboe)

Prospective net

(mmboe)

NPV 10% $/bbl

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Butch 15% 30% 54 8 3.00 24.3 7.3 14.7 4.4 2.1 T-Rex 30% 25% 112 34 3.00 100.8 25.2 61.1 15.3 7.2 Kalvklumpen 20% 25% 102 20 3.00 61.2 15.3 37.1 9.3 4.4 North Uist 6% 28% 262 17 3.00 49.5 13.9 30.0 8.4 4.0 Clapton 40% 34% 66 26 3.00 79.2 26.9 48.0 16.3 7.7 Cooper 30% 15% 78 23 3.00 70.2 10.5 42.5 6.4 3.0 Santana 30% 26% 158 47 3.00 142.2 37.0 86.2 22.4 10.6 832 175 527 136 320 82 39


We also provide a breakdown of key statistics for each asset as follows:

Location: Norwegian Sea Working Interest: 15% Partners: Centrica 40% (operator), Suncor Norge AS 30% and Spring Energy Norway AS 15% Timing: Q4 2011 and Q1 2012

Location: Norwegian Sea Working Interest: 30% Partners: Maersk (operator) 70% Timing: Q42011, Q1 2012

Location: Norwegian Sea Working Interest: 20% Partners: DNO 40% (operator) Timing: Q1 2012

Location: UK - West of Shetland Working Interest:6.25% Partners: BP 47.5% (operator), Nexen 35%, Faroe 6.25%, Idemitsu 5%, CIECO 6.25%. Timing: Q1 and Q2 2012

Location: Norwegian Sea Working Interest: 40% Partners: Faroe Petroleum (40% and operator), DNO (10%), Norwegian Energy Company (12%), Lundin (18%) and Dana (20%). Timing: H1 2012

Location: Norwegian Sea Working Interest: 30% Partners: Centrica (operator) and Petro-Canada Timing Q2 and Q3 2012

Location: Norwegian Sea Working Interest: 30% Partners: Wintershall (operator), Centrica, Concedo and Spring Energy AS. Timing: Q4 2012 and Q1 2013

Butch (Drilling)

T-Rex(Drilling)

Kalvklumpen

North Uist

Clapton

Cooper

Santana


Financial model Faroe Petroleum | 10 February 12

Financial model

Income Statement

Year end December (£m)

2009A 2010A 2011E 2012E 2013E

Group revenue 7.0 15.1 159.7 141.8 153.3Cost of sales (9.3) (14.1) (86.3) (89.1) (93.2)Gross profit (2.3) 1.0 73.4 52.7 60.1Total operating expenses (22.7) (20.3) (55.0) (36.8) (37.8)EBIT (25.0) (19.3) 18.4 15.9 22.3Net interest/financial income/(cost) (0.9) (0.9) (1.9) (0.8) (0.8)Associate and Other non-op. income/(cost) 0.0 0.0 0.0 0.0 0.0PBT (11.8) (26.0) 16.4 15.1 21.5Tax 4.9 5.7 (4.7) (3.8) (5.2)Effective tax rate (%) 41.4 21.9 28.6 25.0 24.0Minorities 0.0 0.0 0.0 0.0 0.0Earnings (6.9) (20.4) 11.7 11.3 16.3 EBITDA (3.5) (5.6) 82.2 90.1 91.5Adjusted EBITDA* (21.1) (20.2) 51.2 76.3 79.1Adjusted EBIT* (28.6) (25.2) 18.3 15.9 22.3Adjusted PBT* (11.8) (26.0) 16.4 15.1 21.5Adjusted earnings* (6.9) (20.4) 11.7 11.3 16.3 DPS (p) 0.0 0.0 0.0 0.0 0.0EPS (p) (6.6) (13.3) 5.5 5.3 7.7EPS [F. Dil.] (p) (6.6) (13.3) 5.5 5.3 7.7EPS [Adj.]* (p) (6.6) (13.3) 5.5 5.3 7.7EPS [Adj. F. Dil.]* (p) (6.6) (13.3) 5.5 5.3 7.7Weighted average no. shares (m) 104.7 152.8 212.4 212.4 212.4Fully dil. w. ave. no. shares (m) 104.7 152.8 212.4 212.4 212.4Year end no. shares (m) 104.7 152.8 212.4 212.4 212.4




Faroe Petroleum | 10 February 12 Financial model

Cashflow Statement


2009A 2010A 2011E 2012E 2013E

Operating income (25.0) (19.3) 18.4 15.9 22.3Amortisation of acquired intangibles 14.0 8.6 30.9 13.9 12.4Amortisation of other intangibles 0.0 0.0 0.0 0.0 0.0Depreciation 7.5 5.0 32.9 60.4 56.8Net change in working capital 1.7 8.2 (19.0) 2.6 0.0Other 1.8 8.3 11.2 11.2 11.2Operating cash flow 0.1 10.9 74.5 103.9 102.7 Capital expenditure (4.7) (47.2) (116.1) (85.0) (30.0)Investment in Other intangibles 0.0 0.0 0.0 0.0 0.0Net interest/financial income/(cost) 0.9 1.4 2.3 0.8 0.8Tax paid 30.2 12.4 28.1 (2.3) 0.9Net acqns./disposals 34.0 (46.5) (115.3) (84.5) (29.5)Dividend paid 0.0 0.0 0.0 0.0 0.0Other 0.0 0.0 0.0 0.0 0.0Cash flow before financing 60.4 (69.0) (126.6) (67.0) 44.9 Proceeds from shares issued 0.0 132.0 0.0 0.0 0.0Investments 0.0 0.0 0.0 0.0 0.0Other 0.0 0.0 0.0 0.0 0.0Net movement in cash/(debt) 60.4 63.0 (126.6) (67.0) 44.9 Opening net cash/(debt) 16.7 43.6 132.2 104.8 88.0Adjustments (Forex, etc.) (1.5) 1.1 0.3 0.0 0.0Closing net cash/(debt) 43.6 132.2 104.8 88.0 128.1 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E 2012E 2013E

Property plant and equipment 13.7 9.8 43.8 50.8 50.8Goodwill and Acquired intangibles 0.0 0.0 0.0 0.0 0.0Other intangibles 65.0 102.7 104.5 107.1 50.3Other fixed assets 0.0 0.0 0.0 0.0 0.0Non current assets 78.8 112.5 148.2 157.9 101.0 Stocks & WIP 0.5 0.6 26.3 15.7 15.7Trade receivables 6.0 7.5 10.0 6.0 5.9Cash 43.6 132.2 104.8 88.0 128.1Other current assets 12.7 28.1 0.0 0.9 0.0Current assets 62.7 168.4 141.1 110.6 149.7 Total assets 141.5 280.9 289.3 268.5 250.8 Trade creditors 12.5 20.9 29.9 17.9 17.8Short term borrowings 22.7 17.6 13.2 13.2 13.2Long term borrowings 0.0 0.0 0.0 0.0 0.0Other liabilities 32.1 61.2 74.7 72.5 77.7Total liabilities 67.3 99.7 117.8 103.5 108.7 Net assets 74.2 181.1 171.5 164.9 142.1 Issued share capital 10.5 21.2 21.2 21.2 21.2Share premium account 91.6 205.9 205.9 205.9 205.9Retained earnings (33.6) (52.3) (63.9) (70.5) (93.3)Other reserves 5.8 6.3 8.2 8.2 8.2Minority interests 0.0 0.0 0.0 0.0 0.0Total equity 74.2 181.1 171.5 164.9 142.1



Financial model Faroe Petroleum | 10 February 12

Key Ratios

Year end December

2009A 2010A 2011E 2012E 2013E

Revenue growth (%) n/a 115.4 958.5 (11.2) 8.1Adj. EBITDA* growth (%) n/a (4.5) (353.7) 49.0 3.8Adj. EBIT* growth (%) n/a (12.0) (172.5) (13.0) 40.2Gross margin (%) (32.5) 6.5 46.0 37.1 39.2Adj. EBITDA* margin (%) (301.5) (133.7) 32.1 53.8 51.6Adj. EBIT* margin (%) (408.4) (166.9) 11.4 11.2 14.5 Gearing (%) n/a n/a n/a n/a n/aInterest cover (x) (32.3) (29.5) 9.7 20.5 28.3Net debt/Adj. EBITDA* (x) (2.1) (6.6) 2.0 1.2 1.6Dividend cover (x) n/a n/a n/a n/a n/a ROE (%) (9.3) (11.2) 6.8 6.9 11.5ROIC (%) (147.6) (43.1) 10.1 13.3 54.5ROCE (%) (147.6) (43.1) 10.1 13.3 54.5 Operating cash conversion (%) (2.1) (193.1) 90.6 115.3 112.3Net cash conversion (%) (874.8) 339.1 (1,082.8) (590.6) 274.9Net working cap / revenue (%) 24.4 54.4 (11.9) 1.8 0.0Cap Ex / revenue (%) 66.9 312.9 72.7 60.0 19.6



Valuation Metrics

Year end December

2009A 2010A 2011E 2012E 2013E

PER (x) (25.6) (12.7) 30.7 31.6 21.9EV / Revenue^ (x) 43.3 20.1 1.9 2.1 2.0EV / Adj. EBITDA^* (x) (14.4) (15.0) 5.9 4.0 3.8EV / Adj. EBIT^* (x) (10.6) (12.0) 16.6 19.1 13.6EV / IC^ (x) 4.1 1.7 1.8 1.8 2.1EV / Taxed Adj. EBIT^* (x) (14.0) (15.8) 21.9 25.1 17.9 Yield (%) 0.0 0.0 0.0 0.0 0.0P / CFPS (x) 2.9 (3.7) (2.8) (5.4) 8.0NAV per share (p) 70.8 118.6 80.8 77.6 66.9





Faroe Petroleum | 10 February 12 Financial model


0

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150

200

250

300





On the front line

Following the successful restructuring of its balance sheet in 2011, Frontera has started its two year development plan at three fields in Georgia. Since then the company has made progress and is gearing up to start gas sales in April. We feel that the company is well placed to meet its production target of 5,000bbl/d in 18 months.

Development underway The two-year plan started in September 2011 and has already yielded a gas discovery at Mtsare Khevi. Oil production continues at 220bbl/d and the company has 300boepd of gas production shut in and due to come to market in April. Given these initially positive results, we are comfortable that the company can meet its goal of 5,000bopd within the two development timeframe.

Balance sheet restructured, funding is available Last year saw the conversion of 85% ($91.1m) of the company’s debt being converted into equity as well as raising $11m of new money. The company has recently drawn down a $3.1m loan using its SEDA facility to pay for its development activities. Frontera has yet to tap into the $250m cost recovery pool given that production has yet to ramp up. Again we are comfortable for now that sufficient capital is available to the company to fund its future activities.

Overhangs could still be an issue With c.2.2 billion shares in issue as well as several large holding, long suffering shareholders, there remains potential for large overhanging sell orders in this stock in future. Clearly such circumstances would depress the share price again.

Valuation and recommendation Frontera’s share price has been very weak since the placing (at 4p) last year due to a substantial share overhang in the market, which has now been cleared out. However, the company has made good progress with its development project so far, but has yet to benefit from any increase in production so far. The share price should be driven by positive production news over the next 18 months. We therefore initiate coverage with a Buy recommendation and set an 18 month of Target Price of 8p. We have not included a valuation for the exploration assets as there is no work plan or funding for them, but these could add significantly to the valuation once they come into play.


10 February 12 | Initiation of coverage | Oil & Gas

Frontera Resources(AIM:FRR)1,5

BUY Share price 1p



Net debt (£m) 61.1


No. of shares (m) 2,070.7

Free float (%) 75.0



(%) 1m 3m 12m

Absolute -20.8 -25.9 -79.9

FTA relative -24.0 -30.7 -79.6


0

5

10

15

20


Price Relative

Source: Datastream


Next news Block 12 operational updates

Business Oil exploration & development

www.fronteraresources.com


Year end December

Revenue($m)

EBIT*($m)

PBT*($m)

Tax(%)

Adj. EPS* (c)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 4.1 (18.0) (28.5) 0.0 (0.3) (5.2) (7.3) 0.02010A 8.3 (52.8) (63.9) 0.0 (0.5) (3.4) (2.5) 0.02011E 48.0 32.1 16.1 0.0 0.0 206.2 4.1 0.02012E 146.6 123.0 108.9 0.0 0.1 30.5 1.1 0.02013E 196.7 166.2 154.0 0.0 0.1 21.6 0.8 0.0





Frontera Resources | 10 February 12 Valuation and recommendation


We value Frontera using a combination of a Discounted Cash Flow (DCF) of the company’s producing assets as well as a risked approach to its exploration portfolio. We have incorporated the following assumptions into our approach:

Assumptions incorporated

Metric Assumption

Forecast oil price/bbl $95 flat Forecast gas price/mcf $4 flat Discount rate 10% FRR profit oil sharing ratio 49% flat NAV for resources/mmboe $5 Long term exchange rate ($/£) 1.65/1 Post placing no. of shares 2,039m


In terms of the company’s exploration portfolio, we have valued Frontera’s contingent and prospective resources individually. The company has an active drilling campaign over the next 18 months, which should see current prospective resources reclassified to contingent resources through continued appraisal work.

Exploration asset valuation

Asset Classification Risked NPV (£m)

Risked NPV (p/share)

Shallow Fields Prodution Unit Contingent Resources 8.2 4.0 Basin Edge Play Prospective Resources 176.1 8.5 Taribani Field Play Prospective Resources 89.5 4.3 Other Prospective resources Prospective Resources 68.0 3.3 341.8 20.1


Our target valuation does not currently recognise prospective resources given the additional work needed to classify the assets to contingent and reserves. However these will be recognised as and when Frontera successfully appraises these plays.

Our sum of the parts (SOTP) matrix will encompass a DCF of Block 12 as the company continues to push forward with its development plan with the aim of reaching 5,000bbl/d by 2H 2013.


£m p/share

Core assets 234.6 11 3P Reserves (Taribani) 89.5 4 Gross Value 324.2 16 Less: G&A -52.5 -3 Net value 271.6 13 Less: Net debt -104.9 -5 Overall Target Price 166.8 8 Source: Seymour Pierce Ltd

We value Frontera using a combination of a

Discounted Cash Flow (DCF) of the company’s

producing assets as well as a risked approach to

its exploration portfolio. We have incorporated

the following assumptions into our approach:


Valuation and recommendation Frontera Resources | 10 February 12


12

4

-3

-5

-10

-5

0

5

10

15

20

Net debt G&A Contingent resources Block 12 productionp/

shar

e



Frontera’s share price has been very weak since the placing (at 4p) last year, due to a substantial share overhang in the market, which has now been cleared out. However, the company has made good progress with its development project so far, but has yet to benefit from any increase in production so far. After a prolonged period in stasis due to its poor balance sheet structure, this looks like a company on the turn for the better. Share price should be driven by positive production news over the next 18 months. We therefore initiate coverage with a Buy recommendation and set an 18 month target price of 8p.

We have not included a valuation for the exploration assets as there is no work plan or funding for them, but these could add significantly to the valuation once these come into play.

We have not included a valuation for the

exploration assets as there is no work plan or

funding for them, but these could add

significantly to the valuation once these come

into play.


Frontera Resources | 10 February 12 Valuation and recommendation

Asset overview

The company has a 100% interest in Block 12 which has an area of c.5,060km2 and is estimated to have in excess of 2bnbbl of resources.

Block 12 plays


Development

Frontera has started a two-year development programme on three fields located in Block 12, which should result in production ramping up from c.225bbl/d to c.5,000bbl/d. The company has estimated that this programme will cost c.$120m which will be funded from operating cash flow, the c.$250m cost recovery pool and potentially using their equity draw down facility.

Historic & forecast production profile

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Q1 2010 Q3 2010 Q1 2011 Q3 2011 Q1 2012 Q3 2012 Q1 2013 Q3 2013 Q1 2014 Q3 2014

Dai

ly p

rodu

ctio

n (b

opd)


The development of the Tarabani, Mirzaani and Mtsarekhevi fields will be achieved through a combination of drilling, fracturing, water injection and downhole pumps. The company has found that fracturing is crucial to ensure commercial flow rates


Valuation and recommendation Frontera Resources | 10 February 12

Exploration

The company does not intend to conduct any exploration during the two year development programme. It intends to fund such activity once the company is self funding after year two. The company has identified two major exploration plays: the Basin Edge Play (BEP) and shale gas.

BEP This is one of the latest exploration plays in the Kura Basin and is located to the north of the block. Frontera has identified two (B and C) potentially giant prospects. 2D and 3D seismic indicates that the C prospect could contain in excess of 500mmbbl.

Shale Gas In 2010, Frontera conducted an internal study which identified major liquids and gas associated with the Maykop shales. The company feels that the geology is similar to that found in Europe and North America. Their internal estimate is 1tcf of recoverable gas and up to 500mmbbl. This play would be a long term development project and may be of sufficient scale to attract a farm-in partner with the technological expertise required for such a development.


Frontera Resources | 10 February 12 Financial model

Financial model

Income Statement


2009A 2010A 2011E 2012E 2013E

Group revenue 4.1 8.3 48.0 146.6 196.7Cost of sales (5.2) (6.1) (6.5) (14.4) (17.6)Gross profit (1.1) 2.2 41.5 132.2 179.2Total operating expenses (20.1) (16.0) (15.1) (23.0) (26.2)EBIT (21.2) (13.8) 26.4 109.2 153.0Net interest/financial income/(cost) (11.5) (14.8) (16.6) (14.1) (12.2)Associate and Other non-op. income/(cost) 0.9 3.7 0.6 0.0 0.0PBT (28.5) (63.9) 16.1 108.9 154.0Tax 0.0 0.0 0.0 0.0 0.0Effective tax rate (%) 0.0 0.0 0.0 0.0 0.0Minorities 0.0 0.0 0.0 0.0 0.0Earnings (28.5) (63.9) 16.1 108.9 154.0 EBITDA (20.3) (13.3) 27.2 109.8 157.4Adjusted EBITDA* (17.5) (52.6) 32.5 123.3 168.4Adjusted EBIT* (18.0) (52.8) 32.1 123.0 166.2Adjusted PBT* (28.5) (63.9) 16.1 108.9 154.0Adjusted earnings* (28.5) (63.9) 16.1 108.9 154.0 DPS (c) 0.0 0.0 0.0 0.0 0.0EPS (c) (0.3) (0.5) 0.0 0.1 0.1EPS [F. Dil.] (c) (0.3) (0.5) 0.0 0.1 0.1EPS [Adj.]* (c) (0.3) (0.5) 0.0 0.1 0.1EPS [Adj. F. Dil.]* (c) (0.3) (0.5) 0.0 0.1 0.1Weighted average no. shares (m) 91.0 132.4 2,039.0 2,039.0 2,039.0Fully dil. w. ave. no. shares (m) 91.0 132.4 2,039.0 2,039.0 2,039.0Year end no. shares (m) 91.0 132.4 2,039.0 2,039.0 2,039.0




Financial model Frontera Resources | 10 February 12

Cashflow Statement


2009A 2010A 2011E 2012E 2013E

Operating income (21.2) (13.8) 26.4 109.2 153.0Amortisation of acquired intangibles 0.5 0.3 0.4 0.3 2.2Amortisation of other intangibles 0.0 0.0 0.0 0.0 0.0Depreciation 0.5 0.3 0.4 0.3 2.2Net change in working capital (0.6) 5.7 151.9 206.9 105.6Other 0.0 0.0 0.0 0.0 0.0Operating cash flow (20.9) (7.6) 179.1 316.7 262.9 Capital expenditure (8.3) (4.3) (36.2) (52.8) (53.2)Investment in Other intangibles 0.0 0.0 0.0 0.0 0.0Net interest/financial income/(cost) 9.8 12.9 15.9 18.8 21.9Tax paid 0.0 0.0 0.0 0.0 0.0Net acqns./disposals (8.3) (4.3) (36.2) (52.8) (53.2)Dividend paid 0.0 0.0 0.0 0.0 0.0Other 1.9 8.1 0.0 0.0 0.0Cash flow before financing (25.8) 4.9 122.6 229.9 178.4 Proceeds from shares issued 7.1 0.0 0.4 0.0 0.0Investments 0.0 0.0 0.0 0.0 0.0Other 3.0 (2.8) 2.6 1.0 (1.0)Net movement in cash/(debt) (15.7) 2.1 125.7 230.9 177.4 Opening net cash/(debt) 7.3 0.8 0.2 152.0 435.4Adjustments (Forex, etc.) 0.0 0.0 0.0 0.0 0.0Closing net cash/(debt) 0.8 0.2 152.0 435.4 667.1 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E 2012E 2013E

Property plant and equipment 1.6 1.2 1.1 1.1 1.1Goodwill and Acquired intangibles 0.0 0.0 0.0 0.0 0.0Other intangibles 48.0 7.9 43.5 95.7 144.5Other fixed assets 3.7 2.3 1.6 1.6 1.6Non current assets 53.3 11.4 46.1 98.4 147.2 Stocks & WIP 7.4 5.0 89.8 81.3 105.0Trade receivables 0.6 0.2 15.7 28.5 36.8Cash 0.8 0.2 152.0 435.4 667.1Other current assets 9.0 0.2 9.0 16.3 21.0Current assets 17.8 5.6 266.5 561.4 829.9 Total assets 71.1 17.0 312.7 659.8 977.1 Trade creditors 0.8 3.1 44.9 81.3 105.0Short term borrowings 9.5 5.9 97.1 95.0 94.0Long term borrowings 107.4 115.2 40.2 62.1 84.0Other liabilities 2.2 3.8 224.6 406.6 525.2Total liabilities 119.8 127.9 406.9 645.1 808.3 Net assets (48.7) (110.9) (94.2) 14.7 168.8 Issued share capital 0.0 0.0 0.0 0.0 0.0Share premium account 170.7 172.3 172.9 172.9 172.9Retained earnings (218.8) (282.7) (266.6) (157.6) (3.6)Other reserves (0.6) (0.6) (0.6) (0.6) (0.6)Minority interests 0.0 0.0 0.0 0.0 0.0Total equity (48.7) (110.9) (94.2) 14.7 168.8




Key Ratios

Year end December

2009A 2010A 2011E 2012E 2013E

Revenue growth (%) n/a 100.2 481.8 205.2 34.2Adj. EBITDA* growth (%) n/a 200.2 (161.9) 279.3 36.5Adj. EBIT* growth (%) n/a 194.1 (160.8) 283.1 35.1Gross margin (%) (26.2) 26.2 86.4 90.2 91.1Adj. EBITDA* margin (%) (424.5) (636.7) 67.7 84.1 85.6Adj. EBIT* margin (%) (435.5) (639.8) 66.9 83.9 84.5 Gearing (%) n/a n/a n/a n/a n/aInterest cover (x) (1.6) (3.6) 1.9 8.7 13.7Net debt/Adj. EBITDA* (x) (0.0) (0.0) 4.7 3.5 4.0Dividend cover (x) n/a n/a n/a n/a n/a ROE (%) 58.5 57.6 (17.1) 738.7 91.3ROIC (%) (343.9) (1,495.1) 44.6 206.3 289.5ROCE (%) (343.9) (1,495.1) 44.6 206.3 289.5 Operating cash conversion (%) 103.1 56.9 658.5 288.4 167.1Net cash conversion (%) 90.3 (7.7) 759.6 211.1 115.8Net working cap / revenue (%) (15.2) 69.6 316.2 141.1 53.7Cap Ex / revenue (%) 201.1 51.7 75.3 36.0 27.0



Valuation Metrics

Year end December

2009A 2010A 2011E 2012E 2013E

PER (x) (5.2) (3.4) 206.2 30.5 21.6EV / Revenue^ (x) 31.6 15.8 2.7 0.9 0.7EV / Adj. EBITDA^* (x) (7.4) (2.5) 4.0 1.1 0.8EV / Adj. EBIT^* (x) (7.3) (2.5) 4.1 1.1 0.8EV / IC^ (x) (2.6) (1.2) (0.5) (0.3) (0.3)EV / Taxed Adj. EBIT^* (x) (7.3) (2.5) 4.1 1.1 0.8 Yield (%) 0.0 0.0 0.0 0.0 0.0P / CFPS (x) (0.1) 0.4 0.3 0.1 0.2NAV per share (c) (53.5) (83.8) (4.6) 0.7 8.3





Financial model Frontera Resources | 10 February 12


0

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4

6

8

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16

18





Kurds and wahey 2012 will see the company move into export production for the first time, resulting in the first significant cash inflows for GKP. The entrance of ExxonMobil and Total into the region has enhanced its credibility as a potential major future oil producing province. We feel that the persistent take over rumours are premature, but likely to be accurate in the longer term.

Production – ramping up and moving into export The Shaikan field has been producing varying, modest amounts of oil during drilling and flow testing. The company is now in the final stages of installing facilities which will allow up to 20,000bopd of production under an extended flow test. Previous production has been sold into the domestic market at a substantial discount (c.$43/bbl in 2011). However, this new production will be exported and sold at international pricing, resulting in significant revenue for the first time.

Exploration – more upgrades to come? In parallel with the Shaikan development, GKP has several potentially high impact wells at other locations in Kurdistan. GKP has again updated its resource numbers on the back of successful drilling. On the assumption of positive results, we would anticipate resource upgrades soon after, further enhancing valuation.

Outstanding issues – not without risk Investors need to be aware of a number of geopolitical issues with respect to Kurdistan. Despite being well advanced, the new Iraqi oil laws have still not been passed. Consequently, the Kurdistan Regional Government (KRG) is unable to sanction oil exports without central government agreement. Following the exit of the US armed forces, tensions are high in Iraq due to sectarian violence, which some commentators have speculated may lead to civil war. In addition, tensions with Turkey are currently at a higher level due to the accidental bombing of Kurdish civilians. GKP also have legal issues with Excalibur Ventures, who claim to have ownership rights at Shaikan. Court proceedings are due to start in October 2012.

Valuation and recommendation We have valued GKP on a DCF basis for its forecast production from the Shaikan field. This yields a core valuation of 31p, excluding cash. We have also included a risked exploration NAV for the other early stage assets which yields an additional 317p. We therefore initiate coverage with a Buy recommendation and set an overall target price of 374p. A draft of this research has been shown to the company following which minor factual amendments have been made.


Gulf Keystone Petroleum(AIM:GKP)1

BUY Share price 343p


Market cap (£m) 2,928.0

Net cash (£m) 15.4

Enterprise value^ (£m) 2,912.6




(%) 1m 3m 12m

Absolute +28.4 +159.0 +104.8

FTA relative +23.2 +142.3 +108.2


050

100150200250300350400


Price Relative

Source: Datastream


Next news Shaikan field operational update

Business Based in Kurdistan, Northern Iraq. Primarily

focused on exploration, but has a small amount

of production from the Shaikan field.

www.gulfkeystone.com/


Year end December

Revenue(£m)

EBIT*(£m)

PBT*(£m)

Tax(%)

Adj. EPS* (p)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 84.4 28.6 27.8 0.0 23.3 7.5 2.9 0.02010A 115.6 45.5 44.7 (0.0) 36.9 4.7 1.8 0.02011E 145.1 78.3 78.0 0.0 48.7 3.6 1.1 0.02012E 15.3 (101.5) (101.3) 0.0 (83.1) (2.1) (0.8) 0.02013E 15.0 (115.6) (115.7) 0.0 (94.9) (1.8) (0.7) 0.0

* excludes exceptional items and amortisation of acquired intangibles.^ EV calculation adjusted for core cash, investments etc. Source: Seymour Pierce Ltd


Gulf Keystone Petroleum | 10 February 12 Valuation and recommendation


We have valued Gulf Keystone in terms of its discovered resource base under the low estimate scenario stated in the most recent CPR, and have not included estimates for yet-to-find resources. In addition, we have included a discounted cash flow (DCF) valuation of GKP’s current and forecast production (2012: c.10,000bopd ramping up to 2014: c.40,000bopd) from its Shaikan field in Kurdistan. We have used the following headline assumptions in our valuation:


Metric Assumption

NPV/mmboe - Oil $3.60 Realised oil price (export) 50% of export - 2012: $100/bbl, 2012+: $90/bbl

flat Realised oil price (domestic) $44.3/bbl flat to 2014 % production (export/domestic) 50%/50% from 2014 % production (export/domestic) 0%/100% Long-term $/£ 1.65 Discount rate 10% Shares outstanding (million) 854.12 Shaikan interest post KRG back in 54.4% Oil recovery factor 20%


Risked exploration net asset value

Block 90% 50% 10% Mean Expected Outcome

Working Interest

Recovery factor

$ NPV/bbl Net Unrisked $ billion

Net risked $ billion

Net risked£ billion

p/shr

Bn bbl Low Best High

Shaikan 8.0 13.4 15.0 10.5 10.3 51.0% 20.0% 3.6 15.7 3.1 1.9 222 Akri-Bijeel 2.6 2.2 12.8% 20.0% 3.6 1.2 0.2 0.1 17 Sheikh-Adi 1 1.9 3 1.9 2.1 80.0% 20.0% 3.6 5.5 1.1 0.7 78

Total 9.0 17.9 18.0 12.4 14.6 22.3 4.5 2.7 317


We have included Akri-Bijeel in the above valuation, even though the company intends to sell the asset (announced in September 2011) to focus on their core Shaikan activities. Our valuation indicates a risked value of $200m attributable to the play, but we would expect that the company would expect a consideration to be in excess of this amount to fund further exploration and development at Shaikan.


£ million p/share

Production 268 31 Discovered 2C 2,708 317 Gross Value 2,975 348 Less: G&A (40) (5) Net Value 2,936 344 Net Cash 256 30 Target Market Cap/ Price 3,191 374 Source: Seymour Pierce Ltd

Our DCF analysis of GKP’s Shaikan production assumes production starts to ramp up in 2012 at an average rate of c.10,000bopd ramping up to c.40,000bopd in 2014. Whilst revenues generated from this level of production will be large, they are unlikely

We have valued Gulf Keystone in terms of its

discovered resource base under the low estimate

scenario stated in the most recent CPR


Valuation and recommendation Gulf Keystone Petroleum | 10 February 12

to be sufficient to support development capex for a 400,000bopd development. Full development of Shaikan will require a multi-billion dollar investment over the life of the project. Therefore, we feel the likelihood is that GKP will exit the field once it has fully defined the asset base, to ensure the greatest possible value prior to an eventual sale to a major oil company looking to enter the region.


317

3130

-5

-50

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300

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400

G&A Net Cash Production Discovered 2C

p/sh

are


Other issues impacting valuation

Although GKP currently has a 75% working interest in Shaikan, under the PSC terms the company has an obligation to assign part of this interest back to the KRG once the asset enters the development stage. This will ultimately reduce GKP’s stake in Shaikan to 51% (excluding the 3.4% Texas Keystone stake) and any eventual sale will be valued on this basis. We have assumed this long term interest in our valuation.

In addition, GKP’s ongoing litigation with Excalibur Ventures continues to weigh on the company’s shares. This protracted legal dispute stems from a claim that Excalibur is entitled to 30% of the company’s blocks in Kurdistan as a result of a collaboration agreement with GKP prior to entry into Iraq. The lawsuit is due to be heard in London in October 2012, and we feel a negative resoultion for GKP will have a major downward impact on the company’s valuation.


We have valued GKP on a DCF basis for its forecast production from the Shaikan field. This yields a core valuation of 31p, excluding cash. We have also included a risked exploration NAV for the other early stage assets which yields an additional 317p. We therefore initiate coverage with a Buy recommendation and set an overall target price of 374p.

We therefore initiate coverage with a Buy

recommendation and set an overall target price

of 374p.


Gulf Keystone Petroleum | 10 February 12 Strategy Overview

Strategy Overview

GKP listed a series of objectives in their 2011 interim results for their forward strategy for the next two years. We feel it is important to analyse these in detail to determine whether they are value accretive for shareholders, and whether failure to meet them will result in any material downside.

1) Explore and appraise aggressively the Shaikan, Sheikh Adi and Ber Bahr blocks in the Kurdistan Region of Iraq to prove up the resource base with increased production to follow.

In our view, GKP’s core strategy will focus on fully appraising the Shaikan field to ultimately ensure that maximum resources are re-classified to reserves, prior to any potential farm out, placing or company sale. The company has benefited from a series of upgrades since 2010 through a continued appraisal work post initial discovery.

Resource upgrade history

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DGA (Jan-10) Ryder Scott (Jan-11) DGA (Apr-11) DGA (Nov-11)

Gro

ss o

il-in

-pla

ce (b

nbbl

)

P10 P50 P90

Source: DGA and Ryder Scott

The company currently has sufficient funds in the short term to appraise its assets. In addition to the $134m cash position confirmed in the company’s interim results, GKP undertook a $200m placing issuing 91m shares at 140p in September 2011, underlining shareholder support for the company’s strategy. The funds will be specifically distributed for the following:

• Completing the Front End Engineering and Design for the company's pipeline capable of transporting a minimum of 440,000 bopd from the Shaikan field to the existing Kirkuk-Ceyhan export pipeline

• Ordering of long lead items for the construction of the company's dedicated pipeline, subject to necessary approvals

• Upgrading the Shaikan Extended Well Test facilities to increase existing production from Shaikan-1 and 3 to 20,000 bopd

• Building additional testing and production facilities for Shaikan-2 and 4 capable of producing 20,000 bopd, following successful well tests at Shaikan-2 and in anticipation of positive results from Shaikan-4

• Drilling of the second exploration well on the Sheikh Adi block

• Acquisition of 3D seismic data over the Ber Bahr block where the first exploration well was spud in October 2011.


Strategy Overview Gulf Keystone Petroleum | 10 February 12

Nevertheless, it should be noted that Shaikan alone is potentially a multi-billion dollar field which will require a capital commitment that exceeds GKP’s current, and in our view, future capabilities. As such, we feel that the asset will either be significantly farmed out or even fully sold once the company has appraised the asset to an extent where it feels it has reach an appropriate valuation.

2) Complete the preparation of the Shaikan Field Development Plan for submission and approval by the Ministry of Natural Resources of the Kurdistan Regional Government

The Shaikan appraisal programme is being completed in parallel with the ongoing work on the Shaikan field development plan. This is a procedural requirement that is necessary for the company to proceed with its operations in Kurdistan.

The plan includes pre-project economics and partner support, as well as the procurement of other technical requirements to fully enable the company to carry out its activities.

Given that the company has been active in the region since 2005, we do not expect any issues to arise over its approval and merely regard it as a formality. Nevertheless, failure to gain approval will limit GKP’s progress and subsequently be detrimental to the company’s value.

3) Implement sufficient infrastructure to ramp up production from the Shaikan field as well as improve existing facilities

GKP is in the process of upgrading its infrastructure at Shaikan to increase production under the terms of its current licence to conduct an extended well test “EWT” at the Shaikan 1 & 3 well. Production is forecast to ramp up to c.20,000bopd and is intended for the export market, where the company can benefit from slightly discounted (due to the oil being heavy and high in hydrogen sulphide) international price rather than the domestic price.

The company has identified a route for a dedicated pipeline to connect the Shaikan Field to the Kirkuk-Ceyhan export pipeline. GKP has completed a feasibility study on a pipeline capable of transporting a minimum of 440,000bopd, which is being submitted for necessary comments and approvals. Once the necessary approvals have been obtained, Front End Engineering and Design (FEED) work and ordering of long lead items will commence. There is currently no timeline for this process and no approvals have yet been made - we assume that this will be a long term objective for the company.

Due to the company’s substantial cash position (outlined above) we feel GKP is fully capable of upgrading its EWT facility and building additional testing and production facilities for Shaikan-2 & 4, and are confident the company will scale up production as a result of this. However, whilst production from the EWT is substantial it is not “commercial” production which is the point where the KRG and GKP’s interest falls to 51%. We therefore expect production to plateau at c.20,000bopd in the medium term.

4) Actively pursuing a move from AIM to a Premium Listing on the Official List of the London Stock Exchange, subject to obtaining necessary approvals

We feel this proposal serves to address two key areas of the market’s view of GKP. Firstly, that the company has a view to be acquired in the short to medium term - an ongoing rumour that management have had to contend with on several occasions. Secondly, that the company does not receive the necessary market exposure on AIM, especially given the size of its operations.


Gulf Keystone Petroleum | 10 February 12 Strategy Overview

It is clearly easier and cheaper to raise capital through placings on AIM than the Main Board, and as such we were not surprised with GKP’s September placing prior to a full listing. We also feel that moving to the official list will add further clout to the company’s position in the market which in our view addresses the second issue.

Furthermore, this strategy suggests that the company will pursue a farm-out of its Shaikan operations, as opposed to a company sale given that the acquisition of a Main Board constituent presents additional challenges for the aquiree. In addition, it further highlights management’s commitment to the company, an issue that has been historically questioned.

5) Appointment to the Board of three additional high-calibre Non-Executive Directors

We feel this objective is an extension of the company’s move to the official list. Since the announcement the company has appointed two NEDs - Lord Charles Guthrie and Mark Hanson – two experienced and complementary candidates. In line with GKP’s strategy we would expect a further appointment, although given that the company can already satisfy the UK Listing Authority’s requirements relating to NEDs on admission to premium listing, we do not feel a further appointment or even non appointment will have any impact on valuation.

6) The company has made a strategic decision to rationalize its asset portfolio and is to seek a buyer for its 20% interest in the Akri-Bijeel block

GKP’s intention to sell its non-core interests so that it can focus on Shaikan has been known for some time. This strategy will yield the funds required to further appraise the field and to allow for a ramp up in production to supply the export market. We feel that this approach reduces the chance of GKP returning to the market to raise additional funds in the short term. The license currently contains one 2.6bnbbl discovery and another drilling prospect with management estimating the possibility of an 8bnbbl discovery. If we use a similar valuation to that applied to our risked net asset exploration appraisal, we would value Akri-Bijeel as follows:

Therefore, using a range of valuations by flexing the recovery factor of the field, we estimate that GKP’s interest in Akri-Bijeel could generate a consideration between $200m and $720m. However, other factors such as GKP’s open desire to sell as well as the ongoing geo-political factors (see below) associated with the asset may impact any purchaser’s assessment.

The company maintains that it is selling its stake not because it is relatively small, but because it is immaterial to the company compared with the exploration potential of its Ber Bahr license and the appraisal of its Shaikan discovery.

GKP has just commenced the process to auction the stake and estimates that a deal could be concluded in Q1 2012. In addition the company is confident of a quick sale due to the high level of interest in the Kurdistan region from large oil companies.


Strategy Overview Gulf Keystone Petroleum | 10 February 12

Timeline Company milestones

Appraisal and early development of exploration successes on o ther

blocks

Build the pipeline

M ove to the Shaikan full field development

M ove from resources to reserves

Complete and submit the Shaikan Field Development Plan

M ove to the Premium Listing on the Official List o f the London

Stock Exchange

Finalise strategic divestment of 20% working interest in Akri-B ijeel

Ber Bahr-1 uncommercial

Upgrade the Shaikan Extended Well Test production facilities

Shaikan-7 to target the Permian

Shaikan-6 to spud

Further testing and drilling on Akri-B ijeel

Ber Bahr-1 un-commercial

Work ongo ing on the Shaikan Field Development P lan

Shaikan o il-in-place upgrade

Shaikan-5 spudded

Shaikan-4 drilling

Shaikan-2 testingIncrease production to 10,000-

20,000 bopd

Design additional production facilities

Ramp up Shaikan o il exports

Design pipeline to connect Shaikanto the Kirkuk-Ceyhan

export pipeline

Sheikh Adi-2 to spud2011 2012 2013 2014


The company has a busy period over the next two years to implement and sustain its ambitious forward strategy. However we feel that its targets are achievable given the company’s financial position as well as its proven operational capabilities.


Gulf Keystone Petroleum | 10 February 12 Progression of regional politics

Progression of regional politics

Kurdistan became an autonomous state within Iraq following the first Gulf war in 1992. It has its own parliament and exerts control over all areas of policy (except for national defence and foreign affairs). Of the 325 seats in the Iraqi Parliament, the Kurdish Alliance has a sizeable presence, holding nearly 15% of the seats and was in fact crucial to the formation of the government.

Prior to the formation of the current government, Kurdistan was in dispute with Iraq's central government in Baghdad on several issues: a land dispute centred on the ethnically-mixed oil-rich city of Kirkuk, the distribution of revenues from the region's energy reserves and the legality of Kurdistan awards of oil licences. These issues had created uncertainty for both investors and oil companies active in Kurdistan.

Despite a growing oil export production profile, the central government prohibited oil exports from Kurdistan. However, agreement has now been given to produce 100,000bopd rising to 200-300,000bopd by the end of 2011. Of this volume, about a third could be exported according to the Kurdish Natural Resources Minister.

Discovered oil & gas fields - Kurdistan

Source: Shamaran Petroleum


Key asset overview Gulf Keystone Petroleum | 10 February 12

Key asset overview

Shaikan Block

The Shaikan field is located 85km to the north-west of of the Kurdistan capital Erbil and covers an area of 283km². The Production PSC for the block was awarded in November 2007 to Gulf Keystone Petroleum International and became operator with 75% working interest. However, (as noted in the valuation section) under the terms of the PSC, the KRG has an option to back in to the Shaikan asset should it be deemed commercial. This would result in GKP's interest falling to 51%.

Shaikan field

Source: Company

Shaikan-1 discovery well The Shaikan discovery was announced in August 2009 with the well reaching a total depth of 2,950m through multiple target horizons in located Cretaceous, Jurassic and Triassic formations. The well encountered a 1,000m gross oil column with over 200m of net pay. The well was retesting in July 2010 and subsequently completed as a first Jurassic zone producer.

Shaikan EWT facilities were completed in September 2010 with test production from Shaikan-1 commencing the following month; net entitlement sales were 54,201bbl to March 2011. GKP is waiting for a response from the KRG relating to future oil sales.

Shaikan-2 appraisal well Shaikan-2 deep appraisal well was spudded in December 2010 and was successfully tested in March 2011. The test showed that rates of up to 10,000bopd were achievable. Shaikan-2 tested 26o API oil in the first Jurassic zone encountered at a stabilised rate of 8,064bopd.

Shaikan-3 appraisal well Shaikan-3 shallow appraisal well was spudded in September 2010 and was completed as a second Jurassic producer in January 2011. Following acid treatment of the Shaikan-1 and Shaikan-3 wells in early 2011 a combined production rate of up to 20,000bopd was achieved. Both Shaikan-1 and Shaikan-3 are tied to the EWT facilities, which are being upgraded to meet the higher production rate and increased storage requirements. The facilities will now also process the oil to meet export specifications. The company is currently examing the potential for a 440,000bopd


Gulf Keystone Petroleum | 10 February 12 Key asset overview

pipeline. It has initiated an engineering study for a pipeline route to the main Kirkuk-Ceyhan oil export line.

Shaikan-4 appraisal well Shaikan-4 deep appraisal well was spudded in May 2011 using the Discoverer 4 rig. The well is targeting the top of the Permian interval and is expected to reach a total depth of c.3,760m.

Other appraisal wells The location for the Shaikan-5 appraisal well has been completed while the plans for Shaikan-6 and 7 appraisal wells have not yet been finalised.

Sheikh Adi Block

This block is 180km² and located to the west and on trend with the Shaikan structure. The PSC for the Sheikh Adi block was awarded in July 2009 to GKP, who are the operator and have a pre-KRG back in working interest of 80%. The KRG has a 20% carried interest in the PSC.

Sheikh Adi location map


The initial three year exploration phase commenced in July 2009 and is due to expire in July 2012. However, we expect this to be extended. The first exploration well (Sheikh Adi-1) was spudded on 4 August 2010. Sheikh Adi-1 drilled through the Cretaceous, Jurassic and Triassic formations to total depth of approximately 3,780m.

In 2010, acquisition of 215km² of 3D seismic data for the Sheikh Adi block commenced and was completed in early 2011 with the data now being processed.

The current resource estimate for Sheikh Adi structure is currently 1.9bn bbls (P50) or 3bn bbl (P10). Further drilling is required in the block in order to tighten up the resource estimate (in our view).


Key asset overview Gulf Keystone Petroleum | 10 February 12

Ber Bahr Block

The block has an area of 280km² and is located to the north-west, and on trend with both the Shaikan and the Sheikh Adi blocks. The PSC for the Ber Bahr block was awarded to Genel Energy International Limited (Operator with the working interest of 40%) and GKP (40%) by the KRG which has a 20% carried interest in the Ber Bahr PSC.

Ber Bahr location map

Source: Company

The Operator’s estimate for the Ber Bahr oil-in-place was 1.9bn bbls. However, the Ber Bahr-1 well was found to be uncommercial following drilling completed in January 2011. The company has not stated any future drilling plans for this block.


Gulf Keystone Petroleum | 10 February 12 Financial model

Financial model

Income Statement


2009A 2010A 2011E 2012E 2013E

Group revenue 0.0 0.8 101.7 63.1 118.1Cost of sales 0.0 (0.8) (9.7) (31.6) (63.6)Gross profit 0.0 0.0 92.0 31.5 54.5Total operating expenses (21.2) (32.6) (24.6) (16.0) (16.0)EBIT (21.2) (32.6) 67.5 15.5 38.5Net interest/financial income/(cost) (0.7) (0.2) 2.8 14.1 13.9Associate and Other non-op. income/(cost) (0.4) 5.9 6.0 0.0 0.0PBT (96.3) (26.8) 76.2 29.6 52.4Tax (0.0) 0.8 (34.6) (11.8) (21.0)Effective tax rate (%) (0.0) 3.1 45.4 40.0 40.0Minorities 0.0 0.0 0.0 0.0 0.0Earnings (96.3) (26.0) 41.6 17.7 31.5 EBITDA (20.8) (32.1) 68.0 16.3 39.3Adjusted EBITDA* (20.6) (25.8) 80.2 44.8 67.5Adjusted EBIT* (21.0) (26.3) 79.7 44.1 66.8Adjusted PBT* (96.3) (26.8) 76.2 29.6 52.4Adjusted earnings* (96.3) (26.0) 41.6 17.7 31.5 DPS (c) 0.0 0.0 0.0 0.0 0.0EPS (c) (22.8) (4.2) 4.9 2.1 3.7EPS [F. Dil.] (c) (22.8) (4.2) 4.9 2.1 3.7EPS [Adj.]* (c) (22.8) (4.2) 4.9 2.1 3.7EPS [Adj. F. Dil.]* (c) (22.8) (4.2) 4.9 2.1 3.7Weighted average no. shares (m) 422.5 622.6 854.1 854.1 854.1Fully dil. w. ave. no. shares (m) 422.5 622.6 854.1 854.1 854.1Year end no. shares (m) 422.5 622.6 854.1 854.1 854.1




Financial model Gulf Keystone Petroleum | 10 February 12

Cashflow Statement


2009A 2010A 2011E 2012E 2013E

Operating income (21.2) (32.6) 67.5 15.5 38.5Amortisation of acquired intangibles 0.0 0.0 0.1 0.1 0.1Amortisation of other intangibles 0.0 0.0 0.0 0.0 0.0Depreciation 0.4 0.5 0.5 0.8 0.8Net change in working capital 6.4 4.3 (2.2) 0.0 0.0Other 0.0 0.0 0.0 0.0 0.0Operating cash flow (14.4) (27.8) 65.8 16.3 39.3 Capital expenditure (49.3) (157.2) (98.3) (25.9) (48.4)Investment in Other intangibles 0.0 0.0 0.0 0.0 0.0Net interest/financial income/(cost) 0.3 0.2 3.0 14.1 13.9Tax paid 0.1 (0.5) (35.0) (11.8) (21.0)Net acqns./disposals (49.2) (157.2) (98.3) (25.9) (48.4)Dividend paid 0.0 0.0 0.0 0.0 0.0Other 0.0 (10.2) 7.0 0.0 0.0Cash flow before financing (112.5) (352.7) (155.7) (33.2) (64.5) Proceeds from shares issued 35.7 359.9 201.0 0.0 0.0Investments 0.0 0.0 0.0 0.0 0.0Other 0.0 0.0 0.0 0.0 0.0Net movement in cash/(debt) (76.8) 7.2 45.3 (33.2) (64.5) Opening net cash/(debt) 33.6 19.2 201.3 352.5 357.5Adjustments (Forex, etc.) 0.4 0.0 0.0 0.0 0.0Closing net cash/(debt) 19.2 201.3 352.5 357.5 334.0 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E 2012E 2013E





Key Ratios

Year end December

2009A 2010A 2011E 2012E 2013E

Revenue growth (%) n/a n/a 12,491.7 (38.0) 87.1Adj. EBITDA* growth (%) n/a 25.1 (410.7) (44.1) 50.6Adj. EBIT* growth (%) n/a 25.2 (403.2) (44.7) 51.6Gross margin (%) n/a 0.0 90.4 49.9 46.2Adj. EBITDA* margin (%) n/a (3,193.9) 78.8 71.0 57.2Adj. EBIT* margin (%) n/a (3,251.4) 78.3 69.8 56.6 Gearing (%) n/a n/a n/a n/a n/aInterest cover (x) (29.6) (168.4) n/a n/a n/aNet debt/Adj. EBITDA* (x) (0.9) (7.8) 4.4 8.0 4.9Dividend cover (x) n/a n/a n/a n/a n/a ROE (%) (139.4) (6.1) 6.1 2.5 4.3ROIC (%) (195.5) (16.5) 42.3 68.6 65.0ROCE (%) (195.5) (16.5) 42.3 68.6 65.0 Operating cash conversion (%) 69.0 86.6 96.7 100.0 100.0Net cash conversion (%) 116.8 1,356.8 (374.3) (186.8) (205.1)Net working cap / revenue (%) n/a 532.3 (2.2) 0.0 0.0Cap Ex / revenue (%) n/a 19,453.7 96.6 41.0 41.0



Valuation Metrics

Year end December

2009A 2010A 2011E 2012E 2013E

PER (x) (23.8) (129.9) 111.2 260.7 147.1EV / Revenue^ (x) n/a 5,700.9 45.3 73.0 39.0EV / Adj. EBITDA^* (x) (223.4) (178.5) 57.5 102.8 68.2EV / Adj. EBIT^* (x) (219.5) (175.3) 57.8 104.6 69.0EV / IC^ (x) 92.2 20.4 14.1 13.6 11.7EV / Taxed Adj. EBIT^* (x) (365.8) (292.2) 96.4 174.3 115.0 Yield (%) 0.0 0.0 0.0 0.0 0.0P / CFPS (x) (20.3) (9.6) (29.7) (139.5) (71.7)NAV per share (c) 16.4 68.6 79.6 81.6 85.3





Financial model Gulf Keystone Petroleum | 10 February 12


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The S factor The impact of the 2011 “Arab Spring” has culminated in huge uncertainty over Gulfsands’ operations in Syria. The company has now invoked the ‘Force majeure’ provisions of its PSC – effectively ceasing production for the foreseeable future. Nevertheless, we feel that the company’s progressive exploration strategy remains unscathed, and any civil/political resolution may be transformational for its beleaguered share price. On this basis we have set a valuation scope on a scale of scenarios, and initiate coverage with a valuation range of 366-146p.

Issues in Syria January 2011 saw a surge in protests across a multitude of Arab states which culminated in an uprising against individual governments and dictatorships. Syria was amongst the countries involved and its current uprising continues. In December 2011, Gulfsands invoked the force majeure provisions of its PSC, after the EU increased its pressure on the country’s regime with additional sanctions against the oil industry in general. As such, Gulfsands will not receive revenues for production arising from Block 26 for the ‘foreseeable future’.

Good assets & management. Bad timing. Ugly Politics. We take the view that Gulfsands remains a well structured, progressive company with a historically conducive mix of robust production and successful exploration. Encouragingly, the company does not hold any balance sheet debt and is currently in a strong liquidity position – sufficient to weather the implications of the force majeure in the medium term. Nevertheless, the uncertainty surrounding the force majeure, and the length of time it will be imposed will continue to plague the share price until a resolution is established.

Other projects We feel that any activity outside of Syria will be focussed in onshore Tunisia/Italy given recent exploration. It also has been active in Iraq where it is seeking to develop a flared gas to power project. However, liquidity could be a concern for the company due to the recent restriction on its revenues, the company has recently stated that it is now examining the acquisition of new assets to diversify its portfolio. Gulfsands’ exploration licence in Syria will expire in August 2012, but this is unlikely to be resolved whilst sanctions are still in place.

Valuation range We feel that it is prudent at this stage to present the overall scope for investors to juxtapose their appetite for risk, and set a best case – worse case range of 369p/share – 146p/share. We initiate with an Add recommendation.

10 February 12 | Initiation of coverage | Oil & Gas Producers

Gulfsands Petroleum(AIM:GPX)1,5

ADD Share price 175p

Target price range 366p – 146p 109% Upside – 17% Downside


Net cash (£m) 123.1



Average daily vol ('000, -3m) 476


(%) 1m 3m 12m

Absolute -5.2 -15.6 -50.4

FTA relative -9.0 -21.0 -49.6


100150200250300350400450


Price Relative

Source: Datastream


Next news Political updates from Syria

Business Oil & Gas Exploration and Production

www.gulfsands.com



Year end December

Revenue(£m)

EBIT*(£m)

PBT*(£m)

Tax(%)

Adj. EPS* (p)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 84.4 28.6 27.8 0.0 23.3 7.5 2.9 0.02010A 115.6 45.5 44.7 (0.0) 36.9 4.7 1.8 0.02011E 145.1 78.3 78.0 0.0 48.7 3.6 1.1 0.02012E 15.3 (101.5) (101.3) 0.0 (83.1) (2.1) (0.8) 0.02013E 15.0 (115.6) (115.7) 0.0 (94.9) (1.8) (0.7) 0.0

* excludes exceptional items and amortisation of acquired intangibles.^ EV calculation adjusted for core cash, investments etc. Source: Seymour Pierce Ltd


Gulfsands Petroleum | 10 February 12 Syrian uprising overview

Syrian uprising overview

Background January 2011 saw a surge in protests across a multitude of Arab states which culminated in an uprising against individual governments and dictatorships. Syria was amongst the countries involved and its current uprising continues.

Although initially there was no impact on any of Gulfsands’ assets as oil production, sales and payments continued, market sentiment towards the company declined significantly during 1H2011. However, during September 2011, Gulfsands was instructed by the Syrian Oil Ministry to reduce Block 26 production in line with reduced availability of crude storage capacity within the country. Production operations on Block 26 were subsequently curtailed such that average gross production during the month of September was 14,547bopd versus the average for the month of August of 24,112bopd. In October 2011 daily gross production had been reduced further to 6,000bopd, and lower still in November. Accordingly, gross production for the month of October averaged 6,028bopd and for November averaged 4,862bopd.

Finally, in December 2011 Gulfsands invoked the force majeure provisions of its PSC in Syria, after the EU increased its pressure on the country’s regime with additional sanctions against three state-owned oil companies. As such, Gulfsands will not receive revenues for production arising from Block 26 for the foreseeable future.

Share price decline since Syrian uprising

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Our view We take the view that Gulfsands remains a well structured, progressive company with a historically conducive mix of strong production combined with recent successful exploration. Encouragingly the company does not hold any balance sheet debt and is currently in a strong liquidity position – sufficient to weather the implications of the Force majeure in the medium term. Nevertheless, the uncertainty surrounding the Force majeure, and the length of time it will be imposed will continue to plague the share price until a resolution is established.

On this basis in terms of our valuation, we felt that it is prudent to provide a range to investors rather than the traditional specific price target approach, given the unusual circumstances surrounding the company. We feel that this approach gives investors the flexibility to base their investment decision against their own specific appetite for political risk, and timing to potential resolution.

We tend to lean towards the upper end of our range given that Gulfsands, in our view, is a robust company and retains a strong asset portfolio, although situated in a currently unstable region Nevertheless, we highlight that a civil and political resolution would be a transformational event for the company, and indeed its share price.

January 2011 saw a surge in protests across a

multitude of Arab states which culminated in an

uprising against individual governments and

dictatorships. Syria was amongst the countries

involved and its current uprising continues.


Valuation and recommendation Gulfsands Petroleum | 10 February 12


We have valued Gulfsands in terms of its risked exploration portfolio, as well as a discounted cash flow (DCF) appraisal of production cash flows arising from their operations in Syria on a best case/worse case scenario range. We have built in the following assumptions to our valuation:


Metric Assumption

Projected oil price 2012:-$100/bbl, 2013+:-$90/bbl flat Discount to Brent 11% Long-term $/£ 1.65 Discount rate 10% Shares outstanding (million) 117.95 Production restriction - best case No restriction, all revenues projected on this basis Production restriction - worse case No revenues recognised from December 2011 onwards


We have incorporated the above assumptions into Gulfsands’ exploration portfolio in which we have subsequently risked to take account of the inherent issues associated with successful exploration drilling.

Risked Net Asset Valuation

Country Asset Gross (mmboe)

Interest CoS Unrisked (mmboe)

Risked (mmboe)

NPV US$/bbl

Risked NPV $m

Risked NPV £m

Net Risked p/share

Production USA GoM Fields 3.4 Various 100% 3.4 3.4 5.00 17.0 10.3 8.7 Appraisal Syria Block 26 Upside 31.0 50% 75% 15.5 11.6 11.00 127.9 77.5 65.7 Tunisia Dougga 23.0 30% 50% 6.9 3.5 1.30 4.5 2.7 2.3 Total appraisal 54.0 22.4 15.1 132.4 80.2 68.0 Exploration upside Syria Abu Ghazal 10.0 50% 20% 5.0 1.0 6.90 6.9 4.2 3.5 Syria KHE-101 (Deep) 2.6 50% 33% 1.3 0.4 6.20 2.7 1.6 1.4 Syria Safa-1 3.4 50% 17% 1.7 0.3 8.30 2.4 1.5 1.2 Syria Maglouga-1 15.6 50% 10% 7.8 0.8 8.30 6.5 3.9 3.3 Syria South Souedieh 7.8 50% 13% 3.9 0.5 8.30 4.2 2.6 2.2 Syria Al Khair 6.0 50% 10% 3.0 0.3 8.30 2.5 1.5 1.3 Syria Wardieh 28.0 50% 10% 14.0 1.4 8.30 11.6 7.0 6.0 Syria exploration 73.4 36.7 4.7 36.8 22.3 18.9 Tunisia Lambouka 3.6 30% 10% 1.1 0.1 3.50 0.4 0.2 0.2 Tunisia Sidi Daher 9.5 40% 10% 3.8 0.4 5.50 2.1 1.3 1.1 Tunisia exploration 13.1 4.9 0.5 2.5 1.5 1.3 Total prod+app+exp 143.9 67.4 23.7 188.6 114.3 96.9


Due to the early stages of development, we currently do not attribute any value to Gulfsands’ projects in Italy and Iraq. In Iraq, the company is in the process of discussions with regards to financing and potential equity partners, although we have yet to see any traction on these discussions. At the company’s offshore Tunisian operations, Gulfsands encountered issues whereby no fluid samples or gas flows were established. As such the company suspended the Lambouka well and intends to re-enter at a later date.

Due to the early stages of development, we

currently do not attribute any value to Gulfsands’

projects in Italy and Iraq.


Gulfsands Petroleum | 10 February 12 Valuation and recommendation

Target price range

Given the recent force majeure imposed on Gulfsands’ Syrian assets, we feel it is appropriate to provide investors with a target price range given that no guidance has been provided by the Syrian authorities as to the cessation period. We have taken a best case and worse case scenario with respect to forecast production, which we outline below.

Pre-uprising valuation

Our best case scenario outlines Gulfsands' potential risked net asset value in the event that the Syrian uprising did not take place at all, and the company continued to produce and export its resources without any restrictions in place. Prior company guidance indicated that production would plateau at 33,000bopd in 2013 which we have continued to model in this scenario.


£ million p / share

Syria (DCF) 252 214 Gulf of Mexico 10 9 Less G&A (71) (60) Plus net (debt)/cash 120 102 Core value 312 264 Appriasal 80 68 Exploration upside 40 33 Target market cap (GBp) 432 366



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Under this scenario, the upper end of our range is largely driven by Block 26 discounted cash flow production contributing 214p/share - some 26% above current levels. Our best case scenario sets an upper range limit of 366p/share.

Force majeure valuation

Conversely, our worse case scenario illustrates the potential value of Gulfsands in the event that the force majeure is implemented for the foreseeable future, thereby restricting all production from Block 26. The company estimates that gross G&A will be $12m ($6m per annum net) for the duration of the sanctions.

Under this scenario, the upper end of our range

is largely driven by Block 26 discounted cash

flow production contributing 214p/share - some

26% above current levels. Our best case scenario

sets an upper range limit of 366p/share.


Valuation and recommendation Gulfsands Petroleum | 10 February 12


£ million p / share

Syria (DCF) (16) (13) Gulf of Mexico 10 9 Less G&A (62) (52) Plus net (debt)/cash 120 102 Core value 53 45 Appriasal 80 68 Exploration upside 40 33 Target market cap (GBp) 173 146



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The above analysis sets the lower end of our target range at a price of 146p/share.

Range of valuation

The above analysis outlines the two extreme limits that could potentially be applied to the company. Importantly, it illustrates that at current levels there is a greater degree of upside potential than there is downside, and suggests that any political resolution would be transformational for the company’s share price. We maintain that it is prudent at this stage to present the overall scope for investors to juxtapose their appetite for risk, and set an upper – lower range of 366p/share – 146p/share. We initiate with an Add recommendation.


Gulfsands Petroleum | 10 February 12 Asset overview – Syria

Asset overview – Syria

Gulfsands’ key producing assets, Khurbet East and Yousefieh, are situated in Block 26 – of which the company has a 50% working interest. The Block covers c.5,414 km2 and encompasses existing fields which currently produce over 100,000bopd, and are operated mainly by the Syrian Petroleum Company. Khurbet East was discovered in 2007 and came on stream in 2008, whilst Yousefieh commenced commercial production in 2010. Gulfsands’ 2P net reserves at both fields are currently c.54mmbbls.

Gulfsands’ current exploration license expires in August 2012, we do not expect this issue to be resolved until force majeure is removed. The development and production period for the Khurbet East field does not expire until 2033 whilst the Yousefieh field expires in 2035, but each may be extended for a further 10 years at the operator's option.

Block 26 location map

Source: Company

Khurbet East

This field has been producing at an average gross production rate of approximately 21,500bopd through early production facilities during August 2011. The development and operation of the field is being undertaken by Dijla Petroleum Company, a joint operating company formed with the Syrian Petroleum Company for this purpose.

The recent KHE-1 discovery well encountered oil at a depth of approximately 2,000m, with reserves arising from the Cretaceous formation only, excluding the deeper Triassic formations. Oil produced from Khurbet East has an API gravity of c.25° which is slightly lighter than that of the area benchmark "Syrian Heavy" crude oil.


Asset overview – Syria Gulfsands Petroleum | 10 February 12

Yousefiah

Following the imposed force majeure, Gulfsands has undertaken a complete shut-in of the Yousefieh field in order to conduct a long term field pressure build-up survey. Memory pressure gauges have been placed in all Yousefieh wells prior to the shutdown of the field. This has allowed the company to determine average field reservoir pressure to a level of accuracy that would not otherwise be possible to achieve when the field is under normal production conditions. Measuring reservoir pressure in this way will enable a more accurate calculation of field in-place volumes and recoverable reserves.

Historical production prior to restriction

Gross production from Block 26 increased by 25% in 2010, from 16,511bopd in January to 20,578bopd in December. Gross oil production increased to over 24,000bopd by the end of August 2011 following the commissioning of an additional Khurbet East sub-station facility. The Yousefieh field was brought on production in April 2010 and by December was producing an average of 2,450bopd from three wells. At Khurbet East production rose from 16,511bopd from seven wells in January to 18,128bopd from ten wells in December. At the end of August 2011 KHE was producing over 21,500bopd and Yousefieh is averaging over 2,600bopd.

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Khurbet East Yousefieh

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Gross daily oil production at the end of August 2011 stood at approximately 24,000bopd, and was forecast to increase to 33,000bopd by 2013. In our view, this illustrates the potential long term value of the company prior to the imposed restrictions, as well as the potential upside on civil and political resolution.

Syrian Exploration

Due to force majeure there are no current or forecast exploration activities in Syria.


Gulfsands Petroleum | 10 February 12 Other projects

Other projects

Iraq

Although Gulfsands has had a presence in Iraq since 2003 and recently opened offices in Baghdad, the company currently holds no reserves in the country. In 2005, Gulfsands signed a Memorandum of Understanding with the Ministry of Oil for the Maysan Gas Project in the south of the country.

The objective of the project is to gather, process and transmit natural gas that is currently a waste by-product of oil production. Nevertheless, although the MoU has been in place for seven years, this is very much a non-core operation – and one which we do not attribute any value.

We understand that this project is no longer a priority given the current situation in Syria as the company is maintaining capital.

Tunisia and Italy

Gulfsands has working interests in two exploration permits in Tunisia - Chorbane and Kerkouane, and one in Southern Italy – Pantelleria.

Tunisia and Italy licence map

Source: Company

Chorbane Operations at Sidi Dhaher-1 began in October 2011 and identified a potential oil column and was suspended for future testing. A rig has now been contracted and is expected on site in the short term.

Gulfsands earned a 40% interest in the Chorbane permit by meeting 80% of the well costs for the Sidi Dhaher-1 well which are capped at $5m and thereafter meeting its pro rata (40%) share of any additional costs beyond $5m. In the event of a commercial


Other projects Gulfsands Petroleum | 10 February 12

success with the Sidi Dhaher-1 well, Gulfsands will be entitled to become the operator of the Chorbane permit.

Kerkouane In April 2011, 640km² of 3D seismic data was acquired over the Lambouka prospect area within the Kerkouane permit area, and the Lambouka-1 well was spudded in mid-July and drilled to a depth of 2,786m. Drilling operations were concluded in early September. Wireline log interpretation indicates that gas and possibly condensate was encountered in the formation; however, as a result of ongoing fluid losses and deterioration of the well bore it was not possible to safely recover fluid samples or pressure data from the formation. The well was suspended with the intention of re-entering at a later date and drilling and testing the reservoir in a sidetrack hole, probably targeting an area structurally up-dip of the existing well bore.

Lambouka location map

Source: Company

Gulfsands earned its 30% working interest in the Kerkouane permit by paying approximately 35% of the cost of the Lambouka-1 well and reimbursing the operator for a portion of various pre-drill costs that include the recently completed 3D seismic programme.


Gulfsands Petroleum | 10 February 12 Financial model – (force majeure projection)

Financial model – (force majeure projection)

Income Statement


2009A 2010A 2011E 2012E 2013E

Group revenue 84.4 115.6 145.1 15.3 15.0Cost of sales (38.0) (38.8) (44.0) (96.8) (110.6)Gross profit 46.5 76.8 101.1 (81.5) (95.6)Total operating expenses (17.8) (31.2) (22.8) (20.0) (20.0)EBIT 28.6 45.5 78.3 (101.5) (115.6)Net interest/financial income/(cost) 0.3 0.2 0.3 0.2 (0.0)Associate and Other non-op. income/(cost) 0.0 0.0 0.0 0.0 0.0PBT 27.8 44.7 78.0 (101.3) (115.7)Tax 0.0 0.0 0.0 0.0 0.0Effective tax rate (%) 0.0 (0.0) 0.0 0.0 0.0Minorities 0.0 0.0 0.0 0.0 0.0Earnings 27.8 44.7 78.0 (101.3) (115.7) EBITDA 54.2 81.0 105.1 (60.3) (67.5)Adjusted EBITDA* 41.4 63.3 91.7 (80.9) (91.6)Adjusted EBIT* 28.6 45.5 78.3 (101.5) (115.6)Adjusted PBT* 27.8 44.7 78.0 (101.3) (115.7)Adjusted earnings* 27.8 44.7 78.0 (101.3) (115.7) DPS (p) 0.0 0.0 0.0 0.0 0.0EPS (p) 23.3 36.9 48.7 (83.1) (94.9)EPS [F. Dil.] (p) 23.1 35.9 47.5 (81.2) (92.7)EPS [Adj.]* (p) 23.3 36.9 48.7 (83.1) (94.9)EPS [Adj. F. Dil.]* (p) 23.1 35.9 47.5 (81.2) (92.7)Weighted average no. shares (m) 119.3 121.9 121.9 121.9 121.9Fully dil. w. ave. no. shares (m) 120.7 124.5 124.8 124.8 124.8Year end no. shares (m) 119.3 121.9 121.9 121.9 121.9




Financial model – (force majeure projection) Gulfsands Petroleum | 10 February 12

Cashflow Statement


2009A 2010A 2011E 2012E 2013E

Operating income 28.6 45.5 78.3 (101.5) (115.6)Amortisation of acquired intangibles 12.8 17.7 13.4 20.6 24.1Amortisation of other intangibles 0.0 0.0 0.0 0.0 0.0Depreciation 12.8 17.7 13.4 20.6 24.1Net change in working capital (6.0) (6.5) 6.5 9.9 0.0Other 27.9 20.7 18.1 18.1 18.1Operating cash flow 76.1 95.2 129.7 (32.3) (49.4) Capital expenditure (24.1) (42.9) (64.5) (42.5) (13.1)Investment in Other intangibles 0.0 0.0 0.0 0.0 0.0Net interest/financial income/(cost) 0.3 0.2 0.3 0.2 (0.0)Tax paid (0.1) 0.4 0.0 0.0 0.0Net acqns./disposals (26.3) (48.0) (49.3) (42.0) (15.3)Dividend paid 0.0 0.0 0.0 0.0 0.0Other (2.2) (5.1) 15.2 0.5 (2.2)Cash flow before financing 23.7 (0.2) 31.4 (116.1) (80.0) Proceeds from shares issued 3.6 3.2 0.9 0.0 0.0Investments 0.0 0.0 0.0 0.0 0.0Other 0.0 (2.4) (13.7) 0.0 0.0Net movement in cash/(debt) 27.3 0.6 18.6 (116.1) (80.0) Opening net cash/(debt) 36.8 57.6 80.6 126.3 19.5Adjustments (Forex, etc.) 0.0 0.0 0.0 0.0 0.0Closing net cash/(debt) 57.6 80.6 126.3 19.5 (81.3) Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E 2012E 2013E

Property plant and equipment 82.6 63.9 64.8 46.4 23.4Goodwill and Acquired intangibles 0.0 0.0 0.0 0.0 0.0Other intangibles 7.1 31.0 48.2 82.6 88.6Other fixed assets 12.0 9.6 9.1 9.1 9.1Non current assets 101.7 104.4 122.1 138.0 121.1 Stocks & WIP 4.2 4.0 5.3 0.7 0.6Trade receivables 21.9 35.6 26.6 3.3 3.2Cash 57.6 80.6 126.3 19.5 (81.3)Other current assets 0.0 18.3 6.0 3.7 6.9Current assets 83.7 138.5 164.2 27.1 (70.6) Total assets 185.3 242.9 286.4 165.2 50.5 Trade creditors 13.4 23.1 15.3 1.9 1.9Short term borrowings 0.0 0.0 0.0 0.0 0.0Long term borrowings 0.0 0.0 0.0 0.0 0.0Other liabilities 31.6 36.8 35.8 35.4 37.3Total liabilities 45.0 59.9 51.1 37.3 39.1 Net assets 140.3 183.0 235.3 127.9 11.3 Issued share capital 13.0 13.1 13.1 13.1 13.1Share premium account 101.9 105.0 105.9 105.9 105.9Retained earnings (1.8) 36.9 87.1 (20.3) (136.8)Other reserves 27.1 (6.0) (5.9) (5.9) (5.9)Minority interests 0.0 0.0 0.0 0.0 0.0Total equity 140.3 183.0 235.3 127.9 11.3




Key Ratios

Year end December

2009A 2010A 2011E 2012E 2013E

Revenue growth (%) n/a 36.9 25.6 (89.5) (1.8)Adj. EBITDA* growth (%) n/a 52.9 45.0 (188.2) 13.1Adj. EBIT* growth (%) n/a 59.2 72.0 (229.6) 13.9Gross margin (%) 55.0 66.4 69.7 (534.5) (638.2)Adj. EBITDA* margin (%) 49.0 54.7 63.2 (530.4) (610.9)Adj. EBIT* margin (%) 33.9 39.4 54.0 (665.6) (771.7) Gearing (%) n/a n/a n/a n/a 716.7Interest cover (x) n/a n/a n/a n/a (9,074.6)Net debt/Adj. EBITDA* (x) 1.4 1.3 1.4 (0.2) 0.9Dividend cover (x) n/a n/a n/a n/a n/a ROE (%) 19.8 24.4 33.2 (79.3) (1,019.1)ROIC (%) 115.7 104.1 121.0 (238.2) (880.1)ROCE (%) 115.7 104.1 121.0 (238.2) (880.1) Operating cash conversion (%) 140.4 117.6 123.4 53.6 73.2Net cash conversion (%) 85.3 (0.5) 40.2 114.6 69.2Net working cap / revenue (%) (7.2) (5.6) 4.5 65.0 0.2Cap Ex / revenue (%) 28.5 37.1 44.4 278.9 87.7



Valuation Metrics

Year end December

2009A 2010A 2011E 2012E 2013E

PER (x) 7.5 4.7 3.6 (2.1) (1.8)EV / Revenue^ (x) 1.0 0.7 0.6 5.4 5.5EV / Adj. EBITDA^* (x) 2.0 1.3 0.9 (1.0) (0.9)EV / Adj. EBIT^* (x) 2.9 1.8 1.1 (0.8) (0.7)EV / IC^ (x) 1.0 0.8 0.8 0.8 0.9EV / Taxed Adj. EBIT^* (x) 2.9 1.8 1.1 (0.8) (0.7) Yield (%) 0.0 0.0 0.0 0.0 0.0P / CFPS (x) 8.8 (1,019.3) 6.8 (1.8) (2.7)NAV per share (p) 117.5 150.1 193.0 104.9 9.3





Financial model – (force majeure projection) Gulfsands Petroleum | 10 February 12


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From zero to hero (again?) In 2011, a mis-communicated reserve report, delayed clarity on funding against a backdrop of weak market conditions resulted in Xcite losing the majority of its 2010 share price gains. With the rig on site awaiting delayed DECC approval and development drilling due to start in February, are we about to see resurgence in this stock? We think so, but it may prove to be another turbulent year for investors should initial drilling results fail to deliver.

Drilling due to start – still waiting for DECC approval The Rowan Norway rig is currently crewing and gearing up in Dundee, with drilling expected to start in February. This initial drilling phase is designed to optimise methods and gather data ahead of moving into full commercial production. Given the relatively low amount of drilling data, we would ideally like to see consistent data coming from these wells. We see this as the key short term risk for the company as mixed or poor results may put the commerciality of the project in doubt.

Funded for initial phase of development With the recent private placing and Equity Drawdown Facility secured, Xcite moves into phase 1A from a positive funding position. Subsequent phases will be funded by production cash flow. However, investors need to remember that this funding will be dilutive to their positions particularly if drilling results are not as predicted and the share price falls.

Resource base should convert into reserves A successful drilling campaign should result in a shift from contingent resources to reserves, enhancing the valuation of the asset. We would anticipate that in these circumstances the company will actively update its asset base audit reports to provide share price drivers for the company.

Valuation and recommendation Given the fairly high degree of upfront risk associated with the drilling programme, investors may initially wish to proceed cautiously. In 2010, Xcite became an excellent trading stock with large swings in price, backed by good volume. We feel that this will continue in 2011 and this may be a more suitable trading strategy rather than taking a long term view for now. We have based our valuation on the May 2011 Reserve Assessment Report and initiate coverage with an Add recommendation and set a target price of 242p.



Xcite Energy(AIM: XEL) 1

ADD Share price 91p



Net cash (£m) 30.8





(%) 1m 3m 12m

Absolute -11.0 -25.0 -74.3

FTA relative -14.7 -29.8 -73.9


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Source: Datastream


Next news Drilling confirmation

Business XEL’s sole asset is a 100% interest in the Bentley

viscous oil field in the UK North Sea. This project

is at the pre-development stage.

www.xcite-energy.com/


Year end December

Revenue(£m)

EBIT*(£m)

PBT*(£m)

Tax(%)

Adj. EPS* (p)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 0.0 (0.8) (0.8) (12.4) (1.4) (64.8) (202.3) 0.02010A 0.0 (2.6) (2.4) 0.0 (1.9) (47.8) (61.8) 0.02011E 0.0 (1.3) (1.1) (2.5) (0.6) (140.5) (121.7) 0.0





Xcite Energy | 10 February 12 Valuation and recommendation


We have based our valuation of Xcite solely on the company's latest Reserves Assessment Report (RAR) for the Bentley field. We have incorporated the following assumptions into our model:


Metric Assumption

Long term $/£ exchange rate 1.65 Discount rate 10% No of shares outstanding, fully diluted (m) 228 Bentley Chance of Success 70% Bentley Chance of Development 90%


Xcite’s reserve report was undertaken by TRACS, we have used the data from this and applied an internally generated risk factor to provide the intrinsic valuation for the Bentley field.

Bentley Field Valuation

Input assumption Low Base High

Reserves (mmbbl) 22.0 27.8 34.9 Contingent resources (mmbbl) 72.7 87.2 100.9 Total (mmbbl) 94.7 115.0 135.8 Bentley East (mmbbl) 14.0 18.3 28.0 Other Prospects (mmbbl) 10.3 17.5 30.6 Total Prospects (mmbbl) 24.3 35.8 58.6 $m $m $m Reserve NPV10 (m) - post tax 229 396 558 Contingent resource NPV10 (m) - Post tax 661 961 1,315 Total 890 1,357 1,873

Source: TRACS

TRACS has estimated that the Bentley field is worth $1,357m on a base case scenario, discounted at a 10% net present value. This is based on a reserves estimation of 27.8mmbbls and contingent resources of 87.2mmbbls. It is these externally verified data points that form the basis of our valuation.

Bentley Field valuation per share

Low Base High

NPV/share (p) - Unrisked 237 361 498 NPV/share (p) - Risked 149 227 314


We risk Xcite’s gross valuation at 70% to reflect the implicit uncertainties associated with successful drilling. We also apply a 90% chance of development ahead of project sanction. These range from technology employed to rig maintenance, as well as unforeseen issues such as weather interruptions, delays or damage. RPS Energy & TRACS (CPR providers) also recommends this as an appropriate measure of risking the Bentley field.


Valuation and recommendation Xcite Energy | 10 February 12


NAV by activity £ million p / share

Confirmed CPR reserves/resources 822.4 227 Plus net (debt)/cash 30.78 15 Core NAV 853.2 242



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Given the fairly high degree of upfront risk associated with the drilling programme, investors may initially wish to proceed cautiously. In 2010, Xcite became an excellent trading stock with large swings in price, backed by good volume. We feel that this will continue in 2011 and that this may be a more suitable trading strategy rather than taking a long term view for now. We have based our valuation on the May 2011 Reserve Assessment Report and initiate coverage with an Add recommendation and set a target price of 242p.


Xcite Energy | 10 February 12 Valuation and recommendation

Bentley field overview

The field was discovered in 1977 by Amoco who subsequently passed on operatorship to Conoco in the 1980s. During this period the field remained undeveloped due to the viscous (10-12o API) quality of the oil. The field is located in 113m of water, 160km east of the Shetland Isles.

Drilling history

Only a few wells have been drilled on the field and these have yielded very mixed results:

Bentley field well summary

Name Year Operator Oil column (ft) Test result

9/3-1 1977 Amoco 81 Nitrogen lift, no flow 9/3-2, 2A 1983 Conoco 92 ESP lifted DST. No flow due to pump failure 9/3-4 1986 Conoco 84 Not tested 9/3b-5 2008 Xcite 87 ESP lifted flow average of 125bopd, maxing at 250bopd 9/3b-6z 2010 Xcite Not stated 2,900STB/d with 2,000bbl produced over 36h period


The most recent well (9/3b-6z) was crucial in proving that Bentley could flow at commercial rates as this had not been achieved by the previous wells. The testing programme was not ideal due to a fault with the pipe from the rig to the tanker which resulting in an ad-hoc “bucket chain” system using tote tanks being employed instead. This has led to speculation from some commentators as to the validity of the flow test. The relatively short flow test of c.25 hours has also raised concerns. Whilst not ideal, we are comfortable with the result gained from the well. However, we do expect that the initial development wells which are due to be drilled over the course of 2012 may require some “tinkering” to get right, due to the relatively low amount of information from the only successful well on the field to date.

Reserves assessment report fallout and funding

The volatility and collapse of the share price during 2011 was driven by poor communication from management ahead of the delayed publication of the reserves assessment report, as well as the mainly retail shareholder base not understanding the process and having an unrealistic view (driven by management comments) on how much of the resource base would be converted into reserves. In addition, the prevailing market conditions did not help matters.

In our view, the poorly received report, in conjunction with poor market conditions prolonged the fund raising process, which was only resolved in late December. Despite the delay, the company is now funded for phase 1A which is crucial for moving this project towards production. The funding comprised £25.8m private placing (in two 50% tranches) with Socius, the second tranche has not yet been issued. Xcite also entered into a £60m Equity Credit Facility with Esousa, replacing a similar facility with Yorkville.

Our view The lack of clarity over funding was one of our major concerns in 2011. However, this funding will have a significant dilution effect as not all of the new equity has yet been issued. The inclusion of warrants in what will be a highly dilutive approach is a step too far in our view.

This funding only covers phase 1A, management has previously stated that funding for the other phases will come from future production cash flows. Should there be issues relating to production, then investors should expect another round of financing.

Only a few wells have been drilled on the field

and these have yielded very mixed results:


Valuation and recommendation Xcite Energy | 10 February 12

Development plan

The original plan was to develop the field in two stages. However, this has now been split into three.

1. Phase 1A – first oil in 2012, currently awaiting DECC approval

2. Phase 1B - first oil in 2013

3. Phase 2 - first oil in 2016

The company has given high level details for each stage:

“Phase 1A comprises the drilling of and production from the first motherbore well and associated laterals on Bentley, prior to the final design and optimisation of Phase 1B. The produced oil will be transferred via a pipeline to a dynamically positioned shuttle tanker, in which a diluent crude oil will be present and thus enabling blending tests to be undertaken for marketing and offtake purposes.”

“Phase 1B is planned to comprise a permanent, normally unattended, minimum facilities, lightweight wellhead tower, capable of accommodating up to 12 drilling risers and remaining throughout the rest of field life. Four additional production motherbore wells will initially be drilled with their associated laterals which, together with the well drilled in Phase 1A, will provide the basis for the remainder of Phase 1 production. Crude oil will be produced to an FPSO via a subsea pipeline, with export via a shuttle tanker. The intention is to run Phase 1B for approximately three years, with the additional riser and potential production capacity providing significant flexibility.”

“Phase 2 remains as previously planned, with a further permanent production platform comprising full processing, drilling and accommodation facilities for the balance of life of field production.”

Our take The Rowan Norway jackup rig is in Dundee harbour crewing and gearing up ahead of drilling which is due to start in February. In December 2011, Xcite signed a Letter of Intent with Teekay Shipping for a shuttle tanker. From the tone of the description of Phase 1A above, it would seem that there is more to be done to fully understand the Bentley field ahead of signing off on fully developing the field.

Given the mixed results from drilling on the block so far, we would feel more comfortable to see if consistent results can be obtained from the first batch of wells. We would expect Xcite’s share price to be volatile during the next drilling phase, especially if the early results are not favourable. We think that it is telling that the company is not giving project production guidance ahead of the initial drilling phase, something we would normally expect to happen as a project moves into the development phase.


Xcite Energy | 10 February 12 Financial model

Financial model

Income Statement


2009A 2010A 2011E

Group revenue 0.0 0.0 0.0Cost of sales 0.0 0.0 0.0Gross profit 0.0 0.0 0.0Total operating expenses (0.8) (2.6) (1.3)EBIT (0.8) (2.6) (1.3)Net interest/financial income/(cost) 0.0 0.1 0.2Associate and Other non-op. income/(cost) 0.0 0.0 0.0PBT (0.8) (2.4) (1.1)Tax (0.1) 0.0 (0.0)Effective tax rate (%) (12.4) 0.0 (2.5)Minorities 0.0 0.0 0.0Earnings (0.9) (2.4) (1.2) EBITDA (0.8) (2.6) (1.3)Adjusted EBITDA* (0.8) (2.6) (1.3)Adjusted EBIT* (0.8) (2.6) (1.3)Adjusted PBT* (0.8) (2.4) (1.1)Adjusted earnings* (0.9) (2.4) (1.2) DPS (p) 0.0 0.0 0.0EPS (p) (1.4) (1.9) (0.6)EPS [F. Dil.] (p) (1.4) (1.9) (0.6)EPS [Adj.]* (p) (1.4) (1.9) (0.6)EPS [Adj. F. Dil.]* (p) (1.4) (1.9) (0.6)Weighted average no. shares (m) 63.8 126.5 198.9Fully dil. w. ave. no. shares (m) 63.8 126.5 198.9Year end no. shares (m) 63.8 126.5 198.9




Financial model Xcite Energy | 10 February 12

Cashflow Statement


2009A 2010A 2011E

Operating income (0.8) (2.6) (1.3)Amortisation of acquired intangibles 0.0 0.0 0.0Amortisation of other intangibles 0.0 0.0 0.0Depreciation 0.0 0.0 0.0Net change in working capital (0.9) 22.0 (16.2)Other 0.1 1.5 0.4Operating cash flow (1.5) 20.9 (17.1) Capital expenditure (0.9) (39.4) (12.3)Investment in Other intangibles 0.0 0.0 0.0Net interest/financial income/(cost) 0.0 0.1 0.2Tax paid 0.0 0.0 0.0Net acqns./disposals (0.5) (39.3) (12.1)Dividend paid 0.0 0.0 0.0Other 0.4 0.0 0.0Cash flow before financing (2.5) (57.7) (41.2) Proceeds from shares issued 1.9 52.6 56.7Investments 0.0 0.0 0.0Other 0.0 0.0 (5.0)Net movement in cash/(debt) (0.6) (5.0) 10.5 Opening net cash/(debt) 1.8 1.7 36.0Adjustments (Forex, etc.) 0.0 0.0 0.0Closing net cash/(debt) 1.7 36.0 58.5 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E

Property plant and equipment 0.0 0.0 0.1Goodwill and Acquired intangibles 0.0 0.0 0.0Other intangibles 23.0 65.3 78.3Other fixed assets 0.0 0.0 0.0Non current assets 23.0 65.3 78.4 Stocks & WIP 0.0 0.0 0.0Trade receivables 0.0 1.6 1.0Cash 1.7 36.0 58.5Other current assets 0.0 0.0 0.0Current assets 1.8 37.5 59.5 Total assets 24.8 102.8 137.9 Trade creditors 0.2 23.7 7.0Short term borrowings 0.0 0.0 0.0Long term borrowings 0.0 0.0 (5.0)Other liabilities 0.5 0.5 0.5Total liabilities 0.7 24.2 2.5 Net assets 24.1 78.6 135.4 Issued share capital 24.2 76.5 133.2Share premium account 0.0 0.0 0.0Retained earnings (2.1) (4.2) (5.4)Other reserves 1.9 6.3 7.6Minority interests 0.0 0.0 0.0Total equity 24.1 78.6 135.4



Xcite Energy | 10 February 12 Financial model


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Calm after the storm Bayfield has updated the market with a comprehensive evaluation of their progress in Trinidad, Russia and South Africa. Although we are encouraged by the progress being made at East Galeota and aspects of the company’s appraisal campaign, near-term production downgrades and operational issues may impact market sentiment in the short-term. Nevertheless, we reiterate our BUY recommendation and set a revised target price of 108p.

Progress being made at East Galeota Bayfield has confirmed the spudding of the first of its seven-well commitment which is programmed for 42 days to completion. In our view, successful drilling at this relatively low risk site will continue to unlock existing resources, allowing the company to potentially increase their reserve base.

Delays to production Production for December 2011 and January 2012 has been detrimentally impacted by adverse weather conditions, obstructing personnel movements between the shore base and the platforms. The production restriction has reduced the NPV attributable to our valuation by c.10p/share. This is due to lower than projected initial cash flows, whilst retaining c.$76.5m exploration and appraisal expenditure for FY2012.

Platform change and refurbishment Recent engineering studies confirmed that it is unsafe to conduct rig operations from Bayfield’s Alpha platform. Although existing production from Alpha (currently 350bopd) will remain on-stream, any new wells required to access reserves from unexploited areas of the reservoirs adjacent to Alpha will, instead, be drilled from either Bravo or Charlie at an additional cost of $10-15m net to the company.

Recommendation and target price revision Our latest target price comprises an updated discounted cash flow (DCF) analysis which reflects the additional capital expenditure requirement and near term production downgrades. On the basis of today’s operational update, we reiterate our BUY recommendation and set a revised target price of 108p (previously 121p).

1,3,4,5 Please see regulatory disclosure notes at the end of this document


10 February 12 | Company Note | Oil & Gas exploration and production

Bayfield Energy( FTSE : BEH.L)1,3,4,5

BUY Share price 49p



Net cash (£m) 29.4



Free float (%) 53.5



PER at Target price (Y1) (60.6)

Sector PER 0.0

Price/book 5.4


(%) 1m 3m 12m

Absolute -7.1 -12.9 n/a

FTA relative -10.9 -18.6 n/a


404550556065707580

Jul Aug Sep Oct Nov Dec Jan

Price Relative

Source: Datastream


Next news FY 2012 Results

Business Oil and gas exploration and production

www.bayfieldenergy.com



Year end December

Revenue(£m)

EBIT*(£m)

PBT*(£m)

Tax(%)

Adj. EPS* (p)

PER (x)

EV/EBIT*(x)

Div yield(%)

2009A 16.2 6.1 5.9 41.4 1.0 1,506.6 8,243.6 0.02010A 16.8 5.9 5.7 38.4 1.0 1,476.7 8,586.0 0.02011E 20.9 7.5 7.4 45.8 1.2 1,289.1 6,723.5 0.02012E 25.2 9.4 9.5 42.0 1.6 934.1 5,403.7 0.02013E 27.2 10.4 10.8 42.0 1.8 819.7 4,849.2 0.0





Bayfield Energy | 10 February 12 Valuation and recommendation


Our valuation of Bayfield comprises an updated discounted cash flow (DCF) analysis which reflects the additional capital expenditure requirement and near term production downgrade. In addition, we include an updated risked net asset valuation of the company’s reserves and resources. The assumptions implicit in our valuation are as follows:


Metric Assumption

$NPV/mmboe - Reserves 7.48 $NPV/mmboe - Contingent resources 3.74 Realised oil price (WTI) 2012:- $80.8/bbl; 2013+:- $85.6 flat Long-term $/£ 1.65 Discount rate 10% Shares outstanding (million) 214.98 Bayfield's working interest (Trinidad) 65%


We have used an inferred market multiple from the recent Range Resources/SOCA Petroleum transaction of $7.48/bbl for reserves and $3.74/bbl for contingent resources. This transaction has provided the market with a recent tangible benchmark on which to apply a real market value to assets in Trinidad as opposed to a theoretically derived economic value.

Range acquired the remaining 90% stake in SOCA’s assets with an initial consideration of $64.6m ($52m cash and $12.6m in shares) for 4.32mmboe net 2P reserves onshore Southern Trinidad. Given the additional risks associated with offshore drilling and lower stage of development, we have applied a 50% hair-cut to this for reserves, and a further 50% to contingent resources. As such, our inferred $NPV/bbl is $7.48 for reserves (($64.6m/4.32) x 50%) and $3.74 for contingent resources ($7.48 x 50%).


Classification Working Interest

CoS Resources/Reserves (mmboe)

NPV 10% US$ / bbl

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Gross Net Reserves 65% 100% 29.7 19.3 7.48 144.5 144.5 90.3 90.3 42.0 Contingent resources 65% 75% 27.5 21.0 3.74 78.4 58.8 49.0 36.8 17.1 57.2 40.3 222.9 203.3 139.3 127.1 59.1


The revision to our valuation from November’s initiation has largely arisen from the impact to our DCF analysis. The production downgrades for December 2011 and January 2012 combined with the additional capital expenditure requirement for the refurbishment of the Charlie platform has lowered our net present value (NPV) for the Trintes field.

We use an inferred market multiple from the

recent Range Resources/SOCA Petroleum

transaction of $7.48/bbl for reserves and

$3.74/bbl for contingent resources.


Valuation and recommendation Bayfield Energy | 10 February 12


£ million p/share

Production 96.9 45.1Reserves 90.3 42.0Net Cash* 28.1 13.1Less: G&A (20.0) (9.3)Core Value 195.4 90.9Contingent resources 36.8 17.1Target Market Cap 232.1 108.0


*We have assumed a post placing cash balance using managements FY12E guidence of c.$55m

Our core valuation comprises a revised DCF analysis of Bayfield’s producing assets, the company’s externally verified reserve estimates, and the FY12E net cash balance. We also attribute a discounted general & administrative (G&A) charge for field related expenditure in relation to the Trintes play. On this basis our revised valuation indicates that Bayfield is currently trading at c.80% below its core asset value alone.


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Recommendation and target price revision

In addition to our core value outlined above, we attribute a value to Bayfield’s contingent resources (see appendix 1 for breakdown). Contingent resources contribute a further 17p/share.

The company also has acreage in South Africa (externally verified by Gaffney, Cline and Associates (GCA)), which we do not currently recognise in our target valuation. We have provided a potential valuation for this in the ‘South African operations’ section of this report.

On the basis of today’s operational update, we reiterate our BUY recommendation and set a revised target price of 108p (previously 121p).

Our core valuation includes a revised DCF

analysis of Bayfield’s producing assets, the

company’s externally verified reserve estimates

On the basis of today’s operational update, we

reiterate our BUY recommendation and set a

revised target price of 108p


Bayfield Energy | 10 February 12 Operational review

Operational review

Bayfield has made several strategic changes on the back of today’s announcement, some of which impact our valuation. We have analysed each update in turn to provide investors with a broad understanding of the overall effect on the company’s financial and strategic outlook.

East Galeota - exploration

Strategic update In line with the market’s expectations, Bayfield is due to spud the first of their seven well programme in the East Galeota licence on the 27th January. The well - designated EG8 - is currently being drilled to a total depth of c.2,650m, and is intended to appraise the shallow marine sandstone reservoirs previously encountered through the EG2 and EG5 offset wells. Previous wells indicated that the reservoirs were oil bearing, a feature also confirmed through 3D seismic interpretation. Management expects the well to take between 42 days to complete, with a potential update expected in March 2012. Following the completion of the EG8 well, it is expected that the rig will then drill the EG7 well at an adjacent site.

Our interpretation We feel the timely spudding of EG8 is a positive development for the company given that the market was expecting an update in relation to the well by the end of January. In our view, successful drilling at this relatively low risk site will continue to unlock existing resources, allowing the company to potentially increase their reserve base.

Trintes Field - appraisal

Strategic update Bayfield’s 2011 interims outlined the initial delay in mobilising the company’s new slant rig by four weeks, as a result of weather conditions encountered on the voyage from Louisiana to Trinidad. The company subsequently undertook the necessary repairs to the damage incurred in transit, and has now completed the second of their two-well programme.

B10 well Bayfield successfully completed a short side track at the B10 well in November and the well is currently producing at over 160bopd including a 20% water cut. Management believes there is potential to increase production here by a further 25% by increasing the speed of the down-hole pump.

B8 well Thus far, the B8 well is yielding encouraging results with current data recording strong flow rates. The well encountered c.225ft of net pay, which represents the most prolific well drilled in Trintes to date. The data also de-risks management’s production projections regarding other planned long sidetracks in the field.

Our interpretation B10 and B8 have, so far, yielded positive results. We feel that additional upside is reasonable to expect from B8 in particular, given the productive reservoirs already encountered. B8 is currently producing in the region of 400bopd resulting from this well alone, which if taken in isolation, would act as a positive share price trigger for the company. At this point we have not included potential upside in respect of these wells as part of our valuation until flow rates are established for an extended period.

Bayfield has made several strategic changes on

the back of today’s announcement, some of

which impact our valuation.

We feel the timely spudding of EG8 is a positive

development for the company given that the

market was expecting an update in relation to

the well by the end of January


Operational review Bayfield Energy | 10 February 12

Trintes Field - production

Strategic update Production for December 2011 and January 2012 has been detrimentally impacted by adverse weather conditions, obstructing personnel movements between the shore base and the platforms. Furthermore, additional repairs were required to the main oil export pipeline between the field and onshore tank farm. This has resulted in a curtailment of production from 15th December to 24th January and production completely shut-in between 28th December and 1st January.

Average production for December yielded a gross output of 1,151boepd, whilst January was particularly disappointing at 800boepd – resulting from the slow recovery from the aforementioned shut-in.

Effect on production profile

0

1000

2000

3000

4000

5000

Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12

boep

d (g

ross

)

Previous forecast Current forecast


The above graph illustrates the near term production set back which will impact Bayfield through 1H 2012. Nevertheless, following the reactivation of the hydraulic oil pumping system on the Bravo platform and the completion of B8, gross productive capacity at the field is estimated to be in the region of 1,700bopd.

Our interpretation The disruption to production, whilst outside of management’s control, is disappointing for Bayfield. Cash flow is imperative for the company as they progress with their extensive exploration and appraisal campaign at the East Galeota and Trintes Fields.

The production restriction has reduced the NPV attributable to our valuation by c.10p/share. This is due to a combination of lower initial cash flows, whilst retaining c.$76.5m exploration and appraisal expenditure for FY2012. Nevertheless, the company remains in a strong cash flow position at present with c.$55m on its balance sheet; and with production returning to pre-disruption levels in June, we are not overly concerned with the company’s liquidity position.

Production for December 2011 and January 2012

has been detrimentally impacted by adverse

weather conditions

The production restriction has reduced the NPV

attributable to our valuation by c.10p/share.



Platform refurbishments

Strategic update Bayfield currently owns four fixed platforms (Alpha, Bravo, Charlie and Delta) at the Trintes Field. Since inception, the company has predominantly used Alpha, Bravo and Delta to target its resources. However, recent engineering studies performed in 4Q 2011 indicated that it will not be safe to conduct rig operations from Alpha, and that the costs of remedial work cannot be economically justified.

To counter this, the company maintains that reserves previously targeted through wells drilled from Alpha can also be accessed by new wells from Bravo and Charlie due to the close proximity of the platforms.

Proximity of platforms

Source: Company

Existing production from Alpha (currently 350bopd) will continue to remain on-stream, however any additional production arising from these reservoirs will now need to be produced from Bravo and Charlie going forward.

Bayfield has carried out an internal assessment of the Charlie platform and determined that it can be brought to a suitable condition for rig and production operations in 2013 - at an additional cost of $10-15m.

Our interpretation We feel the market will respond negatively to this development for two key reasons. Firstly, the company's failure to fully evaluate the Alpha platform on acquisition has led to avoidable near-term strategic and financial ramifications. Furthermore, the additional capital requirement to develop the Charlie platform to sufficiently access the reservoirs previously planned from Alpha is material to Bayfield, and places further constraints on the company's liquidity position.

However, management's financial prudence prior to this development does allow for the extra cost to rehabilitate the Charlie platform. In addition, current production from Alpha will be retained despite the dilapidated condition of the platform, which to an extent, stabilises Bayfield’s near term production cash flows.

Recent engineering studies performed in 4Q

2011 indicated that it will not be safe to conduct

rig operations from Alpha

Bayfield has carried out an internal assessment

of the Charlie platform and determined that it

can be brought to a suitable condition for rig and

production operations in 2013 - at an additional

cost of $10-15m



Forward exploration and appraisal drilling programme

Strategic update The above issues have warranted management to implement revisions to their initial seven well drilling programme. Two wells will now be drilled back to back at East Galeota (EG8 and EG7) in 1Q and 2Q this year, targeting Bayfield's largest prospects in this particular licence. After these prospects are drilled, the company expects to drill a third exploration well to the north-east of the Trintes field. These wells will have a Chance of Success (CoS) in the region of 26% - 38%, as designated per GCA's reserve report.

Resource and potential p/share target valuation

05

10

15

2025

30

3540

45

EG8 EG7

(Mm

boe)

0

2

4

6

8

10

12

Risk

ed p

/sha

re

Unrisked mmboe Risked mmboe Risked p/share

Source: Seymour Pierce Limited

The wells will target 55.3mmbbls of net unrisked resources, which if risked on a consistent basis post successful drilling, could yield a combined 18.2p/share to our risked target valuation.

In addition, Bayfield expects to spud the third well in 2013 dependant on the success of the first two wells. The company has secured approval from the Ministry of Energy and Petrotrin (state owned oil company) to vary certain aspects of the well programmes specified in the Galeota Licence and farm-out agreements to lessen the required depths where geological data does not justify certain targets. As such, the well programmes and drilling targets are subject to continuing review and may be subject to change based on the results of the initial wells.

Nevertheless, the remaining four wells are currently scheduled for 2H 2013 (previously April 2013) representing a delay of up to six months from the initial programme.

Our interpretation The revision to Bayfield’s initial drilling programme is a consequence of the operational disruptions arising from the weather disruptions and the relocation to the Charlie platform. Although we feel this disclosure will somewhat damage market sentiment towards the company, it is imperative for Bayfield to execute their drilling campaign in the most strategically beneficial and financially efficient method. To facilitate this, the EG8 well (a vertical well targeting multiple horizons) will target reservoirs containing the highest volume of prospective resources in this location of Bayfield’s acreage (whilst also carrying the highest CoS).

Although we highlight that the financial impact of the delay is marginal, we do appreciate that uncertainty over the timing of the remaining four wells may be a cause for concern for investors.

Management have proposed revisions to their

initial seven well drilling programme

We appreciate that uncertainty over the timing

of the remaining four wells may be a cause for

concern for investors.



South African operations

Strategic update Bayfield has received acceptance from the Petroleum Agency of South Africa (PASA) for the company’s application for the Pletmos inshore licence. Following this, Bayfield has filed all documentation required by PASA which includes a variation to the wording within the document. Following receipt of this revision, a date will be set for the signing of the licence documentation.

Once the licence is approved, Bayfield’s initial focus will be on the reprocessing of existing 2D seismic data over the block, which is expected to be completed this year. In addition, management estimates that any acquisition of new 2D seismic data is unlikely to be undertaken prior to December 2013.

Our interpretation We are encouraged by the positive steps Bayfield are taking to conclude licence negotiations for the Pletmos Basin. This play not only diversifies geographical risk in the company’s portfolio, but also adds further exploration upside outside of its core operations.

The signing of the licence documentation is merely a formality at this stage given the advanced nature of the application and the fact that Bayfield was named as the preferred bidder for the acreage c.2 years ago. The company will hold an effective working interest of 90% (post state back in), and the play is estimated to contain c.625mmboe of net unrisked prospective resources. Interpretation of existing 2D seismic data has identified seven prospects which have been corroborated by GCA.

At present we do not attribute any value to the resources identified by GCA in our target valuation due to the limited activity to date in the Pletmos Basin. However, if risked on a consistent basis to Bayfield’s operations in Trinidad, there is potential for an additional c.40p/share upside once the company undergoes successful drilling and converts its current prospective resource base to the contingent classification.

Risked net asset value - Pletmos Basin

Interval Working Interest


NPV 10% US$ / bbl

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Gross Net 1 90% 18% 43.4 39.1 3.74 146.2 26.3 91.4 16.4 7.62 90% 15% 15.7 14.2 3.74 53.0 7.9 33.1 5.0 2.33 90% 13% 34.2 30.8 3.74 115.0 15.0 71.9 9.3 4.35 90% 8% 6.2 5.6 3.74 20.9 1.7 13.1 1.0 0.59 90% 6% 31.4 28.3 3.74 105.7 6.3 66.0 4.0 1.810 90% 6% 325.5 292.9 3.74 1095.6 65.7 684.7 41.1 19.1GA-VI 90% 10% 44.5 40.0 3.74 149.7 15.0 93.5 9.4 4.4 500.9 450.8 1686.0 137.9 1053.7 86.2 40.1


Russian operations

Strategic update Bayfield has now undertaken the full interpretation of the 2D seismic data acquired over the Karalatsky licence. As a result, the company has not identified any prospects that would justify further investment in an exploration well. Therefore, management has come to the conclusion that it is in the best interests for the company to surrender the Karalatsky licence and dissolve the Astrakhanskaya Gas and Oil Company (AGOC), the local operating company in which it holds a 74% interest. At this point, management does not believe that Bayfield is exposed to any financial penalty or sanction as a result of this decision. However, the company will recognised a non-cash impairment of c.£3.5m in their financial statements as a consequence of the disposal.

Bayfield has received acceptance from PASA

regarding the company’s application for the

Pletmos inshore licence

The signing of the licence documentation is

merely a formality at this stage given the

advanced nature of the application

Management has concluded that it is in the best

interests for the company to surrender the

Karalatsky licence



Our interpretation We feel the company’s exit from Russia is a positive development. In our view, this aspect of Bayfield’s portfolio has been somewhat of a distraction and the movement out of the country reduces Bayfield’s financial exposure to non-core high risk drilling. In terms of our valuation, there will be no impact given that we did not attribute any value to Bayfield's Russian operations, and the recognition of the impairment in 1H 2012 is a non-cash item.


Bayfield Energy | 10 February 12 Appendix 1 – RENAV breakdown Trinidad

Appendix 1 – RENAV breakdown Trinidad

Risked net asset value - Trinidad

Classification Activity Working Interest


NPV 10% US$ / bbl

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Gross Net Reserves Trintes Field Main 65% 100% 17.4 11.3 7.48 84.5 84.5 52.8 52.8 24.6 Reserves Trintes FNE extension 65% 100% 8.1 5.3 7.48 39.5 39.5 24.7 24.7 11.5 Reserves Trintes SW extension M 65% 100% 1.4 0.9 7.48 7.0 7.0 4.4 4.4 2.0 Reserves GAL-9 G&H 65% 100% 1.8 1.2 7.48 9.0 9.0 5.6 5.6 2.6 Reserves Trintes Ext GAL-12 H 65% 100% 0.9 0.6 7.48 4.5 4.5 2.8 2.8 1.3 Contingent EG-1 65% 75% 7.2 4.7 3.74 17.4 13.1 10.9 8.2 3.8 Contingent EG-2 65% 75% 3.2 5.2 3.74 19.3 14.5 12.1 9.0 4.2 Contingent EG-3 65% 75% 5.4 3.5 3.74 13.1 9.9 8.2 6.2 2.9 Contingent EG-4 65% 75% 11.0 7.2 3.74 26.8 20.1 16.7 12.6 5.8 Contingent GAL-21 65% 75% 0.7 0.5 3.74 1.8 1.3 1.1 0.8 0.4 57.2 40.3 222.9 203.3 139.3 127.1 59.1



Financial model Bayfield Energy | 10 February 12

Financial model

Income Statement


2009A 2010A 2011E 2012E 2013E

Group revenue 16.2 16.8 20.9 25.2 27.2Cost of sales (10.0) (308.7) (384.9) (337.4) (343.7)Gross profit 6.1 (291.9) (364.0) (312.2) (316.5)Total operating expenses (0.4) (0.3) 0.0 0.0 0.0EBIT 5.8 (292.2) (363.9) (312.2) (316.5)Net interest/financial income/(cost) (0.2) (0.1) (0.5) (0.2) (0.0)Associate and Other non-op. income/(cost) 0.0 0.0 0.0 0.0 0.0PBT 5.9 5.7 7.4 9.5 10.8Tax (2.5) (2.2) (3.4) (4.0) (4.6)Effective tax rate (%) 41.4 38.4 45.8 42.0 42.0Minorities 0.2 0.1 0.1 0.1 0.1Earnings 3.5 3.5 4.0 5.5 6.3 EBITDA 7.5 (290.1) (361.3) (308.4) (312.6)Adjusted EBITDA* 7.9 8.1 10.2 13.2 14.4Adjusted EBIT* 6.1 5.9 7.5 9.4 10.4Adjusted PBT* 5.9 5.7 7.4 9.5 10.8Adjusted earnings* 3.5 3.5 4.0 5.5 6.3 DPS (p) 0.2 0.2 0.3 0.3 0.3EPS (p) 1.0 1.0 1.2 1.6 1.8EPS [F. Dil.] (p) 1.0 1.0 1.1 1.6 1.8EPS [Adj.]* (p) 1.0 1.0 1.2 1.6 1.8EPS [Adj. F. Dil.]* (p) 1.0 1.0 1.1 1.6 1.8Weighted average no. shares (m) 3,363.0 3,380.0 3,380.0 3,380.0 3,388.0Fully dil. w. ave. no. shares (m) 3,389.0 3,400.0 3,400.0 3,400.0 3,410.0Year end no. shares (m) 3,363.0 3,380.0 3,380.0 3,380.0 3,388.0




Bayfield Energy | 10 February 12 Financial model

Cashflow Statement


2009A 2010A 2011E 2012E 2013E

Operating income 5.8 (292.2) (363.9) (312.2) (316.5)Amortisation of acquired intangibles 0.0 0.0 0.0 0.0 0.0Amortisation of other intangibles 0.0 0.0 0.0 0.0 0.0Depreciation 1.8 2.2 2.6 3.8 3.9Net change in working capital (0.7) (0.8) 1.1 (0.2) (0.1)Other 1.5 1.8 1.9 1.9 1.9Operating cash flow 8.4 (289.0) (358.3) (306.7) (310.8) Capital expenditure (6.8) (8.4) (9.0) (5.0) (5.0)Investment in Other intangibles 0.0 0.0 0.0 0.0 0.0Net interest/financial income/(cost) (0.2) (0.2) (0.5) (0.2) (0.0)Tax paid (2.1) (2.0) (3.0) (4.0) (4.6)Net acqns./disposals (7.7) (7.3) (8.9) (4.9) (4.9)Dividend paid (0.7) (0.8) (0.9) (0.9) (1.2)Other (1.5) (0.4) (0.3) (0.6) (1.2)Cash flow before financing (10.5) (308.1) (380.7) (322.4) (327.7) Proceeds from shares issued 0.1 0.1 0.0 0.0 0.0Investments 1.1 0.5 0.2 0.0 0.0Other 2.9 3.2 2.9 0.0 0.0Net movement in cash/(debt) (6.4) (304.3) (377.6) (322.4) (327.7) Opening net cash/(debt) 1.5 (5.1) (7.2) (2.8) 0.3Adjustments (Forex, etc.) 0.0 0.0 (0.1) 0.0 0.0Closing net cash/(debt) 1.1 2.5 3.9 6.4 9.0 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2009A 2010A 2011E 2012E 2013E

Property plant and equipment 20.1 28.3 33.3 34.5 35.6Goodwill and Acquired intangibles 0.8 0.8 0.8 0.8 0.8Other intangibles 9.3 7.2 7.2 7.0 6.8Other fixed assets 3.8 3.8 4.7 5.0 5.3Non current assets 34.0 40.1 46.0 47.2 48.4 Stocks & WIP 0.8 0.7 0.8 1.0 1.0Trade receivables 4.7 6.0 5.6 6.4 7.0Cash 1.1 2.5 3.9 6.4 9.0Other current assets 2.9 3.3 4.5 7.0 9.7Current assets 8.4 10.2 11.2 14.7 17.9 Total assets 42.4 50.3 57.1 61.9 66.3 Trade creditors 4.2 4.4 5.3 6.1 6.6Short term borrowings 1.2 1.3 2.2 2.8 1.8Long term borrowings 5.0 8.4 4.5 3.3 3.1Other liabilities 8.8 9.4 9.8 9.8 9.8Total liabilities 19.2 23.6 21.9 22.1 21.3 Net assets 23.2 26.7 35.2 39.8 44.9 Issued share capital 0.0 0.0 0.0 0.0 0.0Share premium account 0.0 0.0 0.0 0.0 0.0Retained earnings 0.0 0.0 0.0 0.0 0.0Other reserves 0.0 0.0 0.0 0.0 0.0Minority interests 0.3 0.4 0.3 0.4 0.5Total equity 23.2 26.7 35.2 39.8 44.9



Financial model Bayfield Energy | 10 February 12

Key Ratios

Year end December

2009A 2010A 2011E 2012E 2013E

Revenue growth (%) n/a 3.7 24.7 20.6 7.8Adj. EBITDA* growth (%) n/a 2.0 26.3 29.6 9.1Adj. EBIT* growth (%) n/a (4.0) 27.7 24.4 11.4Gross margin (%) 38.0 (1,740.3) (1,740.3) (1,237.2) (1,163.8)Adj. EBITDA* margin (%) 48.8 48.0 48.6 52.2 52.9Adj. EBIT* margin (%) 38.0 35.2 36.0 37.1 38.4 Gearing (%) n/a n/a n/a n/a n/aInterest cover (x) 34.3 55.1 16.4 39.3 567.9Net debt/Adj. EBITDA* (x) 0.1 0.3 0.4 0.5 0.6Dividend cover (x) 4.8 4.3 4.5 5.7 5.3 ROE (%) 14.9 13.1 11.4 13.9 14.0ROIC (%) 51.3 41.7 44.7 110.3 125.7ROCE (%) 51.3 41.7 44.7 110.3 125.7 Operating cash conversion (%) 111.6 99.6 99.2 99.5 99.4Net cash conversion (%) (283.7) (8,781.2) (9,463.4) (5,827.6) (5,195.4)Net working cap / revenue (%) (4.1) (4.6) 5.5 (0.7) (0.4)Cap Ex / revenue (%) 41.8 50.1 42.9 19.8 18.4



Valuation Metrics

Year end December

2009A 2010A 2011E 2012E 2013E

PER (x) 1,506.6 1,476.7 1,289.1 934.1 819.7EV / Revenue^ (x) 3,131.7 3,019.3 2,421.3 2,006.9 1,861.7EV / Adj. EBITDA^* (x) 6,415.8 6,288.4 4,980.7 3,842.6 3,521.5EV / Adj. EBIT^* (x) 8,243.6 8,586.0 6,723.5 5,403.7 4,849.2EV / IC^ (x) 2,324.0 2,128.2 1,631.8 1,534.6 1,430.7EV / Taxed Adj. EBIT^* (x) 14,213.0 14,803.4 11,592.3 9,316.7 8,360.8 Yield (%) 0.0 0.0 0.0 0.0 0.0P / CFPS (x) (5,094.9) (164.0) (132.7) (156.8) (154.8)NAV per share (p) 0.7 0.8 1.0 1.2 1.3





Bayfield Energy | 10 February 12 Financial model


0

20

40

60

80

100

120

140





Always believe in your soul Gold continues to make encouraging progress, both in terms of production upgrades and high impact exploration. We feel a successful farm down of the company’s Z34 acreage in Peru; will represent a clear milestone for the company as they look to prove up the significant resource potential in the Block.

Robust increase in near term production In 2011 Gold completed a workover programme at its Nancy-Burdine-Maxine (NBM) oil field which saw production double to the current 600 bopd (gross) level versus 1HFY11 (period ending 31 October 2010). In the longer term production is forecasted to increase c.5x versus 1HFY11 levels; reaching an average of 1,400 bopd in 1HFY13.

Farm out potential Gold have been very explicit in terms of their strategic outlook relating to a significant farm out of their 100% interest in Block Z34, Peru. The block holds approximately 1.4bn bbl of contingent resources, and as such represents significant upside to investors even post farm-out. We assume that Gold intends to farm down c.50% of their acreage and also include a recovery of past capital expenditure (c.$20m) and to be carried for up to three wells. We have used a mid-case (two well) scenario in our target valuation, and assess the Block Z34 value post farm down to contribute 2.9p/share to our target price.

Block XXI farm down The company is due to conclude the 70% joint operating agreement with Vale S.A. Vale will pay an upfront cash consideration of $2m and will carry Gold through the remaining exploration programme capped at $10m. We feel this agreement has acted as a milestone for the company and contributes 0.8p to our target valuation.

Valuation and recommendation We feel the market clearly does not attribute any value to Gold’s significant prospective resource base in Peru, which we believe represents a core driver for the company going forward. Gold also benefits from a robust mix of production and impending high impact exploration, which we feel represents a strong buying opportunity for investors at current levels. Our core valuation (production plus net cash) is 2.4p, whilst cash due from Vale and other exploration assets add another 5.6p. On this basis, we continue coverage with a BUY recommendation and a target price of 8p. 3,5 Please see regulatory disclosure notes at the end of this document A draft of this research has been shown to the company following which minor factual amendments have been made.


Gold Oil Plc( LSE:GOO.L) 3,5

BUY Share price 3p



Net cash (£m) 10.5





PER at Target price (Y1) (414.8)

Sector PER 0.0

Price/book 1.3


(%) 1m 3m 12m

Absolute -0.7 -13.3 -45.8

FTA relative -4.8 -18.9 -44.9


1.0

2.0

3.0

4.0

5.0

6.0


Price Relative

Source: Datastream


Next news Operational updates - Peru

Business Exploration, appraisal, development and

production of oil and natural gas.

www.goldoilplc.com



Year end December

Revenue(£m)

EBIT*(£m)

PBT*(£m)

Tax(%)

Adj. EPS* (p)

PER (x)

EV/EBIT*(x)

Div yield(%)

2010A 1.0 (0.8) (0.9) (12.2) (0.2) (14.0) (16.3) 0.02011A 1.2 (1.5) (1.6) 0.1 (0.3) (10.3) (8.9) 0.02012E 1.6 (0.1) (0.1) (50.0) (0.0) (140.7) (95.4) 0.02013E 3.6 0.3 0.3 (50.0) 0.1 49.8 43.4 0.02014E 9.0 2.5 2.5 30.0 0.2 14.0 5.6 0.0

* excludes exceptional items and amortisation of acquired intangibles.^ EV calculation adjusted for core cash, investments etc.



Gold Oil Plc | 10 February 12 Valuation and recommendation


Our valuation of Gold Oil comprises three key components:

1. Discounted cash flow analysis of the NBM field.

2. Risked net asset appraisal of the company’s contingent resources in Peru and Colombia.

3. Scenario analysis post Block Z34 farm down

The implicit assumptions used in our risked valuation are as follows:


Metric Assumption

NPV $/mmboe - Colombia 20.00 NPV $/mmboe - Peru 6.00 Long term exchange rate $/£ $1.65/£1 Number of shares outstanding (m) 891.51 Chance of exploration success - Colombia 50% Chance of exploration success - Peru 10% Discount rate 10%


Discounted cash flow analysis We have modelled the cash flows arising from the company’s Nancy-Burdine-Maxine (NBM) oil field against the PSC terms in Peru. This yields a net present value of c.$28m when discounted at 10%, contributing 1.9p/share to our target price.

Risked net asset evaluation We also provide a risked net asset valuation of Gold’s prospective resources in Colombia (Azar Block) and Peru (Block XXI) as follows:


Country Project Interest CoS/CoD Prospective Rec. Resources (mmboe)

NPV 10% US$ / boe

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Gross Net Colombia La Vega East 20% 50% 3 0.6 20 12.0 6.0 7.3 3.6 0.4 Colombia La Vega South 20% 50% 3 0.6 20 12.0 6.0 7.3 3.6 0.4 Colombia La Vega West 20% 50% 3 0.6 20 12.0 6.0 7.3 3.6 0.4 Peru Prospect A 30% 10% 25 7.5 6 45.0 4.5 27.3 2.7 0.3 Peru Prospect B 30% 10% 30 9 6 54.0 5.4 32.7 3.3 0.4 64.0 18.3 72.0 135.0 27.9 81.8 16.9 1.9


We have assumed an NPV/bbl at each field based on transaction values in each country respectively. At the Azar Block we assume an NPV/bbl of US$20 – in line with the Ecopetrol and Talisman Energy takeover of BP’s Colombian assets in 2010, which equates to US$20.21/bbl. For Block XXI we have used the inferred market valuation from D&M’s certified volume estimates for Karoon Gas of $6/bbl.

On this basis, our risked valuation of Gold’s prospective resources yield’s 1.9p/share to our target valuation.

Scenario analysis of Z34 farm out Gold have been very explicit in terms of their strategic outlook incorporating a significant farm down of their 100% interest in Block Z34 Peru. The block holds approximately 1.4bn bbl of contingent resources and as such represents significant upside to investors even post farm-out.


Valuation and recommendation Gold Oil Plc | 10 February 12

We assume that Gold intends to farm-out c.50% of their acreage and also include a recovery of past capital expenditure (c.$20m) and to be carried for up to three wells.

The company expects each well to cost in the region of $75m to drill, and we risk each scenario at 50% in terms of chance of success.

As such we incorporate the following assumptions into our farm-out scenario analysis valuation:

Scenario analysis assumptions

Metric Assumption

Past capex $20 Well cost $75 No of wells Up to three Final interest 50% Risking 50%


Using the above prudent assumptions we have valued a three well case scenario valuation:

Scenario valuation

Scenario $m £m p/share Risked p/shr

1 well $95 £58 6.5 1.6 2 well $170 £103 11.6 2.9 3 well $245 £148 16.7 4.2


On this basis, we will incorporate a mid-case (two well) scenario in our target valuation, and assess the Block Z34 value post farm out to contribute 2.9p/share to our target price.

Overall valuation Our sum-of-the-parts (SOTP) valuation will combine all of the above individual components as well as net cash. In addition, the company has successfully concluded the 70% joint operating agreement with Vale S.A. Vale will pay an upfront cash consideration of $2m and will carry Gold through the remaining exploration programme capped at $10m. We feel this agreement has acted as a milestone for the company and contributes 0.8p to our target valuation.


£ million p/share

NBM DCF 16.7 1.9 Net Cash 5.1 0.6 Core value 21.8 2.4 Z34 (2W) 11.6 2.9 Vale cash 7.3 0.8 Other exploration 16.9 1.9 Gross Value 57.5 8.0



Gold Oil Plc | 10 February 12 Valuation and recommendation


2.9

1.9

1.9

0.8

0.6

0

1

2

3

4

5

6

7

8

9

Net Cash Vale cash NBM DCF Other exploration Z34 (2W)

p/sh

are



We feel the market clearly does not attribute any value to Gold’s significant prospective resource base in Peru, which we feel represents a core driver for the company. The company also benefits from a robust mix of production and high impending high impact exploration, which we feel represents a strong buying opportunity for investors at current levels.

Our core valuation (production plus net cash) is 2.4p, whilst cash due from Vale and other exploration assets add another 5.6p. On this basis, we continue coverage with a BUY recommendation and a target price of 8p.


Operations Gold Oil Plc | 10 February 12

Operations

Gold currently has exploration and production operations in Colombia and Peru. Production is currently confined to Colombia where the company operates its Nancy-Burdine-Maxine oil field. The company has a robust exploration and development programme planned during 2011 and 2012, which encompass its entire portfolio of assets.

Overview of key assets

Onshore Colombia

Onshore Colombia

Onshore Peru

Offshore Peru

Drill La Vega East well Sept/Oct 2011

Drill Nancy-2 well and renegotiate contract

400 sq. Kms. 2D seismic Drill in 2012

Min 500 sq. kms. 3D seismic Seek partner to Drill in 2012/13

Planned Activity

3D seismic acquired and interpreted. Civil works for drilling In preparation

Nancy -1 producing. Workover of Burdinewells completed. Long term testing

Farmed out to Vale. Awaiting assignment approval

Acquired/Interpreted 2D seismic. LOI with BGP for 500km2 3D programme

Status

Geographic focus

20%58%30%100%Working Interest

AzarNancy BurdineBlock XXIBlock Z34Projects

Onshore Colombia

Onshore Colombia

Onshore Peru

Offshore Peru

Drill La Vega East well Sept/Oct 2011

Drill Nancy-2 well and renegotiate contract

400 sq. Kms. 2D seismic Drill in 2012

Min 500 sq. kms. 3D seismic Seek partner to Drill in 2012/13

Planned Activity

3D seismic acquired and interpreted. Civil works for drilling In preparation

Nancy -1 producing. Workover of Burdinewells completed. Long term testing

Farmed out to Vale. Awaiting assignment approval

Acquired/Interpreted 2D seismic. LOI with BGP for 500km2 3D programme

Status

Geographic focus

20%58%30%100%Working Interest

AzarNancy BurdineBlock XXIBlock Z34Projects

Source: Company data and Seymour Pierce Limited

Peru

Gold’s Peruvian assets consist of 2 operational projects: Block XXI (30% interest) and Block Z34 (100%). In January Vale, the Brazilian mining company, farmed into Block XXI. At Block Z34, Gold is scheduled to begin a 3D seismic survey covering 500 sq. kms. (~310 sq. miles) in early July after which it intends to farmout a stake, on terms similar to Block XXI. Gold's Peruvian assets are key to the company's exploration potential and valuation with Block Z34 alone having an unrisked prospective P50 resources of c.1.4bn bbls

Offshore Block Z34 (100% interest and operated) Block Z34 is located offshore western Peru at the Northern boundary with Ecuador. The block covers an area of ~3,700 sq. kms (2,300 sq. miles) and is bounded to the East by Block Z2B operated by Savia Peru and to the North by Block Z30 operated by Karoon. Gold has a 100% interest and is operator of the block. Z34 is located in the Talara Basin, next to the Talara oil fields which have produced approximately 1.6 billion barrels to date and have a current daily production of over 12,000 bopd. Although the whole block is considered highly attractive it is in relatively deep water (100–2,000m) and hence the Southern part of the block (highly prospective and in shallower water) is a priority for Gold’s seismic acquisition and exploration drilling.

Production is currently confined to Colombia

where Gold operates its NBM oil field

At Block Z34, Gold is scheduled to begin a 3D

seismic survey covering 500 sq. kms. in early

July

The southern part of block Z34 lies in shallower

water and is hence a priority for Gold’s 3D

seismic acquisition and exploration drilling


Gold Oil Plc | 10 February 12 Operations

Block Z34 location


History: Gold entered into a promotion licence with Perupetro in 2005 and qualified as operator in July 2006. In March 2007 Gold was granted the licence for Block Z34 together with Plectrum Petroleum Plc (50% interest). Plectrum was subsequently purchased by a subsidiary of Cairn Energy, from whom Gold purchased the remaining 50% in 2008. Gold began acquisition of 2,013 sq. kms (1,250 sq. miles) of 2D seismic in 2009. Z34 had negligible exploration prior to this with no well drilled in the bulk of the permit. Gold completed processing of 2D seismic in 2009 with interpretation completed in 2010. Preliminary interpretation of seismic data indicates the block has significant potential and a number of leads have been identified.

Z34 Prospects and Leads

Planned 3D Seismic area

Chilcano

Pisco

Francesca

CuyProspect ‘G’

Planned 3D Seismic area

Chilcano

Pisco

Francesca

CuyProspect ‘G’


Recent developments: In late May Gold announced it had contracted BGP Geoexplorer PTE to acquire 500 sq. kms of 3D seismic over Block Z34 after receiving an

Preliminary interpretation of 2D seismic data

indicates significant potential and a number of

leads have been identified.

In May Gold received environmental clearance

and contracted the acquisition of 3D seismic



environmental permit (PMA) from the Peruvian Ministry of mines earlier in the month. The permit allows the company to shoot a maximum of 808 sq kms (501 sq. miles) of 3D seismic.

Planned activity: The BGP Pioneer vessel has been mobilised and is expected to commence operations in early July. Seismic acquisition is expected to take 30 days from commencement with interpretation expected to take 3-4 months to complete. Post interpretation of seismic data, Gold intends to farmout a stake in the block, in an arrangement similar to Block XXI. Gold expects to reach a farmout agreement for Block Z34 by the end of 1HCY12 and plans to drill an exploration well in 3QCY12.

Block XXI (30% interest and operated) Block XXI located in northwest Peru covers an area of 3,030 sq. kms (~1,890 sq. miles) and is ~50 miles north west of the port town of Talara which is an oilfield hub. Gold has a 30% interest in the block and is currently the operator.

Block XXI, Onshore Peru


History: Gold entered into a promotion licence with Perupetro in October 2004 and was formally awarded the licence in December 2005 with an exploration period of seven years. In 2005 Gold completed 5,200 sq. kms (3,200 sq. miles) of aeromagnetic survey which identified six leads. In 2006 Gold drilled the San Alberto-1X well which encountered good porosity. The San Alberto-2 X well was subsequently drilled in 2008. Drilling demonstrated the existence of effective reservoirs. Gold concluded it needed to acquire seismic before progressing further on the block.

Recent developments: In January Gold announced that it had signed a farm out and JV agreement for Block XXI with Vale. Under the agreement, Vale paid an US$2m upfront cash consideration and will carry Gold through the remaining exploration programme (maximum of US$10m gross; US$3m attributable to Gold) in return for a 70% interest in Block XXI. Gold retains a 30% interest in the block and Vale will take over as operator. (The agreement is subject to approval by Perupetro and Gold will remain operator until the agreement is formally approved and Vale has personnel in Peru to operate Block XXI). Gold expects Vale to take over operatorship in 3QCY11.

Planned activity: The JV partners plan to acquire 400 sq kms of 2D seismic data in 4Q CY11 and drill a well each in 2QCY12 and 4QCY12. We note that Gold is free carried on the seismic acquisition and drilling, as per terms of its farm out agreement with Vale.

Gold expects to reach a farmout agreement by

1HCY12 end and drill an exploration well in

3QCY12.

Block XXI located in northwest Peru covers an

area of 3,030 sq. kms

Gold drilled a well in 2008 which demonstrated

the existence of an effective reservoir.

400 sq kms of 2D seismic data to be acquired in

4Q CY11 and drilling a well planned in 2QCY12

and 4QCY12.


Gold Oil Plc | 10 February 12 Operations

Colombia

Gold Oil Colombia was established in 2006. Colombia is Gold’s principal operating country, where it currently has 3 operational projects: The Nancy-Burdine-Maxine (NBM) oil field, Azar and Rosa Blanca blocks.

Nancy-Burdine-Maxine (27.4% net interest and operated) The Nancy-Burdine-Maxine (NBM) oil field is located in South West Colombia. Gold has a 58.05% working interest and is operator of the field. Termotecnica (18.05%), ISP (18.05%), Bioss (2.84%) and VHF (3%) are the other partners.

As per the terms of the licence at NBM, a royalty of 20% applies to Gold and partners before Ecopetrol takes a 41% share with no contribution to capital or operating costs. Oil from the NBM fields sells at a netback price related to West Texas Intermediate but at a discount (approx. $10/bbl) resulting from pipeline transport costs and quality adjustments (API gravity of 28-30°; WTI at 39.6°).

Production: In fiscal 2010 the Nancy-1 well had net production attributable to Gold of 26,000 bbls of oil; at an average rate of 71 bopd. In March, 2011 Gold successfully completed a workover programme on the Burdine-5 well resulting in the well coming on stream at an 82 bopd net (300 gross) rate. Current production from the NBM field is 165 bopd net (600 bopd gross).

History: The NBM fields were discovered by Texaco and bought on stream in 1976. The Nancy-1 well initially produced 1,400 bopd declining to 230 bopd by 1978 subsequently increasing to 670 bopd when pumping was added. Argosy International later assumed control of NBM. In 1995 the NBM field was abandoned due to a lack of economic feasibility, at which stage Nancy-1 produced 200 bopd with no water. The fields were returned to Ecopetrol who licensed them to the Union Temporal in 2003.

In April 2008 a geological and geophysical report concluded that there were additional oil zones in the Nancy and Burdine fields that had not been perforated and areas of the field were not being effectively drained. Subsequently the partners commissioned an independent reservoir engineering study. In January 2011 Gold and its partners commenced a workover programme on the Burdine field. The programme planned to re-enter the Burdine-1, 4 and 5 wells. Burdine-1 and 5 are planned as oil producing wells whilst Burdine-4 will operate as a water disposal well. Gold estimated the workover will add between 200 and 400 bopd of gross production (between 55 and 109 bopd net) to the NBM fields current production.

Recent developments: In mid March Gold announced the workover programme at Burdine-5 had been completed and the well was bought on stream at a net rate of 82 bopd (300 bopd gross); doubling company wide net production.

Planned activity: Gold plans to drill the Nancy-2 development well in 4QCY11. Nancy-2 is expected to come on steam in March 2012 with production estimated at 220 bopd net (800 bopd gross). Additionally Gold plans to acquire 30 sq. kms of 2D seismic over the NBM field in 2QCY12.

Azar (20% working interest and non operated) Gold has a 20% working interest in the Azar Block, located to the northeast of the NBM fields. Gran Tierra (40% and operator) and Lewis Energy (40%) are the other partners.

History: Ecopetrol drilled the Palmera -1 well on the Azar Block in 1996. Subsequent logging indicated the well was not economically feasible at the time. In October 2006 Gold and its partners entered into a licence contract for the Azar block, granting them the right to explore for a 6 year period and an exploitation period of 24 year. The well was re-entered in 2QCY08 and tested 50 bopd (15° API oil) at a depth of 7,860 feet.

Recent developments: 72 sq. kms (~45 sq. miles) of 3D seismic was acquired over the LA Florida structure, located in the North of the block. Based on an earlier seismic survey two prospects, have been identified: La Vega Sur and East.

Gold has 3 operational projects in Colombia: The

Nancy-Burdine-Maxine (NBM) oil field, Azar and

Rosa Blanca blocks.

Current production from the NBM field is 165

bopd net; 600 bop gross.

In mid March production from the NBM field

doubled post completion of the workover

programme.



Planned activity: The seismic data was interpreted and the JV partners decided to drill a well in 3QCY11. Additionally the partners agreed to drill two more contingent wells in 2QCY12 and 4QCY12. As a result of a prior farm-in agreement Gold only has to contribute half its stake (i.e. 10% instead of its 20% interest) to the cost of the next well drilled. Gold would have to pay its full share for any subsequent wells drilled.

Rosa Blanca (25.2% interest and non operated) The Rosa Blanca block is located in the upper part of the Middle Magdalena Basin, covers ~175 sq. miles (45,000 Ha) and is surrounded by oil producing fields. In November 2010 Gold signed an agreement with Montecz SA, a Colombian company, to farm out a stake at Rosa Blanca. As per the terms of the agreement Montecz would pay 100% of costs (up to US$2m gross) in exchange for a 72% stake in Rosa Blanca. Gold retained a 25.2% interest in Rosa Blanca whilst Empresa, the third partner in the JV, retained a 2.8% stake.

The Rosa Blanca-2 well was spudded in January and drilled to a depth of c.2,900 feet. Drill stem tests (DST) were carried out on the Rosa Blanca and Tablazo formations. The DST on the Rosa Blanca formation failed to flow, indicating the reservoir was tight and non commercial, whilst the Tablazo formation flowed only water.

Recent developments: The JV partners are currently evaluating results at Rosa Blanca and will decide on the future of the block. We note that Gold was free carried on the exploration well, as per terms of the farmout. Should the JV partners decide to progress on the Rosa Blanca block, Gold would have to contribute its proportional share of the cost. We believe this to be unlikely; the most probable development at Rosa Blanca would be the JV partners relinquish the block.

Other operations Colombia and Peru remain central to Gold’s operational strategy. However, the company has indicated that it continues to pursue opportunities in Latin America and the Caribbean. Gold’s strategy is to selectively approach countries taking into account geological potential but being mindful of geopolitical risks. The company stated that it has identified some exciting opportunities which it seeks to acquire in the medium term.

Operations timeline

Onshore Seismic

Offshore Seismic

Partner Negotiations

Drilling/Workovers

Colombia

20%Additional drilling (contingent)

20%Drill La Vega East wellAzar Block

58.05%Acquire 30 km 2D seismic

58.05%Drill Nancy-2 well

58.05%Workover Burdine existing wellsNancy Burdine

30%Drill exploration well(s)

30%Acquire 400 km 2D seismicBlock XXI

Drill exploration well

100%Seek farm in partner

100%Process/Interpret 3D seismic

100%Acquire 500 sq km 3D seismicBlock Z34

Q4Q3Q2Q1Q4Q3Q2

20122011Gold Oil WI%Peru

Onshore Seismic

Offshore Seismic

Partner Negotiations

Drilling/Workovers

Colombia

20%Additional drilling (contingent)

20%Drill La Vega East wellAzar Block

58.05%Acquire 30 km 2D seismic

58.05%Drill Nancy-2 well

58.05%Workover Burdine existing wellsNancy Burdine

30%Drill exploration well(s)

30%Acquire 400 km 2D seismicBlock XXI

Drill exploration well

100%Seek farm in partner

100%Process/Interpret 3D seismic

100%Acquire 500 sq km 3D seismicBlock Z34

Q4Q3Q2Q1Q4Q3Q2

20122011Gold Oil WI%Peru


In November 2010 Gold signed an agreement

with Montecz to farm out 72% stake; retaining a

25.2% interest

We believe the JV partners will relinquish the

Rosa Blanca block.

Gold’s strategy is to selectively approach

countries taking into account geological

potential but being mindful of geopolitical risks.


Gold Oil Plc | 10 February 12 Financial model

Financial model

Income Statement


2010A 2011A 2012E 2013E 2014E

Group revenue 1.0 1.2 1.6 3.6 9.0Cost of sales (0.6) (0.6) (0.8) (1.8) (4.5)Gross profit 0.4 0.5 0.8 1.8 4.5Total operating expenses (1.3) (2.1) (1.0) (1.5) (2.0)EBIT (0.8) (1.5) (0.1) 0.3 2.5Net interest/financial income/(cost) (0.0) (0.0) 0.0 0.0 0.0Associate and Other non-op. income/(cost) 0.0 0.0 0.0 0.0 0.0PBT (0.9) (1.6) (0.1) 0.3 2.5Tax (0.1) 0.0 (0.1) 0.2 (0.7)Effective tax rate (%) (12.2) 0.1 (50.0) (50.0) 30.0Minorities 0.0 0.0 0.0 0.0 0.0Earnings (1.0) (1.6) (0.2) 0.5 1.7 EBITDA (0.8) (1.2) 0.2 0.8 2.9Adjusted EBITDA* (0.8) (1.2) 0.2 0.8 2.9Adjusted EBIT* (0.8) (1.5) (0.1) 0.3 2.5Adjusted PBT* (0.9) (1.6) (0.1) 0.3 2.5Adjusted earnings* (1.0) (1.6) (0.2) 0.5 1.7 DPS (p) 0.0 0.0 0.0 0.0 0.0EPS (p) (0.2) (0.3) (0.0) 0.1 0.2EPS [F. Dil.] (p) (0.2) (0.3) (0.0) 0.1 0.2EPS [Adj.]* (p) (0.2) (0.3) (0.0) 0.1 0.2EPS [Adj. F. Dil.]* (p) (0.2) (0.3) (0.0) 0.1 0.2Weighted average no. shares (m) 500.7 595.3 891.5 891.5 891.5Fully dil. w. ave. no. shares (m) 561.0 604.8 891.5 891.5 891.5Year end no. shares (m) 561.0 604.8 891.5 891.5 891.5




Financial model Gold Oil Plc | 10 February 12

Cashflow Statement


2010A 2011A 2012E 2013E 2014E

Operating income (0.8) (1.5) (0.1) 0.3 2.5Amortisation of acquired intangibles 0.0 0.0 0.0 0.0 0.0Amortisation of other intangibles 0.0 0.0 0.0 0.0 0.0Depreciation 0.0 0.3 0.3 0.5 0.5Net change in working capital 1.2 1.3 (1.9) 0.1 0.2Other 0.0 0.0 0.0 0.0 0.0Operating cash flow 0.3 0.1 (1.7) 1.0 3.2 Capital expenditure (1.1) (2.3) (6.1) (2.6) (0.7)Investment in Other intangibles 0.0 0.0 0.0 0.0 0.0Net interest/financial income/(cost) (0.0) (0.0) 0.0 0.0 0.0Tax paid 0.1 (0.0) 0.1 (0.2) 0.7Net acqns./disposals (1.1) (2.3) (6.1) (2.5) (0.6)Dividend paid 0.0 0.0 0.0 0.0 0.0Other 0.0 0.0 0.0 0.0 0.0Cash flow before financing (1.8) (4.6) (13.7) (4.3) 2.6 Proceeds from shares issued 0.0 11.2 0.0 0.0 0.0Investments 0.0 0.0 0.0 0.0 0.0Other 0.0 0.0 (0.6) 0.0 0.0Net movement in cash/(debt) (1.7) 6.6 (14.4) (4.3) 2.6 Opening net cash/(debt) 1.0 1.7 10.5 2.2 0.6Adjustments (Forex, etc.) 0.0 0.0 0.0 0.0 0.0Closing net cash/(debt) 1.7 10.5 2.2 0.6 2.9 Source: Company data, Seymour Pierce Ltd

Balance Sheet


2010A 2011A 2012E 2013E 2014E





Key Ratios

Year end December

2010A 2011A 2012E 2013E 2014E

Revenue growth (%) n/a 22.0 38.9 124.2 146.5Adj. EBITDA* growth (%) n/a 50.0 (113.7) 401.3 248.1Adj. EBIT* growth (%) n/a 82.4 (90.6) (319.7) 678.3Gross margin (%) 42.0 45.4 51.3 50.0 50.0Adj. EBITDA* margin (%) (85.7) (105.3) 10.4 23.3 32.9Adj. EBIT* margin (%) (88.7) (132.6) (9.0) 8.8 27.7 Gearing (%) n/a n/a n/a n/a n/aInterest cover (x) (40.4) (48.4) n/a n/a n/aNet debt/Adj. EBITDA* (x) (2.1) (8.5) 12.8 0.7 1.0Dividend cover (x) n/a n/a n/a n/a n/a ROE (%) (12.4) (8.4) (1.0) 2.8 9.0ROIC (%) (88.3) (68.2) (2.8) 19.2 268.0ROCE (%) (88.3) (68.2) (2.8) 19.2 268.0 Operating cash conversion (%) (41.5) (5.7) (1,012.2) 116.0 107.4Net cash conversion (%) 181.0 290.2 7,929.2 (870.5) 151.5Net working cap / revenue (%) 121.2 111.3 (115.8) 3.7 2.4Cap Ex / revenue (%) 115.5 198.3 374.6 70.1 7.2



Valuation Metrics

Year end December

2010A 2011A 2012E 2013E 2014E

PER (x) (14.0) (10.3) (140.7) 49.8 14.0EV / Revenue^ (x) 14.5 11.9 8.5 3.8 1.5EV / Adj. EBITDA^* (x) (16.9) (11.3) 82.0 16.4 4.7EV / Adj. EBIT^* (x) (16.3) (8.9) (95.4) 43.4 5.6EV / IC^ (x) 2.3 1.6 0.9 0.8 0.8EV / Taxed Adj. EBIT^* (x) (23.3) (12.8) (136.2) 62.0 8.0 Yield (%) 0.0 0.0 0.0 0.0 0.0P / CFPS (x) (7.7) (3.5) (1.8) (5.7) 9.2NAV per share (p) 1.4 3.1 2.0 2.0 2.2





Financial model Gold Oil Plc | 10 February 12


0

1

2

3

4

5

6

7

8

9





Gas storage potential Independent Resources is making encouraging progress in the development of its planned major underground gas storage facility in Italy. We feel that the advancement of this process represents the long term upside for investors; whilst in the near term, a successful farm-out of the Independent’s shale gas play in Tuscany could be a transformational event.

Italian gas storage Independent plans to construct a large underground storage (UGS) facility by storing natural gas in a deep, naturally fractured reservoir in Italy's Po Valley. This would potentially represent the country's largest storage project, and could play a key strategic and commercial role in solving Italy's gas deliverability constraints, security of supply, and market development. In addition, we have analysed recent transaction values for similar projects to provide investors with a long term potential valuation.

Ribolla shale gas play The Ribolla Basin Shale Gas project was originally proposed as a more limited coal bed methane (CBM) project within the company’s Fiume Bruna license located in Tuscany. This licence forms the basis of the company’s target valuation with gross prospective estimates of recoverable gas in the region of 160bcf, representing c.62p/share. In our view, a successful farm-out of a proportion of the company’s 100% interest here, to include a funding element for further development, will represent a near-term share price trigger for investors.

Uncertainty in Tunisia In 2010, Independent and its JV partner drilled two wells and plugged and abandoned both in what was seen as a disappointing drilling campaign. At this point, we do not attribute any value for the block in our target price.

Valuation and recommendation We feel that Independent's long term value may lie in its Italian gas storage potential, and our range of potential valuations of the facility illustrates the expected premium available to investors - if the company can successfully develop this side of the business. Nevertheless, our core valuation yields a base value of 67p, and on this basis we initiate coverage with a BUY recommendation.

3,5 Please see regulatory disclosure notes at the end of this document F Forecast change A draft of this research has been shown to the company following which minor factual amendments have been made.

10 February 12 | Initiation of coverage | Oil & Gas Producers

Independent Resources(AIM:IRG)3,5

BUY Share price 49p



Net cash (£m) 2.5





(%) 1m 3m 12m

Absolute +24.1 +22.5 +4.3

FTA relative +19.0 +14.6 +6.0


0

20

40

60

80

100


Price Relative

Source: Datastream


Next news Updates - Ribolla shale gas play

Business Integrated natural gas

www.ir-plc.com



Year end December

Revenue(£m)

EBIT*(£m)

PBT*(£m)

Tax(%)

Adj. EPS* (p)

PER (x)

EV/EBIT*(x)

Div yield(%)

2010A 0.0 (2.6) (2.2) 2.0 (0.1) n/a (7.8) 0.02011A 0.0 (1.2) (1.2) 0.0 (0.0) n/a (17.0) 0.02012E 0.0 (1.0) (0.9) 0.0 (0.0) n/a (21.0) 0.02013E 0.0 (1.1) (1.1) 0.0 (0.0) n/a (18.1) 0.02014E 0.0 (1.1) (1.1) 0.0 (0.0) n/a (18.1) 0.0





Independent Resources | 10 February 12 Valuation and recommendation


We value Independent Resources on a risked expectation net asset value basis covering the company's Ribolla Basin shale gas play. We feel the company's acreage in Italy and Tunisia is too early stage to attribute any near- erm value to investors; however we provide a range of potential valuations for the Rivara gas storage project that is currently gathering pace. We incorporate the following assumptions in our valuation:


Metric Assumption

Long-term $/£ exchange rate 1.65 NPV/boe - Gas 3.5 Discount 10% Chance of exploration 50% Shares outstanding (m) 45.84


These assumptions have been assimilated into our risked net asset value appraisal as follows:


Prospect Name Interest Bcf Mmboe COS NPV 10% US$ / boe

Unrisked NPV $m

Risked NPV $m

Unrisked NPV £m

Risked NPV £m

Net Risked p/share

Ribolla Basin Shale Gas Play 100% 160 26.67 50% 3.50 93.33 46.67 56.57 28.28 61.70


Our core valuation will only comprise Independent's risked assessment of 2C resources arising from its shale gas play, as well as the company’s net cash position as at last year end (30/9/11).

Valuation matrix

£ million p/share

Ribolla Basin Shale Gas Play 28.3 61.7 Net cash 2.5 5.5 Target market cap/price 30.8 67.2



61.7

5.5

0

10

20

30

40

50

60

70

80

Net Cash Ribolla Basin Shale Gas Play

p/sh

are



Valuation and recommendation Independent Resources | 10 February 12

Potential gas storage valuations

There have been multiple transactions involving gas storage acquisitions is the last few years, which we have collated to attribute a regional value to Independent's future underground storage (UGS) facility by storing natural gas in Italy's Po Valley. We feel it is necessary to illustrate other regions outside of Europe, due to the number of transactions for various facilities as well as the growing interest from larger players in the market.

Gas storage transactions by region

Buyer Seller Country Year Asset Capacity (bcf)

Transaction amount Value per Bcf

Snam Rete Eni Italy 2009 Multiple 494 2051 4.15 MOL MSZKSZ Hungary 2009-2010 Szoreg 60 844 14.07 Plinacro PSP Croatia 2009 Okoli 19 110 5.79 Petronas Northern Netherlands 2009 Waalwijk 15 110 7.33 Haddington Ventures Continental BV Holland 2011 Subsidiary 25 410 16.40 Plinacro Croatian Government Croatia 2009 Okoli 5 95 19.00 European average 11.12 Inergy Tres Palacios US 2010 Tres Palacios 38.4 725 18.88 Buckeye ArcLight Capital US 2007 Lodi 22 440 20.00 US Average 19.44 Centrica Perenco UK 2009 Baird 42 250 5.95 Centrica Warwick Energy UK 2008 Caythorpe 7.5 115 15.33 UK Average 10.64 Spectra Energy Corp Haddington Energy Canada 2010 Bobcat 46 540 11.74 Carlyle/Riverstone Global Energy EnCana Canada 2006 Multiple 174 1500 8.62 Canadian average 10.18


The above transaction values per bcf are clearly wide ranging, however they do provide an indication as to the potential value of Independent’s planned UGS facility. On an overall average basis, the inferred market value of the facility could be in the region of £81m or 178p/share on the basis that the facility will have a capacity of 10.5bcf.

Application of average transaction values to Independent

bcf $m £m p/shr

Europe 10.5 116.8 70.8 154.4 US 10.5 204.1 123.7 269.9 UK 10.5 111.7 67.7 147.7 Canada 10.5 106.9 64.8 141.3 Overall average 10.5 134.9 81.7 178.3


The above also illustrates that on the European inferred multiple, the potential value to investors could be c.154p/share.


Independent Resources | 10 February 12 Valuation and recommendation

Potential values applied to Independent

0

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200

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300

Canada UK Europe US

Pote

ntia

l p/s

hare



Our core valuation comprises exploration and development, activities, and cash; which yields a base value of 67p. We feel that Independent's long term value clearly lies in its Italian gas storage potential. Our range of potential valuations of the facility illustrates the expected premium available to investors if the company can successfully develop this side of the business. On this basis, we initiate coverage with a BUY recommendation and set a target price of 67p.


Operational overview Independent Resources | 10 February 12

Operational overview

Rivara underground gas storage facility

Independent plans to construct a large underground storage (UGS) facility by storing natural gas in a deep, naturally fractured reservoir in Italy's Po Valley. The Rivara project has been granted a provisional long-term concession by Italy's Ministry of Economic Development (MSE) which is subject to completion of a satisfactory environmental impact assessment and final approval by MSE of the results of the appraisal work programme prior to development. MSE and Italy's gas markets regulator (AEEG) are eager to encourage new gas storage capacity in the country to alleviate the well-documented deficit in this sector of the gas supply chain which is a matter of public interest. The company has dedicated an impressive effort to navigate the onerous Italian approval process and expects to complete this process in the near term.

Underground natural gas storage is a common feature of almost all gas delivery systems and has been used for many decades. It is a well-understood process that is environmentally benign and involves a low-impact physical profile.

Rivara's working capacity is estimated at approximately 105bcf, which would make it one of the largest gas storage facilities in Italy and in Europe. The company anticipates that it will be developed in a commercial partnership, using long term project finance.

The company currently expects to develop Rivara in two stages. The first stage starts with an 18-month appraisal and optimisation programme, leading to its bankable Final Investment Decision. A three year construction and commissioning period would follow. The project company, ERG Rivara Storage srl, includes the 15% equity participation of ERG S.p.A., a leading Italian energy business. Independent Resources has traditionally been open to Joint Ventures as a means to both unlock and add value in the short term. It would seem logical for a major integrated gas company to seek a controlling stake in such a strategic site.

The key potential benefits of the Rivara storage facility are:

• the large capacity of the structure

• its unique geological features not only allow for faster injection and withdrawal than conventional gas storage facilities, but for constant peak gas deliverability throughout its annual operational cycle

• its potential to go a long way towards closing Italy's current storage deficit and meeting the growing demand for gas storage capacity in Italy

• its geographical location, in-market and close to a trunkline intersection on the transcontinental "gas highway" and likely future gas trading "hub"

• its strategic value as a primary storage facility bridging the European “Southern Corridor”, the large Italy market itself, and connected markets in South-Central Europe.

Ribolla Basin Shale Gas Play

The Ribolla Basin Shale Gas project was originally proposed as a relatively limited coal bed methane (CBM) project within the company’s Fiume Bruna license located in Tuscany. The Ribolla gas-saturated coal and shale basin is currently interpreted to extend well beyond the Fiume Bruna license and into the company’s Casoni license to the south. In practice these licenses now cover the entire producible basin.


Independent Resources | 10 February 12 Operational overview

The Fiume Bruna exploration permit consists of an area totalling 247km located in southern Tuscany, Central Italy, lying entirely onshore and the Casoni exploration permit consists of an area totalling 187km2 and is located just to the south of the Fiume Bruna block, entirely onshore. The prospective area covered by both licenses is characterised by plains and includes cultivated fields.

Ribolla shale gas play location map


IRG drilled and cored Italy's first CBM stratigraphic borehole in 2006, and measured gas content and gas adsorption characteristics in coal and carbonaceous shale. The gas was found to be thermogenic. During 2008-2009 Independent recorded a total of 66 km of 2D seismic and drilled FB 1 well in August 2009. In addition, a large number of vintage boreholes, available from the past mining activity, have been used to construct a regional depositional model of the Ribolla basin and beyond. This allowed IRG to map a thick gas-bearing carbonaceous shale sequence, consistently located immediately above and below the main coal seam. The FB 2 well was subsequently drilled to test the coal’s productivity in the shallow part of the basin, where the coal and the gas shale were found to be saturated with gas. A hydraulic fracture job coupled with ceramic proppant, designed to enhance productivity, was followed by a seven weeks production test.

The Fiume Bruna project has heretofore been described in terms of a relatively shallow CBM play but recent analysis, a new depositional model, and well results indicate that this organic-rich basin is more extensive and likely more productive at depths averaging 1,000m


Operational overview Independent Resources | 10 February 12

The Casoni and Fiume Bruna blocks cover more than 450km and contain more than 140km of potentially productive area with a coal plus gas shale sequence at an average depth of 1,000m. The measured data indicates in the entire area an interval of coal and gas shale more than 9m thick on average.

Independent has upgraded its previously-announced gross prospective estimates of recoverable gas to 160bcf 2C Contingent Resources, and includes both the Fiume Bruna and Casoni blocks. This represents an improvement of the gross figures, not only due to the addition of the Casoni license area but also the use of a more appropriate average gas content of the rock based on extensive measurements. The upgrade from Prospective Resources, as it was previously reported, to Contingent Resources, arises from successfully flowing natural gas to surface.

Tunisian oil and gas acreage

Independent holds a c.19% interest in the Ksar Hadada exploration permit covering an area of 2,252 km2 onshore south-east Tunisia. Several large oil-prone prospects have been mapped; these are sourced by the Silurian Tanezzuft Shale, which is the main source rock for North Africa and the Middle East.

Tunisian acreage

Source: Company

Light oil discoveries in the Cambro-Ordovician immediately to the south of the block in the adjacent Remada Sud permit have now validated the potential of the Ksar Hadada prospects. Across the border in Libya very high oil production rates have been achieved on test from multiple Acacus wells, providing added attraction to the Acacus play on Ksar Hadada. In addition, significant shale oil prospectivity remains to be mapped and tested.

In 2004, the then permit operator, Petroceltic, drilled a third well into the Sidi Toui structure, but the rig had to be released to another operator before the well could be fully tested. Subsequent analysis of the well results indicates the presence of a live hydrocarbon column.

Mean gross prospective recoverable resource estimates prior to execution of the 2010 Drilling Programme, for Sidi Toui (main target, plus subsidiary blocks) are currently estimated to be 161mmbo. Oil from nearby discovery wells is light at 42° API.

In 2010, the JV drilled two wells and plug and abandoned both in what was seen as a disppointing drilling campaign. The company experienced operational difficulties, however the extensive logging data collected in the wells will be used to analyse the


Independent Resources | 10 February 12 Operational overview

remaining prospect inventory on the Ksar Hadada block. The joint venture will review all the data collected from the ST-4 and Oryx wells before making a decision on whether to extend operations on the block.

The permit’s Operator, PetroAsian Energy (Tunisia) Ltd, has a 78.03% Working Interest. The JV is now focusing on a new reservoir compartment of the Sidi-Toui Cambro-Ordovician prospect, as well as the very significant volume of oil-bearing Silurian Hot Shale, which is pervasive and effectively underlies the entire residual area of the permit at relatively shallow depth.

Source: xx

At the present time, we do not attribute any value for the block to our target price. Nevertheless, despite the dissapointing result in 2010, the company had and retains very limited financial exposure given the terms of the joint venture agreement and we highlight management’s financial prudence on this basis.


Financial model Independent Resources | 10 February 12

Financial model

Income Statement


2010A 2011A 2012E 2013E 2014E

Group revenue 0.0 0.0 0.0 0.0 0.0Cost of sales 0.0 0.0 0.0 0.0 0.0Gross profit 0.0 0.0 0.0 0.0 0.0Total operating expenses (1.2) (1.2) (1.0) (1.1) (1.1)EBIT (1.2) (1.2) (1.0) (1.1) (1.1)Net interest/financial income/(cost) 0.4 0.0 0.1 0.1 0.1Associate and Other non-op. income/(cost) 0.0 0.0 0.0 0.0 0.0PBT (2.2) (1.2) (0.9) (1.1) (1.1)Tax 0.0 0.0 0.0 0.0 0.0Effective tax rate (%) 2.0 0.0 0.0 0.0 0.0Minorities 0.0 0.0 0.0 0.0 0.0Earnings (2.2) (1.2) (0.9) (1.1) (1.1) EBITDA (0.1) (1.1) (0.9) (1.1) (1.1)Adjusted EBITDA* (1.4) (1.1) (0.9) (1.1) (1.1)Adjusted EBIT* (2.6) (1.2) (1.0) (1.1) (1.1)Adjusted PBT* (2.2) (1.2) (0.9) (1.1) (1.1)Adjusted earnings* (2.2) (1.2) (0.9) (1.1) (1.1) DPS (p) 0.0 0.0 0.0 0.0 0.0EPS (p) (0.1) (0.0) (0.0) (0.0) (0.0)EPS [F. Dil.] (p) (0.1) (0.0) (0.0) (0.0) (0.0)EPS [Adj.]* (p) (0.1) (0.0) (0.0) (0.0) (0.0)EPS [Adj. F. Dil.]* (p) (0.1) (0.0) (0.0) (0.0) (0.0)Weighted average no. shares (m) 41.6 45.8 45.8 45.8 45.8Fully dil. w. ave. no. shares (m) 41.6 45.8 45.8 45.8 45.8Year end no. shares (m) 41.6 45.8 45.8 45.8 45.8




Independent Resources | 10 February 12 Financial model

Cashflow Statement


2010A 2011A 2012E 2013E 2014E

Operating income (1.2) (1.2) (1.0) (1.1) (1.1)Amortisation of acquired intangibles 0.0 0.0 0.0 0.0 0.0Amortisation of other intangibles 1.1 0.0 0.0 0.0 0.0Depreciation 0.0 0.0 0.0 0.0 0.0Net change in working capital 0.1 1.1 0.8 (0.2) 0.1Other (0.5) (0.1) (0.2) (0.1) (0.1)Operating cash flow (0.5) (0.1) (0.3) (1.3) (1.0) Capital expenditure (2.5) (1.3) (1.4) (1.4) (4.2)Investment in Other intangibles 0.0 0.0 0.0 0.0 0.0Net interest/financial income/(cost) 0.0 0.0 0.0 0.0 0.0Tax paid (0.1) 0.1 0.1 0.0 0.0Net acqns./disposals (2.4) (1.3) (1.4) (1.4) (4.2)Dividend paid 0.0 0.0 0.0 0.0 0.0Other 0.1 0.0 0.0 0.1 0.1Cash flow before financing (5.3) (2.6) (2.9) (4.0) (9.4) Proceeds from shares issued 2.6 0.0 0.0 0.0 0.0Investments 0.0 0.0 0.0 0.0 0.0Other (0.1) 0.0 0.0 0.0 0.0Net movement in cash/(debt) (2.9) (2.6) (2.9) (4.0) (9.4) Opening net cash/(debt) 5.3 3.9 2.5 0.9 (1.7)Adjustments (Forex, etc.) 0.0 0.0 0.0 0.0 0.0Closing net cash/(debt) 3.9 2.5 0.9 (1.7) (6.8) Source: Company data, Seymour Pierce Ltd

Balance Sheet


2010A 2011A 2012E 2013E 2014E

Property plant and equipment 0.1 0.1 0.1 0.1 0.1Goodwill and Acquired intangibles 0.5 0.5 0.5 0.5 0.5Other intangibles 8.0 9.3 10.9 12.3 16.5Other fixed assets 0.0 0.0 0.0 0.0 0.0Non current assets 8.5 9.8 11.4 12.8 17.0 Stocks & WIP 0.0 0.0 0.0 0.0 0.0Trade receivables 5.5 4.5 3.7 3.0 2.4Cash 3.9 2.5 (0.5) (3.2) (8.3)Other current assets 0.1 0.0 0.0 0.0 0.0Current assets 9.4 7.0 3.1 (0.2) (5.9) Total assets 18.0 16.8 14.6 12.6 11.1 Trade creditors 0.6 0.8 1.1 1.6 2.3Short term borrowings 0.0 0.0 0.0 0.0 0.0Long term borrowings 0.0 0.0 0.0 0.0 0.0Other liabilities 0.3 0.0 0.0 0.0 0.0Total liabilities 0.9 0.8 1.1 1.6 2.3 Net assets 17.1 16.1 13.5 11.0 8.9 Issued share capital 0.5 0.5 0.5 0.5 0.5Share premium account 15.3 15.3 15.3 15.3 15.3Retained earnings (1.2) (2.0) 0.0 0.0 0.0Other reserves 1.2 1.0 1.0 1.0 1.0Minority interests 1.3 1.3 1.3 1.3 1.3Total equity 17.1 16.1 18.1 18.1 18.1



Financial model Independent Resources | 10 February 12

Key Ratios

Year end December

2010A 2011A 2012E 2013E 2014E

Revenue growth (%) n/a n/a n/a n/a n/aAdj. EBITDA* growth (%) n/a (20.6) (19.2) 16.3 (0.2)Adj. EBIT* growth (%) n/a (54.0) (19.1) 15.8 0.0Gross margin (%) n/a n/a n/a n/a n/aAdj. EBITDA* margin (%) n/a n/a n/a n/a n/aAdj. EBIT* margin (%) n/a n/a n/a n/a n/a Gearing (%) n/a n/a n/a 15.7 77.4Interest cover (x) n/a n/a n/a n/a n/aNet debt/Adj. EBITDA* (x) (2.7) (2.2) (1.0) 1.6 6.4Dividend cover (x) n/a n/a n/a n/a n/a ROE (%) (12.7) (7.2) (5.0) (5.8) (5.8)ROIC (%) (88.0) (88.9) (65.5) (74.5) (24.8)ROCE (%) (88.0) (88.9) (65.5) (74.5) (24.8) Operating cash conversion (%) 903.6 10.4 30.6 124.4 92.3Net cash conversion (%) 246.3 223.2 322.5 385.5 890.7Net working cap / revenue (%) n/a n/a n/a n/a n/aCap Ex / revenue (%) n/a n/a n/a n/a n/a



Valuation Metrics

Year end December

2010A 2011A 2012E 2013E 2014E

PER (x) (944.1) (1,929.1) (2,500.0) (2,139.7) (2,139.7)EV / Revenue^ (x) n/a n/a n/a n/a n/aEV / Adj. EBITDA^* (x) (13.8) (17.4) (21.6) (18.6) (18.6)EV / Adj. EBIT^* (x) (7.8) (17.0) (21.0) (18.1) (18.1)EV / IC^ (x) 1.7 1.6 1.3 1.1 0.8EV / Taxed Adj. EBIT^* (x) (7.8) (17.0) (21.0) (18.1) (18.1) Yield (%) 0.0 0.0 0.0 0.0 0.0P / CFPS (x) (3.8) (8.6) (7.7) (5.5) (2.4)NAV per share (p) 37.8 32.2 26.5 21.2 16.5





Independent Resources | 10 February 12 Financial model


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100

150

200

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I

Appendix 1: Glossary of terms

Variable Meaning Units

Admission Process of admission of an entity to a Stock Market API American Petroleum Institute AVO Amplitude versus offset or amplitude variation with offset is often used as a direct hydrocarbon indicator Barremian Part of the Lower Cretaceous about 130m years old Best Estimate Projected volumes. Often associated with a central, P50 or mean value bbl(s) Barrels(s) bbls/d Barrels per day BCF Billion cubic feet of gas boe Barrels of oil equivalent, converting gas to oil at 6 mcf to 1bbl boepd Barrels of equivalent production per day bopd Barrels of oil per day BOP Blowout preventer Bscf Billions of standard cubic feet bwpd Barrels of water per day Caisson A small fixed structure used offshore for the production of oil and gas Condensate Hydrocarbon liquid that condenses out of natural gas if the temperature is reduced to below the dew point

temperature of natural gas.

Contingent Resources Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorised in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterised by their economic status

CoS Exploration or geological or commerical chance of success. The probability, typically expressed as a percentage, that a given outcome will occur

Cretaceous A group of rocks ranging in age from about 70 to 150m years old Darcy, milliDarcies, mD Measures of permeability in reservoir rocks Fan sequences A series of turbidities that have come to rest in a fan shape Jurassic A group of rocks ranging in age from about 150 to 200m years old Lead A project associated with a potential accumulation that is currently poorly defined and requires more data

acquistion and/or evaluation in order to be classified as a Prospect

LNG Liquified Natural Gas Long reach deviated drilling

Drilling of deviated wells further from the production platform than has been normal up to this point

Lower Cretaceous A group of rocks ranging in age from about 100 to 150m years old mcf Thousand cubic feet of gas MD Measured depth ft or m mD MilliDarcies MDRKB Measured Depth Rotary Kelly Bushing ft or m MDBRT Measured Depth Below Rotary Table ft or m Mean The arithmetic average of a set of values MM Million MM bbl Million barrels of oil MM boe Million barrels of oil equivalent MMscf/d Million standard cubic feet per day


CONT’D

MMstb Millions stock tank barrels N/G Net to Gross NPV Net present value NYMEX New York Mercantile Exchange P90 The probability that a stated volume will be equalled or exceeded. In this example a 90 per cent. Chance that the actual

volume will be greater than or equal to that stated Paleozoic An era of geological time ranging in age from about 250 to 550m years old Producing Related to development projects (eg wells and platforms): Active facilities, currently involved in the extraction

(production) of hydrocarbons from discovered reservoirs Prospect A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target Prospective Resources Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable

from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity

Proved or P90 or 1P Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 per cent. probability that the quantities actually recovered will equal or exceed the estimate

Proved plus Probable or P50 or 2P

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50 per cent. probability that the actual quantities recovered will equal or exceed the 2P estimate

Proved plus Probable plus Possible or 3P

Possible Reserves are those additional reserves which analysis of geo-science and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10 per cent. probability that the actual quantities recovered will equal or exceed the 3P estimate

Recoverable Oil or gas Those quantities of oil or gas that are estimated to be produceable from discovered or undiscovered accumulations Reserves Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development

projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorised in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterised by development and production status

Sales Gas Gas volume for sale after liquid stripping in the separator scf Cubic foot of gas at standard pressure and temperature Seismic amplitude response

Changes in the amplitude of events seen on seismic data that may be indicative of the presence of hydrocarbons

stb/d Stock tank barrels per day STOIIP Stock tank oil initially in place Synrift In context of this report, refers to formations that were formed during the rifting and early opening of the Atlantic

Ocean Sw Water saturation ratioTCF Trillion cubic feet of gas TD Total depth ft or mTurbidite A rock that was deposited in deep water by long distance slumping from shallower water Unrisked recoverable oil or gas

Those quantities of oil or gas that are estimated to be produceable from discovered or undiscovered accumulations, without factoring the probability that the given outcome will occur

Valanginian Part of the Lower Cretaceous about 140m years old

Source: CGA and Seymour Pierce Ltd

Seymour Pierce Limited 20 Old Bailey, London EC4M 7EN

Switchboard: +44 (0)20 7107 8000 Corporate Finance fax: + 44 (0)20 7107 8100 Research + Sales fax: +44(0)20 7107 8102


Key to material interests

1 The analyst has a personal holding of the securities issued by the company, or of derivatives related to such securities.

2 Seymour Pierce Limited or an affiliate owns more than 5% of the issued share capital of the company.

3 Seymour Pierce Limited or an affiliate is party to an agreement with the company relating to the provision of investment banking services, or has been party to such an agreement within the past 12 months. Our corporate broking agreements include a provision that we will prepare and publish research at such times as we consider appropriate.

4 Seymour Pierce or an affiliate has been lead manager or co-lead manager of a publicly disclosed offer of securities for the company within the past 12 months.

5 Seymour Pierce is a market maker or liquidity provider in the securities issued by the company. 6 Seymour Pierce is party to an agreement with the company relating to the production of research

recommendations. Distribution of ratings

Our research ratings are defined with reference to the absolute return we expect over the next 12 months:

Rating Definition

Buy Absolute return expected to be more than 10%

Add Absolute return expected to be between 5% and 10%

Hold Absolute return expected to be between -5% and +5%

Reduce Absolute return expected to be between -5% and -10%

Sell Absolute return expected to be less than -10%

As from 25 October 2010 the nomenclature of our recommendation was changed. Prior to that time Add recommendations were described as Outperform and Reduce recommendations were described as Underperform.

As at 31 December 2011 the distribution of all our published recommendations is as follows:

Rating

Proportion of recommendations

Proportion of these provided withinvestment banking services

Buy 57.7% 46.8%

Add 2.5% 50.0%

Hold 19.0% 3.2%

Reduce 4.9% 0.0%

Sell 6.7% 0.0%

None 9.2% 80.0%

Important Notes Our research recommendations are issued and approved for distribution within the United Kingdom bySeymour Pierce Limited only to eligible counterparties and professional clients as defined under the FSA rules.Our research is not directed at, may not be suitable for and should not be relied upon by any other person.The information contained in our research is compiled from a number of sources and is believed to be correct,but cannot be guaranteed. It is not to be construed as an offer, invitation or solicitation to buy or sell anysecurities of any of the companies referred to within it. All statements made and opinions expressed are madeas at the date on the face of the material and are subject to change without notice. Where prices of securitiesare mentioned, these are the mid-market prices as at the close-of-business on the business day immediatelypreceding the date of the research. The meanings of our research ratings, together with the proportion of ourrecommendations issued during the previous quarter carrying each rating, is set out on our website atwww.seymourpierce.com. Seymour Pierce Limited and/or its associated companies and ultimate holdingcompany may from time-to-time provide investment or other services to, or solicit such business from, any ofthe companies referred to in research material. In addition, they and/or their directors and employees and/orany connected persons may have an interest in the securities of any of the companies in the report and mayfrom time-to-time add to or dispose of such interests. Details of the significant conflicts relating to thecompanies that we research are set out on our website www.seymourpierce.com, together with a summary ofour policies for managing conflicts of interest.

Seymour Pierce does not meet all of the FSA standards for managing conflicts of interest, as a result ourresearch should not be regarded as an impartial or objective assessment of the value or prospects of itssubject matter, though of course we will always ensure that it remains clear, fair and not misleading.

Seymour Pierce Limited is authorised and regulated by the Financial Services Authority, and is a member of theLondon Stock Exchange.

FTSE®”, "FT-SE®", "Footsie®", “FTSE4Good®” and “techMARK are trade marks jointly owned by the London Stock Exchange Plcand The Financial Times Limited and are used by FTSE International Limited (“FTSE”) under licence. “All-World®”, “All-Share®” and“All-Small®” are trade marks of FTSE.

"The FTSE INDICES] are calculated by FTSE. FTSE does not sponsor, endorse or promote [this presentation] and is not in any wayconnected to it and does not accept any liability in relation to its issue.

All copyright and database rights in the index values and constituent list vest in FTSE. Seymour Pierce Limited has obtained full licence from FTSE to use such copyright and database rights in the creation of this presentation.

February 2012

Oil & Gas AIM Initiations



Sam Wahab Research Analyst +44 (0) 20 7107 8094 [email protected]

ACA

Seymo

ur Pierce

Oil & G

as AIM

Initiations | February 2012

Seymour Pierce Limited20 Old Bailey, London EC4M 7EN

Switchboard +44 (0)20 7107 8000Corporate finance fax +44 (0)20 7107 8100Research and Sales fax +44 (0)20 7107 8102


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