Company Note - Proactiveinvestors NA...Djeno Unchained AAOG offers investors exposure to near-term,...

8 June 2018

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Company Note

Anglo African Oil & Gas*Djeno UnchainedAAOG offers investors exposure to near-term, low-cost drilling in the Republic of the Congo with a mix of risk/reward from a single well. The TLP-103 well will be drilled this summer and targets three different reservoir sands on its Tilapia field (AAOG 56%): the producing R1/R2 reservoir, the discovered Mengo sands and a deeper Djeno sands exploration prospect, which have delivered impressive flow rates from neighbouring fields. The shares have decent valuation support from the existing producing horizon, while upside potential in the success case for the Mengo and Djeno reservoirs could be major. We initiate with a risked NAV-based price target of 41p/sh.

New CEO, new sense of urgency. AAOG’s new CEO only joined in January, yet already there has been a marked improvement in operational performance and a new sense of urgency. Workovers on two existing Tilapia wells – TLP-101 and TLP-102 – are now bearing fruit and management are targeting 100-180 bopd from these once a downhole pump is installed on TLP-102, which helps underpin the shares.

Let’s get ready… The main event, however, remains the drilling of the multi-horizon TLP-103 well. After some delay, the company now has everything in place to drill this summer. Importantly the well can be drilled from onshore, dramatically reducing cost. Moreover, the recent $10m placing means AAOG can fund 100% of the well cost if state-owned SNPC does not pay its share. Any additional partner cost incurred can then be clawed back from future production under the PSC contract terms.

3 in 1 oil. This well is targeting three separate reservoir horizons with a range of risk/reward – low risk appraisal of 2mbbls of producing reserves in the R1/R2 sands (6.3p/sh), appraisal of an 8-24mmbbl undeveloped discovery in the Mengo sands potentially worth 18-45p/sh on a risked basis, and a deeper exploration prospect in the Djeno sands, assigned gross prospective oil resources of 16-42mmbbls. This final target carries higher risk (25% CoS) but also higher reward. Our risked valuation range for the Djeno of 16-39p/sh rises to 69-159p/sh when fully de-risked.

Significant dividend potential. Our risked NAV for the ‘Best’ resource case from all three of these horizons is 41p/sh (106p/sh unrisked). In the ‘High’ resource case this rises to 90p/sh (241p/sh unrisked). Moreover, success with either the Mengo or Djeno sands would be expected to result in meaningful earnings and cash generation and open up the prospect of a significant dividend stream; management has committed to distributing between 50-75% of net profits after necessary capex.

Corp

Ticker AAOG:AIMOil & GasShares in issue (m) 162.1Next results FY Jun

Price 9.6pTarget price 41.0pUpside 327%

Market cap £15.6mNet debt/(cash) -£5.0mOther EV adjustments £0.0mEnterprise value £10.5m

What's changed? From To

Adjusted EPS - -4.9

Target price - 41.0

Share price performance

2017 20188.0

10.012.014.016.018.020.022.024.026.0

Anglo African Oil & Gas

% 1M 3M 12MActual -8.6 -30.2 -45.5

Company descriptionAn independent oil and gas companywith a producing asset in the Republicof the Congo

Jonathan WrightDirector of [email protected] 7220 0543

Sales desk 020 7220 0522

Trading desk 020 7220 0533 * denotes corporate client of finnCap

9.600000000000

Key estimates | Year end: Dec 2016A 2017E 2018E 2019E 2020ERevenue £m 0.0 0.2 1.6 8.4 10.8Adj EBITDA £m -0.9 -3.2 -0.6 6.6 9.1Adj EBIT £m -0.9 -3.3 -0.7 6.1 8.5Adj PBT £m -0.9 -3.4 -0.6 6.2 8.6Adj EPS p -2.2 -4.9 -0.4 3.8 5.3DPS p 0.0 0.0 0.0 1.4 2.2

Key valuation metrics 2016A 2017E 2018E 2019E 2020EEV/EBIT (adj) x -11.3 -3.2 -15.4 1.7 1.2P/E (adj) x -4.3 -2.0 -24.3 2.5 1.8Dividend yield % 0.0% 0.0% 0.0% 15.1% 22.9%Free cash yield % -0.3% -62.2% -24.6% 33.8% 50.1%Pre-tax ROCE % 99.4% -41.2% -4.8% 33.9% 36.8%

This report has been prepared solely for the use of Jonathan Wright

http://www.finncap.com/https://researchlibrary.finncap.com/

Anglo African Oil & Gas 8 June 2018Djeno Unchained

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Growth analysis 2017E 2018E 2019E 2020E

Year end: DecSales growth % n/m 606.7% 432.1% 28.5%

EBITDA growth % -248.7% 81.8% n/m 36.9%

EBIT growth % -256.8% 79.5% 998.5% 39.1%

PBT growth % -260.5% 81.0% n/m 39.2%

EPS growth % -120.4% 91.9% n/m 39.2%

DPS growth % n/m n/m n/m 51.9%

Income statement 2017E 2018E 2019E 2020E

Year end: Dec

Sales £m 0.2 1.6 8.4 10.8

Gross profit £m -0.1 0.6 7.8 10.3

EBITDA (adjusted) £m -3.2 -0.6 6.6 9.1

EBIT (adjusted) £m -3.3 -0.7 6.1 8.5

Associates/other £m 0.0 0.0 0.0 0.0

Net interest £m -0.1 0.0 0.1 0.1

PBT (adjusted) £m -3.4 -0.6 6.2 8.6

Total adjustments £m 0.0 0.0 0.0 0.0

PBT (stated) £m -3.4 -0.6 6.2 8.6

Tax charge £m -0.0 0.0 0.0 0.0

Minorities £m 0.0 0.0 0.0 0.0

Reported earnings £m -3.4 -0.6 6.2 8.6

Adjusted earnings £m -3.4 -0.6 6.2 8.6

Shares in issue (year end) m

EPS (stated) p -6.5 -0.5 3.8 5.3

EPS (adjusted, fully diluted) p -4.9 -0.4 3.8 5.3

DPS p 0.0 0.0 1.4 2.2

Profitability analysis 2017E 2018E 2019E 2020E

Year end: DecGross margin % -50.1% 38.6% 93.4% 95.4%

EBITDA margin % n/m -37.4% 79.1% 84.3%

EBIT margin % n/m -43.3% 73.1% 79.1%

PBT margin % n/m -40.7% 73.9% 80.0%

Net margin % n/m -40.7% 73.9% 80.0%

Cash flow analysis 2017E 2018E 2019E 2020E

Year end: DecCash conv'n (op cash / EBITDA) % n/m n/m 101.1% 101.2%

Cash conv'n (FCF / EBITDA) % 297.6% 648.3% 79.2% 85.6%

U/lying FCF (capex = depn) £m -1.9 -0.6 6.3 8.7

Cash quality (u/l FCF / adj earn) % 55.2% 93.6% 101.1% 101.2%

Investment rate (capex / depn) x 105.0 36.0 3.0 2.7

Interest cash cover x n/a net cash n/a n/a

Dividend cash cover x n/a n/a 2.2 2.2

Cash flow 2017E 2018E 2019E 2020E

Year end: DecEBITDA £m -3.2 -0.6 6.6 9.1

Net change in working capital £m 1.5 0.0 0.0 0.0

Other operating items £m 0.0 0.0 0.1 0.1

Cash flow from op. activities £m -1.7 -0.5 6.7 9.2Cash interest £m -0.1 0.0 0.1 0.1

Cash tax £m 0.0 0.0 0.0 0.0

Capex £m -7.9 -3.3 -1.5 -1.5

Free cash flow £m -9.7 -3.8 5.3 7.8Acquisitions / disposals £m 0.0 0.0 0.0 0.0

Dividends £m 0.0 0.0 -2.3 -3.6

Shares issued £m 13.5 7.4 0.0 0.0

Other £m -1.1 -0.6 0.0 0.0

Net change in cash flow £m 2.7 3.0 2.9 4.2Opening net cash (debt) £m 0.0 2.7 5.6 8.5

Closing net cash (debt) £m 2.7 5.6 8.5 12.8

Working capital analysis 2017E 2018E 2019E 2020E

Year end: Dec

Net working capital / sales % n/m -153.8% -29.7% -24.1%

Net working capital / sales days n/m -561 -109 -88

Inventory (days) days 0 0 0 0

Receivables (days) days 1,446 205 38 30

Payables (days) days 5,345 766 147 118

Leverage analysis 2017E 2018E 2019E 2020E

Year end: DecNet debt / equity % no debt no debt no debt no debt

Net debt / EBITDA x n/a n/a no debt no debt

Liabilities / capital employed % 0.0% 0.0% 0.0% 0.0%

Balance sheet 2017E 2018E 2019E 2020E

Year End: DecTangible fixed assets £m 2.4 5.7 6.7 7.6

Goodwill & other intangibles £m 5.4 5.4 5.4 5.4

Other non current assets £m 0.0 0.0 0.0 0.0

Net working capital £m -2.4 -2.4 -2.5 -2.6

Other assets £m 0.0 0.0 0.0 0.0

Other liabilities £m 0.0 0.0 0.0 0.0

Gross cash & cash equivs £m 2.7 5.6 8.5 12.8

Capital employed £m 8.1 14.2 18.1 23.2Gross debt £m 0.0 0.0 0.0 0.0

Net pension liability £m 0.0 0.0 0.0 0.0

Shareholders equity £m 8.1 14.2 18.1 23.2

Minorities £m 0.0 0.0 0.0 0.0

Capital employed £m 8.1 14.2 18.1 23.2

Capital efficiency & intrinsic value 2017E 2018E 2019E 2020E

Year end: DecAdjusted return on equity % -41.9% -4.5% 34.3% 37.3%

RoCE (EBIT basis, pre-tax) % -41.2% -4.8% 33.9% 36.8%

RoCE (u/lying FCF basis) % -23.1% -4.2% 34.7% 37.8%

NAV per share p

NTA per share p



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Investment caseAAOG provides investors with exposure to near-term, low-cost drilling in the Republic of the Congo with a mix of risk/reward from a single well. The TLP-103 well will be drilled this summer and targets three different reservoir sands on the Tilapia field: the producing R1/R2 reservoir, the discovered Mengo sands and the deeper Djeno sands, which have delivered impressive flow rates from neighbouring fields. The share price have decent support from the existing producing horizon, while upside potential in the success case for the Mengo and Djeno reservoirs is significant; we initiate with a risked NAV-based price target of 41p/sh.

Anglo African Oil & Gas (AAOG) listed on AIM in March 2017, raising gross proceeds of £10m to fund the acquisition of Petro Kouilou and a workover/drilling programme on its 56% owned Tilapia field in the Republic of the Congo. However, it is only now, under the new CEO, James Berwick, that real progress is being made, with a marked improvement in operational performance and a new sense of urgency since he joined in January.

The company has recently been awarded a new 20-year licence for the Tilapia field, which is awaiting ratification, and the workovers on two existing wells – TLP-101 and TLP-102 – are finally bearing fruit. However, the main event remains the drilling of the multi-horizon TLP-103 well. After some delay, the company now has all necessary licences, permits and service provision, including a rig, in place to drill the well this summer.

Importantly, this drilling target is located just 1.8km offshore and can be drilled from onshore, dramatically reducing well costs, which are estimated at $8m gross including contingency. However, its partner on the block, state-owned SNPC, has not been paying its share of costs; hence the need for the recent $10m placing to ensure that AAOG can fund 100% of the well cost if necessary.

Of note is the fact that the PSC terms on Tilapia allow AAOG to claw back drilling costs above its pro rata share from future cash flows. Moreover, the new licence, once ratified, is expected to see SNPC’s stake reduced from 44% to 19%. This is a reflection of the Congo’s New Petroleum Code, which requires a local partner on all new licences – in this case AOCG, a private upstream, downstream, transportation and oil services company.

The TLP-103 well is targeting three separate reservoir horizons with a range of risk/reward:

Appraisal of 2mmbbls gross proven reserves in the R1/R2 sands. This is the lowest risk target of the well given these sands are already producing at Tilapia. We estimate an NPV for this horizon of 6.3p/sh, assuming plateau production of 250 bopd from 2021 and net reserves of 1.1mmbbls.

Appraisal of an undeveloped discovery in the Mengo sands assigned a 60% Geological CoS. We have considered both the Best (8.1mmbbls gross) and High (23.8mmbbls gross) contingent resource cases laid out in the CPR, which we estimate will require between five and 13 wells to develop. This gives a risked valuation for the Best - High Mengo cases of 18-45p/sh (unrisked 30-75p/sh), with peak production in 2022 of 2,000 - 6,000 bpd respectively.

The final target is a deeper exploration prospect in the Djeno sands, assigned gross prospective oil resources of 15.9-42.3mmbbls in the Best and High cases respectively. This is higher risk (25% CoS) but also much higher reward; discovery wells on adjacent blocks have flowed at 5,000 bpd from the Djeno sands. To be conservative, we assume individual well flow rates of 2,500bpd with four to 10 development wells required in the Best - High resource cases respectively, giving a risked valuation range of 16-39p/sh (69-159p/sh unrisked) for the Djeno sands.

Of note is the fact that the CPR from October 2016, where the above resource estimates have been sourced, only included data to the end of the licence period; July 2020 – so,

New sense of urgency

All set to drill this summer

All set to drill this summer



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effectively these resource estimates correspond to less than four years of production. The new licence, which is awaiting ratification, resets the licence period to 20 years, which means these resource estimates are very conservative.

The PK acquisition therefore provided AAOG with a low-cost entry into a proven producing asset. High-quality land-based production and infrastructure facilities are already in place and have significant spare capacity. Success with the TLP-103 well, therefore, can quickly be turned into production and cash flow at minimal cost. Capex requirements are mainly limited to drilling costs, which should be able to be funded from future cash flow.

Our risked NAV for AAOG of the Best case resource from these three horizons is 41p/sh (106p/sh unrisked). In the High resource case this rises to 90p/sh (241p/sh unrisked). The 6.8p/sh core NAV, which only includes the R1/R2 producing reservoirs, provides a solid underpinning to the shares, which at the current 9.6p/sh have little value ascribed to either the Mengo or Djeno horizons that will be drilled with TLP-103.

For financial modelling purposes, we have considered two scenarios; a base case assuming the development of just the R1/R2 and Mengo horizons, and a success case which also incorporates the development of the Djeno sands. These point to a potential production range of 2,000-8,000 bpd for these cases respectively. With the majority of surface facilities already in place at Tilapia and low development/operating costs, this potential growth should be able to be funded from internal cash flows.

Success then with either the Mengo or Djeno sands would be expected to result in meaningful earnings and cash generation, and open up the prospect of a significant dividend stream; management has committed to distributing between 50-75% of net profits after necessary capex.

While Tilapia remains the main focus of management, over and above this it is pursuing other opportunities and has signed the exclusive right to negotiate to acquire two producing fields in a new jurisdiction. It is now completing the due diligence process on these assets.

Rapid cash flow potential

Figure 1: AAOG net asset valueNet Asset Valuation Net WI reserves EV/bbl Unrisked value Geological Dry hole Risked NPV

mmboe $/boe $mm CoS cost $mm p/shNet cash / (debt) 2.7 1.2Placing (net) 9.2 4.0G&A costs -10.6 -4.7Tilapia - R1/R2 1.1 12.0 13.2 100% 0.0 6.3

1P: Core value 14.4 6.8Discovered/Undeveloped reserves:

Tilapia - Mengo (Best) 4.8 14.2 67.6 60% 0.5 17.9

2P: Core + discovered value 82.0 24.7Visible Exploration:

Tilapia - Djeno (Best) 9.1 17.2 156.1 25% 2.0 16.4

3P: Core + discovered + visible exploration value 238.1 41.1

Source: finnCap

Growth should be internally funded

Dividend commitment



5

Republic of the Congo – a snapshotThe Republic of the Congo (or Congo-Brazzaville) is a former French colony that gained independence in August 1960.

President Denis Sassou Nguesso, a French-trained paratrooper colonel, is one of Africa's longest-serving leaders. He first came to power in 1979 after being installed as President by the military. He lost his position in the country's first multi-party elections in 1992 but returned to power in 1997 after a brief civil war in which he was backed by Angolan troops. He gained his latest five-year term after elections in March 2016. His ruling party, the Parti Congolais du Travail (PCT), won an absolute majority at the legislative election last July, winning 90 of the 151 seats at the National Assembly.

During his first presidency in 1979-92, he loosened the country's links with the Soviet bloc and gave roles in oil exploration and production to French, US and other Western companies.

The Congo has at times had a troubled history with the oil industry, with the economy and population suffering for many years from the mismanagement of oil funds. In the early 1980s, the Congo received over a billion dollars a year in oil revenue, but these were used to fund a huge expansion in food imports and the civil service. The nation’s budget deficit soared, resulting in expensive oil-backed loans from multinationals, which trapped the Congo in a cycle of poverty. This culminated in the early/mid-90s with the Elf Aquitaine scandal, for which the CEO, Le-Floch Prigent, was imprisoned for five years for bribery.

Today, oil is the mainstay of the economy, contributing ~65% of GDP and accounting for over 90% of exports. The country became a net external creditor in 2011, with external debt representing only about 16% of GDP and debt servicing absorbing less than 3% of government revenue. In recent years, the country has endeavoured to improve financial transparency in the sector.

It has also implemented highly successful policies to encourage investment, including the new Hydrocarbons Code in October 2016, which improved the flexibility and attractiveness of contract terms and granted exclusive mining rights to the state-owned oil company, Societe Nationale des Petroles du Congo (SNPC).

In 2016, domestic production in the Congo was 238,000 bpd, 24% down from its peak of 314,000 bpd in 2010. The country is estimated to have 1.6bn bbls of proven oil reserves and 3.2 tcf of gas. Most of the associated gas produced is re-injected due to the lack of infrastructure, with 16% flared in 2015, down from 60% in 2008. The Congo is committed to reducing greenhouse gas emissions and signed up to the Zero-Flaring Initiative in 2012 with the World Bank, which committed it to eliminating gas flaring by 2030. The majority of oil production is exported, again mainly due to the small local market but to also support the country’s wider economy.

Production renaissance occurringNew projects are expected to boost production this year to ~350,000 bpd, which would make it the third largest sub-Saharan producer in Africa after Nigeria and Angola. Eni’s Nene Marine oil field in shallow water is one of the drivers of this renaissance, which started up last year and has the potential to reach 140,000 boepd in the coming years. TOTAL’s Moho Nord field, with a capacity of 100,000 bpd, started up last March and Wing Wah Petrochemical’s Banga Kayo field should add another 50,000 bpd of capacity this year.

Sector driven by majorsUnsurprisingly, and given that the Congo was a French colony, TOTAL is one of the key participants in the oil and gas sector. Since 1968, TOTAL has drilled 50% of the country’s exploration wells, which have discovered 65% of the reserves and brought 16 fields onstream. In 2017, it had average production in the Congo of 104 kboepd from nine operated and three non-operated fields. The company is active throughout the supply

Figure 2: Republic of CongoPopulation 5 millionCapital BrazzavilleArea 342,000 sq.kmMajor languages

French, indigenous African languages

Major religions

Christianity, indigenous African beliefs

Currency CFA (Communaute Financiere Africaine) franc

Source: finnCap



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chain, including a 63% interest in the only oil-export terminal, Djeno, and is its second largest petroleum products retailer. In 2017, it paid $578m to the government in taxes and licence fees.

Eni is another key player, again active in the country since 1968, and produced 98,000 boepd in 2016 from onshore and offshore (shallow and deep water) areas. Its gas production feeds the CEC power plant and Eni has signed up to a framework agreement aimed at integrated development and monetisation of gas production.

The country also benefits from a well-established, highly experienced and qualified local service and support industry.

Petro Kouilou acquisitionAAOG acquired Petro Kouilou (PK), an oil and gas operator that has been active in the

Congo since 2012, in March 2017. The purchase price comprised $2.5m in cash plus 20% of the fully diluted enlarged capital. This was funded from the initial March 2017 AIM listing proceeds.

PK’s core asset is 56% of the Tilapia licence, with SNPC owning the remainder. All of the necessary licences and permits are in place for the current production and for the appraisal and exploration activity.

The Tilapia field already has surface infrastructure installed with an underutilised capacity of more than 4,000 bpd.

Post-acquisition, the company has undertaken workover activities on existing wells (TLP-101 and 102) in order to increase base-level production. It will now go on to drill one new multi-horizon well (TLP-103), targeting known and identified reservoirs.

SNPC has already agreed upon the budget for the proposed work programme and granted the authorisation for expenditure (AFE) with PK for its share of capex.

Initial disappointing results from the well workover programme, alongside delays to signing up a drilling rig for TLP-103 and SNPC not paying its share of costs, meant that AAOG recently placed additional shares, raising a further $10m (gross) at 8p/sh, to ensure it can fund 100% of the TLP-103 well cost if necessary.

Figure 3: TLP-103 drilling budgetUse Value ($ ‘000)Cost of rig 2,250Services 2,050Staff 720Materials 640Support services 600Drilling tools 350Logistics 240Civil Works 50Environmental study 40Total 6,940

Source: AAOG



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Tilapia Asset reviewTilapia is located 1.8 km offshore the Congo, in the Lower Congo Basin. The field is drilled and has production and storage facilities located onshore. It is situated a 45-minute drive from Pointe-Noire, the second largest city in the Congo, and 17 km from the nearest refinery. The roads are of sufficient quality that production can be trucked to the refinery throughout the year.

Tilapia field – in productionThe field is a faulted structural trap and has seen six wells and two sidetracks drilled to date; three by Elf between 1993-95 (TLPM-1, 2 and 3), one by Napta in 2000 (TLPL-1) and the remainder by Prestoil / Petro Kouilou since 2005 (TLP-101V/ST, TLP-102, TLP-201bis).

The field has been in production since 2007 and management are aiming for production of 100-180bopd from the R1/R2 horizon via the TLP-101 and 102 existing wells. Since start-up, cumulative production has been 0.38mmbbls, with no water. The associated gas is currently flared and the gas-oil ratio is 2,800scf/bbl.

Production started in 2007 at a rate of 942 bpd before going into decline due to the bottom-hole pressure increasing. The steady decline in production can be interpreted in several ways: secondary gas cap expansion, communication with a neighbouring fault block or aquifer influx.

However, AAOG is of the view that the field could continue to produce at reasonable commercial rates (above 150bopd) for a number of years by applying enhanced oil recovery techniques such as: gas re-injection, horizontal drains and velocity strings.

Figure 4: Tilapia field location map

Source: PK

Figure 5: Tilapia reserves in production & justified for developmentOil & Liquids (MMstb) Gross Net

1P 2P 3P 1P 2P 3PTilapia 0.000 0.199 0.277 0.000 0.095 0.132

Source: Lloyd’s Register



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Figure 6: Tilapia field data

Source: PK

Figure 7: Tilapia reservoir cross-section

Source: Petro Kouilou



9

Infrastructure

The Tilapia field benefits from having extensive surface infrastructure, which is under-utilised and would only require limited capex, such as an additional 5,000 bbl storage tank estimated at $300k, in order to meet AAOG’s forecast production requirements.

Work programme AAOG has conducted a workover programme on the existing TLP-101 and TLP-102 wells and is to drill a new well, TLP-103, this summer in order to test the deeper potential in the licence. The licence has three reservoirs of interest: Tilapia, Mengo and Djeno. SNPC has recently recommended a new 20-year licence be awarded to AAOG, extending the current end date of July 2020. No signing bonus was needed, but AAOG has committed to drill TLP-103. This new licence is awaiting ratification.

This new multi-horizon well will first drill through the existing producing horizon, R1/R2, then into the lower Mengo Sands, where AAOG has well-log data showing the existence of producible hydrocarbons and from which neighbouring onshore producers are achieving very good production rates of hundreds of barrels of oil a day per well.

Finally, TLP-103 will drill deeper still to explore the Djeno Sands. This horizon has not previously been drilled within this licence area, but Tilapia is located immediately adjacent to areas from which other operators, including Eni and SOCO plc, are achieving production per well of thousands of barrels a day.

TLP-101The TLP-101 workover was completed by AAOG’s operational team in March for no capital cost. Wax build-up in the flow lines and topside equipment was removed and a test programme was started to determine optimal flow rate for the well.

In April, it was announced that the stabilised oil flow rate at TLP-101 increased 120% to 80-90bpd from 38bpd following a five-day test programme via just the well annulus. The

Figure 8: Tilapia installed infrastructure

Source: AAOG



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well was temporarily closed to enable a shift back to producing via the coiled tubing and cleaned flow lines once pressure had built up.

Pressure stabilised in late April and the well was brought back on line and immediately surpassed the previous rate of 38 bopd. The flow rate will be allowed to increase gradually until a maximum sustainable level is achieved.

TLP-102Last May, testing of the R2 reservoir in TLP-102 confirmed the presence of hydrocarbons and pressure within the reservoir. However, despite reperforation and acidisation, the well did not flow oil.

Schlumberger then tried again this April and this second intervention remedied the near-wellbore formation damage. The well produced oil and gas to surface with the aid of nitrogen lift, and tests of the oil and gas samples taken have confirmed the well is in contact with the reservoir. The pressure in the well has increased steadily, exceeding expectations, and the well will be tested to see whether oil flows unassisted. AAOG still expects that, to achieve optimum flow rates, the well will require the installation of a downhole pump, which it has on site and can be installed via a crane.

As stated in the CPR, in the P50 scenario, these workovers could increase production to 185 – 250 bpd.

TLP-103This well remains the main investment case for AAOG. Schlumberger has been contracted to provide support services to drill the well and a rig contract was signed in March with Société de Maintenance Pétrolière (SMP), a private French drilling company with a depot in Gabon, for the supply of Rig-102 to drill TLP-103. SMP has extensive experience in West Africa with 19 land rigs operating in the field.

The rig is currently in Gabon and will be inspected by an independent third-party but should be in good condition, given it was last used by TOTAL. The rig is expected to leave Gabon for the Congo via barge and will be transported via trucks once in the Congo to the drill site.

The well will be drilled from onshore, targeting the offshore prospects 1.8km away. By taking this approach, all of the offshore operational risk is removed, dramatically reducing costs. The well will also be a deviated well in order to avoid faulting, which has added some cost. Drilling operations are expected to commence in July and take 64 days.

This well is targeting three horizons;

Appraisal of 2mmbbls of gross proven reserves in the R1/R2 producing reservoirs.

Appraisal of an 8.1mmbbl gross contingent resource discovery in the lower Mengo sands.

A deeper exploration prospect in the Djeno interval assigned 58.4mmboe of gross prospective resources.

Figure 9: R1 and R2 STOIIP (mmbbls)Compartment Reservoir P90 P50 P10TLP-101ST R2 0.85 2.12 5.01TLP - 102 R1 1.31 2.97 6.53TLP - 102 R2 5.31 8.00 11.40Total 7.47 13.09 22.94




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Gross well costs are estimated at ~$8m (including $1m contingency). AAOG has already spent $1.2m on long-lead items, which includes SNPC’s 44% share of these costs. Uncertainty over SNPC’s ability to fund its share of the well costs drove the recent $10m placing. With this complete, AAOG now has the necessary funds to pay 100% of the well costs if needed. Moreover, the terms of the licence over the Tilapia field allow for AAOG to claw back any drilling costs incurred above its pro-rata share from future cash flows.

TLP-101 and 102 alone have the potential to produce between 185bpd and 250bpd. Success at TLP-103 could materially increase this, with the R1/R2 sands and the Mengo discovery potentially raising production to 750bpd. A discovery in the Djeno sands would be transformational; Eni’s adjacent Minsala Marine well has produced 5,000bpd from this interval.

Given the various potential outcomes of the well, AAOG has a number of options available to them. Should the R1/R2 and Mengo prove commercial and the Djeno not, then the well is expected to be completed as a producer comingling both zones. If both the Djeno and Mengo prove to be commercial, the well would be completed as a Djeno producer. The completion required to produce both the Mengo and Djeno from the same well is too complicated, so a follow-up well, funded from cash flow, would be needed, targeting the Mengo reservoir. The SMP rig is expected to stay on site for a year, so a second well would be materially cheaper – $3-4m – as no mob/demob cost would be involved.

Mengo reservoir – undeveloped discovery

This reservoir was discovered by the TLP-101V in 2006 and encountered a 38m gross column (10-15m net pay) with oil shows and movable hydrocarbons in the Lower Cretaceous Mengo sands. The flow rate was very low at 11 bpd on an open-hole basis with no stimulation. Commercial flow rates will therefore require fraccing (one off) or horizontal wells as the reservoir sands are thin and porosity is relatively low at 10%. We note that, at the point of the original drilling, the technology for a suitable single frac did not exist. Alternately, new Fishbones stimulation technology (described later) is being considered for this interval.

In order to further test the potential of this interval, the TLP-103 well will be drilled through the Mengo layer before going on to test the deeper Djeno prospect. The CPR estimates gross resource of 1.9-23.8mmbbls (Best estimate 8.1mmbbls), and ascribes a 60% CoS.

Figure 10: TLP-103 well costItem US$ ('000)Cost of rig 2,250Services 2,050Staff 720Materials 640Support Services 600Driling tools 350Logistics 240Civil works 50Environmental study 40Sub-total 6,940Already paid (1,200)Net balance 5,740Contingency 1,000Total drilling budget 6,740

Source: AAOG

Figure 11: Tilapia contingent resources (MMstb)Gross Net*Low Best High Low Best High Risk

Mengo 1.9 8.1 23.8 0.9 3.9 11.3 60%Source: Lloyd’s Register.*AAOG WI = 56% net of 15% royalty



12

2D seismic shows the presence of a single four-way dip closure trap located below the Tilapia Pointe Indienne R1/R2 reservoirs. The CPR highlights that higher resolution seismic may show that the Mengo reservoir is faulted and compartmentalised. However, this assumption would need to be confirmed either by acquiring new seismic or by drilling.

The data collected during drilling suggests poor reservoir quality in the 38m column with an average permeability of 0.5md and a porosity range of 8 to 12%. Again, the data show a net to gross ratio of 55-60% with an average porosity of 10% with no confirmation of the oil water contact depth.

Field analogues

There are three onshore analogous fields located 30–40km to the southeast of Tilapia called Mengo, Kundji and Bindi (MKB). The MKB fields have seen at least 17 wells drilled to date and the fields were operated by Elf from 1980 to 1992, during which time cumulative production reached 1.5mmbbl – less than 1% of the oil in place estimate.

Figure 12: 2D seismic over four-way dip closure on R1 & R2 reservoirs




13

The reservoirs at MKB appear to be thicker than those encountered by the TLP-101V well and the seismic shows variations in thickness, reflective of the syn-rift depositional nature of the sandstones. The MKB seismic shows that the fields are large faulted four-way dip closures, which are consistent with what has been observed at Tilapia.

Redevelopment work on the Kundji field was started in 2009 by SNPC, with Panoro Energy as technical partner and a 20% shareholder, and two new development wells were drilled and brought onstream in 2011. The KUN-1 well drilled by Elf produced 516kbbls, making it the largest producing well in the licence. As part of the new development programme, KUN-4bis was drilled 80m away in 2009 and was completed using modern techniques.

This well showed that the area had not been drained by the KUN-1 well and confirmed the original pressure exhibited by the well and therefore showed good mobility and recharge qualities in the reservoir. The KUN-4bis well produced at 600 bpd – more than double the rate of the KUN-1 well.

Subsequently, the KUN-4 and KUN-5 development wells were drilled in 2011 and brought onstream at rates of 250 bpd and 350 bpd respectively. By November 2011, the wells had declined and were producing at 180 bpd and 50 bpd respectively.

Following the drilling of four more wells (KUN-201, 202, 203 and 204), Gaffney Cline more than doubled the oil in place estimates for the Kundi field. The P50 estimate increased from 223mmbbl to 480mmbbl.

SNPC is currently looking at development options to restart MKB production at a rate of 5,000 bpd. Surface infrastructure has already been installed at a cost of $42m with drilling operations ongoing.

Figure 13: MKB fields

Source: Panoro Energy



14

What are Fishbones?

Fishbones is both the name of the company (www.fishbones.as) and an innovative new method of drilling developed in Norway in partnership with Statoil, Eni and Lundin. In short, Fishbones technology provides a lower cost and frequently more effective way to stimulate reservoirs than conventional hydraulic fracturing technology.

Initially, a horizontal well is drilled and the Fishbone liners are placed. Inside the liner are small diameter needles with drill bits at one end and turbines at the other. The turbines are powered by the pressurised drill fluid which results in the miniature drill heads spinning and the needle being forced out of the liner and into the reservoir. As the schematic above shows, the needles then penetrate both horizontally and vertically up to 10.8m through rock and reservoir in a few hours.

This is new technology but has started to be adopted in the field globally, by IOCs, E&Ps and State oil companies. AAOG believes this technology will deliver cost benefits and superior productive potential versus hydraulic fracturing.

Djeno reservoir – the main event

This Lower Cretaceous reservoir exploration prospect is expected below the Mengo discovery made by the TLP-101V well. The Djeno will be tested as part of the appraisal drilling of the Mengo well. The CPR has assigned the following hydrocarbons in place and prospective resources:

Figure 14: Fishbones technology

Source: Fishbones.as

Figure 15: Djeno Hydrocarbons Initially In Place (HIIP)Compartment Reservoir Low Best High

Djeno oil rim (MMstb) Djeno 20.3 53.2 140.0Djeno gas column (bcf) Djeno 142.0 356.0 893.0



http://www.fishbones.as/


15

The prospect based on the 2D seismic is thought to be a four-way dip closed structural trap. The first Djeno discoveries made in the 1970s were gas and condensate fields. However, more recent drilling and production success has shown the presence of oil rims, as has been found at multiple wells in the Nene and Litchendjili field areas adjacent to the Tilapia licence.

The CPR predicts that the Djeno sands in the Tilapia structure will be gas-bearing with an oil rim. The majority of wells drilled near the licence have yielded wet gas with a producible oil rim, as evidenced in the Nene-Lidongo trend. The key difficulty with an oil rim development is management of production from the gas cap, which will be difficult to do even with horizontal wells.

If the Djeno sandstones hold significant quantities of gas above the oil rim the company will pursue commercialisation options as part of the wider field-development plan. The most likely routes being either local/regional markets for gas or local gas to power development (which is favoured by the Government and SNPC).

Djeno chance of success

The chance of success for the well is estimated to be 25% by Lloyd’s Register in the CPR. The key uncertainty is associated with the oil rim.

Adjacent exploration and production successOne of the key reasons AAOG is excited about the prospectivity within the Tilapia licence is the exploration and production success in the surrounding acreage in the Djeno sands by multiple companies.

Figure 16: Djeno Prospective resourcesGross Net*Low Best High Low Best High Risk

Liquids (MMstb) 6.0 15.9 42.3 2.9 7.6 20.1 25%Gas (bcf) 97.8 247.0 625.0 46.6 117.6 297.5 25%Total (mmboe) 22.9 58.4 150.1 10.9 27.9 71.4 25%% Liquids 26.2% 27.2% 28.2% 26.5% 27.3% 28.2%

Source: Lloyd’s Register*AAOG WI = 56% net of 15% royaltyGas converted at 5,800 scf/bbl

Figure 17: Djeno chance of successRisk factor Probability

Trap geometry 70%Reservoir 80%Seal 90%Charge 50%Chance of success 25%




16

Surrounding acreage

Source: Eni

Eni

Eni production averaged 83 kboepd in the Republic of Congo in 2017 from more than a dozen fields. The following are in close proximity to Tilapia:

The Loango oil field, 35km offshore in 90m water depth, was discovered in 1971 and started producing in 1985. The field consists of seven platforms; a production platform (PP) dedicated to the treatment of the produced oil and gas, and six well head platforms (DP1-6).

The Zatchi oil field, located in the Madingo block, was discovered in 1980 and started up in 1988. Five fixed production platforms have been installed at the field.

The Litchendjili gas field is estimated to have 1bn boe of resource in place. The field came onstream in June 2015 and is expected to ultimately produce at a rate of 140,000 boepd with the gas being fed into the CEC power station.

The Nené Marine field started up in January 2015, just 16 months after being discovered. It is estimated to have 1.5bn boe in place and is located 25km away from AAOG's acreage in shallow water and is expected to have plateau production of over 140,000 boepd. Development will happen in several stages with production coming from the same pre-salt Djeno reservoir that AAOG is targeting with its TLP-103 well.

The Minsala Marine field was discovered in October 2014 and tested at a rate of 5,000 bpd from the Djeno sands and is estimated to have 1bn boe of reserves.

TOTAL

TOTAL has been present in the Congo since 1968 and operates several offshore fields including Kombi-Likalala-Libondo (65%), Moho-Bilondo (53.5%), Nkossa and Nsoko (53.5%), Sendji and Yanga (55.25%). It also has interests in the Loanga (42.5%) and Zatchi (29.75%) fields, operated by Eni.

Haute Mer B is a deep-water licence operated by TOTAL, which is estimated to have 195mmbbls of gross unrisked prospective resources in Cretaceous carbonate and Tertiary reservoirs. Oryx Petroleum recently announced the sale of its 30% stake to TOTAL for $8m, with the deal expected to close in Q2 2018. This will raise TOTAL’s interest in the licence to 64.6%.



17

CNOOC

Haute Mer A is a deep-water licence, operated by CNOOC (45%), with 34mmbbl of gross best unrisked prospective resources across three prospects and three leads in multiple horizons. Oryx Petroleum’s 20% interest in this block is up for sale. The Elephant-1 discovery was drilled on this block in 2013, encountering oil and gas, although this was in Miocene Tertiary intervals.

SOCO International

The Lidongo discovery was made in 2014 and flowed at 5,174bpd liquids and 3.65mmcfd gas (post-fraccing) from the Djeno sands in the Marine XI licence, 20km away from Tilapia. A 20-year production licence was granted in October 2016 with the company examining potential commercialisation options.

New Age Oil and Gas

The company has 65% and 50% working interests in the Marine XII and Marine III licences. The former holds the Litchendjili, Nené and Minsala Marine discoveries with Marine III an early stage exploration licence. We note that the Tilapia licence was originally part of the Marine III licence.



18

ValuationWe have separately modelled the three different target horizons for the upcoming TLP-103 well using the PSC terms detailed in Appendix I, a Brent oil price of US$65/bbl in 2018/19 and $70/bbl flat long term, and a 10% discount rate. Given that the production infrastructure is largely already in place, capex is mainly limited to future drilling/workover requirements on the different reservoirs. We also phase the capex so that it can be funded from operating cash flow. The CPR assumes fixed opex of US$62,650 per annum with variable opex of US$4.12/bbl in all of the scenarios.

R1-R2

For the producing R1/R2 reservoirs, we assume plateau production of 250 bpd is reached in 2021 with a well workover performed every other year to maintain output. Net cash generated in this case is ~$2m per annum once plateau production is achieved, generating a NPV of $13.2m or 6.3p/sh.

Mengo valuation

For the Mengo we have considered the Best (8.1mmbbls gross) and High (23.8mmbbls gross) contingent resource cases laid out in the CPR. For each, we have assumed Mengo wells have an IP of 800 bpd, but quickly decline to ~500bpd before stabilising at a more modest (10% p.a.) decline rate. The number of development wells required varies from five in the Best case to 13 in the High case, with 2-3 wells drilled per annum. We have assumed $3.5m for each well resulting in drilling costs of $18.5m and $50m for the Best and High cases respectively.

Figure 18: Mengo gross production profiles (bpd)

0

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Mengo - Best Mengo - High

Source: finnCap

Figure 19: Mengo net cash flow ($m)

-5.0

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Mengo - Best Mengo - High

Source: finnCap

Figures 18 and 19 above demonstrate the gross production profiles and net cash flow associated with each of the Mengo resource cases. In the Best case, production peaks at ~2,000 bpd, generating net cash flow for AAOG of ~$15m at peak. In the High case, production hits 6,000 bpd and net cash flow peaks at $35m.

This gives an unrisked valuation for the Mengo horizon of $68-169m (30-75p/sh), or 18-45p/sh on a risked basis.

Figure 20: Mengo valuation (net to AAOG)Resource case Net WI reserves

mmbblEV/bbl$/bbl

Unrisked NPV$mm

GeologicalCoS

Dry hole cost $mm

Risked NPVp/sh

Best case – 5 well development 4.8 14.2 67.6 60% 0.5 17.9High case – 13 well development 13.2 12.8 169.0 60% 0.5 44.7

Source: finnCap



19

Djeno valuation

For the Djeno, we have modelled the Best (15.9mmbbls gross) and High (42.3mmbbls gross) prospective resource cases as per the CPR. While neighbouring wells in the Djeno have achieved flow rates ~5,000 bpd, to be conservative we have assumed each well produces at 2,500 bpd with an initial decline rate of 25% p.a., moderating to 15% p.a. after four years. The number of development wells required varies from four in the Best case to 10 in the High case, with two wells drilled per annum. We have assumed drilling costs of $4m per well with an additional $2.5m capex for storage/topside facilities and $8m to connect to an export terminal. This gives development costs of $30.5m and $54.5m respectively for the Best and High resource cases, or $1.9/bbl and $1.3/bbl.

Figure 21: Djeno gross production profiles (bpd)

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Djeno - Best Djeno - High

Source: finnCap

Figure 22: Djeno net cash flow ($m)

(10.0)

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Djeno - Best Djeno - High

Source: finnCap

Figures 21 and 22 illustrate the gross production profiles and net cash flow streams associated with each of the Djeno resource cases modelled. In the Best case, production peaks at ~6,000 bpd, generating net cash flow for AAOG of ~$40m at peak. In the High case, production hits 13,000 bpd and net cash flow peaks at ~$85m.

This gives an unrisked valuation range for the Djeno horizon of $156-360m (69-159p/sh), or 16-39p/sh on a risked basis.

Net asset value

We have compiled a blended risked NAV using the Best case resource estimates for the three horizons to set our price target, factoring in the company’s net cash and the NPV of G&A at $1.2m per annum. This gives a risked NAV for AAOG of 41p/sh (106p/sh unrisked). With the stock currently trading at 9.6p/sh, the market is ascribing little value to the Mengo or Djeno horizons that will be drilled with TLP-103.

Figure 23: Djeno valuation (net to AAOG)Resource case Net WI reserves

mmbblEV/bbl$/bbl

Unrisked NPV$mm

GeologicalCoS

Dry hole cost $mm

Risked NPVp/sh

Best case – 4 well development 9.1 17.2 156.1 25% 2.0 16.4High case – 10 well development 23.2 15.5 360.1 25% 2.0 38.9

Source: finnCap



20

Of note is the fact that the CPR from October 2016, where the above resource estimates have been sourced, only included data to the end of the licence period; July 2020 – so, effectively these resource estimates correspond to less than four years of production. The new licence, which is awaiting ratification, resets the licence period to 20 years, which means these resource estimates are very conservative.

Figure 25 below demonstrates the risked and unrisked constituents of our NAV estimate under the different reserve case scenarios.

One point to note is the project’s lack of sensitivity to capex and opex, a function of the PSC terms (see Appendix I), whereby capital costs and operating costs are reimbursed through a typical cost-recovery mechanism. As such, a 10% change in our capex or opex assumptions only changes NAV by ~1%. The project is more sensitive to oil prices, with a 10% move in oil price changing NAV by ~11%. Given its low operating and development costs, Tilapia has a very low oil price breakeven, with all three horizons as modelled $12/bbl or less.

FinancialsAt this point, a leap of faith needs to be taken in terms of forecasting the longer-term financials for AAOG given the numerous permutations and combinations of outcomes relating to the TLP-103 well. For the purposes of this report, we have considered two scenarios: a base case assuming the development of just the R1/R2 and Mengo (Best case) horizons, and a success case, which also incorporates the development of the Djeno (Best case) reservoir.

Figure 24: AAOG net asset valueNet Asset Valuation Net WI reserves EV/bbl Unrisked value Geological Dry hole Risked NPV

mmboe $/boe $mm CoS cost $mm p/shNet cash / (debt) 2.7 1.2Placing (net) 9.2 4.0G&A costs -10.6 -4.7Tilapia - R1/R2 1.1 12.0 13.2 100% 0.0 6.3

1P: Core value 14.4 6.8Discovered/Undeveloped reserves:

Tilapia - Mengo (Best) 4.8 14.2 67.6 60% 0.5 17.9

2P: Core + discovered value 82.0 24.7Visible Exploration:

Tilapia - Djeno (Best) 9.1 17.2 156.1 25% 2.0 16.4

3P: Core + discovered + visible exploration value 238.1 41.1

Source: finnCap

Figure 25: AAOG NAV waterfall chart

6.8 17.929.8

74.516.4

68.8

158.7

44.5

38.8

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250.0

Core (Netcash +R1/R2)

Mengo Best(risked)

Djeno Best(risked)

Mengo High(risked)

Djeno High(risked)

Mengo Best(unrisked)

Djeno Best(unrisked)

Mengo High(unrisked)

Djeno High(unrisked)

p/sh

are

price target

Source: finnCap



21

The base case assumes gross production peaks ~2,000 bpd and has associated gross life of field capex of $22m, or just over $2/bbl. For the success case, gross Tilapia oil production peaks at over 8,000 bpd in 2021 and has gross life of field capex of $53m, or again ~$2/bbl. Not only are unit costs expected to be much lower than a typical offshore development (F&D $10-15/bbl), but the phasing of the capex is much less intensive. As mentioned earlier, the majority of facilities are already in place and capex is largely focused on a drilling and workover programme. As such, AAOG’s share of capex should be able to be funded from internal cash flows.

Valuation multiplesWe have financially modelled out these two cases described above:

Figure 26: Tilapia gross production forecasts (bopd)

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Source: finnCap

Figure 27: AAOG financial scenarios summary2018E 2019E 2020E 2021E 2022E

R1-R2 + Mengo (Best)Gross production (boepd) 217 1,208 1,682 2,120 2,458Earnings (£m) -0.6 6.2 8.6 11.3 11.9Cash flow (£m) -0.5 6.7 9.2 12.0 12.7Dividend (£m) 0.0 2.3 3.6 5.0 5.9P/E -24.1 2.5 1.8 1.4 1.3EV/EBITDA -21.7 1.9 1.4 1.1 1.0Dividend yield 0% 15% 23% 32% 38%FCF yield -25% 34% 50% 70% 83%

R1-R2 + Mengo (Best) + Djeno (Best)Gross production (boepd) 769 5,134 6,940 8,415 7,388Earnings (£m) 3.5 26.0 37.0 43.3 34.4Cash flow (£m) 3.8 27.7 39.1 45.6 36.4Dividend (£m) 0.0 16.4 23.0 30.2 25.7P/E 4.4 0.6 0.4 0.4 0.4EV/EBITDA 3.4 0.5 0.3 0.3 0.4Dividend yield 0% 106% 149% 195% 166%FCF yield 4% 153% 213% 278% 238%

Source: finnCap



22

Even if the Djeno sands do not come in, AAOG could still trade on highly attractive earnings and cash flow multiples and generate meaningful free cash flow and dividends from the R1-R2 and Mengo horizons alone (our base case). In the Djeno sands success case (Best), these multiples become somewhat ludicrous; trading under 1x earnings and EV/EBITDA and generating major free cash flow and dividends. Life is rarely that straight forward, however, but these estimates demonstrate the material upside potential that could be unlocked with the upcoming TLP-103 well.

Dividend policyThe company has stated that once production reaches 1,000 bpd and assuming that oil prices are not less than $30/bbl, it will distribute dividends of at least 50% of net profits after allowing for necessary capex and subject to the availability of distributable reserves. If production exceeds 5,000 bpd, it will distribute at least 75% of net profits.

The table above illustrates the distributable cash flow post all deductions at the field level, assuming exploration success at all three horizons with the TLP-103 well. If Djeno is half as productive as has been shown in neighbouring fields, then the level of free cash flow generation could yield very significant dividend potential.

Figure 28: AAOG distributable profits on Djeno (Best) success case (£m)2018E 2019E 2020E 2021E 2022E 2023E 2024E

Distributable profit 0.0 16.4 23.0 30.2 25.7 21.2 18.0DPS (p/sh) - 13.4 18.8 24.7 21.0 17.3 14.7 Dividend yield 0% 114% 161% 211% 179% 148% 126%

Source: finnCap



23

Appendix I – Fiscal termsThe original PSA was signed in December 2005 and was extended for five years in January 2015 with an expiry of July 2020. A new 20-year licence has been recommended by SNPC and is awaiting formal ratification by the Director General of Hydrocarbons, the Minister and the Conseil des Ministres.

Additionally, there is a 15% Royalty.

Appendix II - Offtake agreementOfftake agreement signed in April 2007 with CORAF – SNPC’s refining subsidiary.

No minimum or maximum production.

PK trucks to refinery gate.

Price set quarterly by committee of all producers and tracks Brent with no discount.

Adjustments made retrospectively, including average monthly production.

Pricing based on NKOSSA blend 41.2 API.

CORAF settles on 20th of each month in arrears.

Payment in Euros.

Oil mainly used for local refining and local markets.

Agreement under Congolese law, with arbitration in Paris.

Figure 29: Fiscal TermsCumulative oil (mmbbl) Cost Oil

(%)Profit oil (%)

Contractor profit oil (%) Government profit oil (%)

0-1 70 30 70 301-5 60 40 60 405-25 55 45 55 45>25 50 50 50 50

Source: PK, SNPC



24

Appendix III – Management incentivesManagement share options (15%, 20p exercise price) were granted at Initial Completion or joining at the 20p placing price and vest in three tranches once total oil production at Tilapia reaches certain production milestones:

1/3 on production of 1,000 bpd

1/3 on production of 2,500 bpd

1/3 on production of 5,000 bpd (in each case measured over a consecutive 30-day period)

Subject to achieving the minimum production targets set out above, vesting is one-third on date of grant, one-third on first anniversary of grant and one-third on second anniversary of grant.

The executives have agreed to defer 75% of their accrued but unpaid consultancy fees of £120,000 each against achieving increases in production.

25% of consultancy fees were paid on admission to AIM.

Remaining 75% deferred and paid in three tranches contingent on the company achieving sustained increases in aggregate production to 500, 625 and 750 bpd respectively.

Executives have also agreed that they will defer half of their remuneration if the oil price is less than US$35/bbl and if the company is otherwise cash-flow constrained.



25

Appendix IV – ManagementDavid Sefton – Executive ChairmanDavid has extensive experience of making, managing and exiting investments and has significant public and private board experience. He is a specialist in the oil & gas industry across Europe, Russia, the Middle East and North America. He has worked with many of the world’s leading international and national oil companies and is a private equity manager and executive. David completed undergraduate and postgraduate studies at the University of Oxford and qualified as a barrister. He then worked at Cleary, Gottlieb, Steen & Hamilton before becoming Chief Legal Officer for the international acquisition arm of LukOil.

James Berwick – CEOAppointed in January 2018, Mr Berwick has held several senior executive positions within leading independent oil and gas operators, including privately owned and Africa-focused Impact Oil & Gas and Ophir Energy plc, which is listed on the London Stock Exchange. Between 2013 and 2018, James held the board-level position of Commercial Director of Impact, during which he oversaw a significant expansion of the company's activities, including the acquisition of six assets. Mr Berwick was also instrumental in securing farm-out agreements with operators including Exxon, Statoil, Woodside, CNOOC and TOTAL. At Ophir, James was Director of New Business (2006 - 2013) with responsibility for scaling up and managing the company's portfolio ahead of its successful IPO in 2011. As well as overseeing every commercial transaction completed during this period, he was also responsible for successfully de-risking Ophir's asset base within the constraints of available capex. James previously held the role of General Manager for Gabon where Ophir drilled several wells under his supervision and he managed the company's operated assets throughout Africa, including Marine IX in the Republic of the Congo. Before his career in the oil and gas industry, James served for 12 years in the British Army and the French Foreign Legion.

James Andrew Cane – Finance DirectorJames has been a chief executive and finance director of both listed and private equity-backed businesses, including at Ashley House plc, a quoted developer of doctors’ surgeries and health centres. He was a non-executive director of the Lambeth Building Society until its sale to the Nationwide in 2006. He was also the chief financial officer of 8 Miles LLP, a private equity firm managing a fund to invest in buyouts across Africa. James is the chief financial officer of Linton Capital, an investment manager in the oil & gas services sector, and finance director of KCR Residential REIT plc. He has operated a financial and management consultancy business for over 30 years, advising a number of national and international private-equity firms on strategy, fundraising, marketing and business development. He is a director of Queen’s Club and is chairman of its finance committee.

Phil Beck – Non-Executive DirectorPhil is a senior energy industry business consultant with over 40 years’ commercial, engineering and project management experience in the upstream oil and gas industry. Trained as a geologist and petroleum engineer, he spent his early career with British Gas and Unocal Corporation. For the last 24 years, he has worked as a consultant, during which time he assisted Saudi development company, Delta International, on several M&A transactions in the upstream oil and gas sector as well as in other industry sectors. Phil was formerly engaged as an adviser to Lazard for energy-related transactions and has been a director of a number of energy companies, including Centurion Energy (operating in Egypt and Tunisia), formerly a Canadian listed oil and gas company, and Island Oil and Gas plc (operating in Ireland and the Netherlands), formerly quoted on the LSE AIM market. He was also a director of a Middle East service company operating in Saudi Arabia and neighbouring countries.



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Nick Butler – Non-Executive DirectorNick is the founding Chairman of the Policy Institute at King’s College London, which links academic work to policy-makers in the UK and across Europe. Since May 2010, he has held the post of Visiting Professor at King’s College London and is currently the external adviser and reviewer of the World Energy Outlook, the flagship publication of the International Energy Agency. In addition, Nick is a member of the Strategic Advisory Council of Statoil, the Norwegian state-controlled energy company and serves on the Advisory Council Centre for Ecology and Hydrology, an independent agency wholly owned by the UK government. Between 2009 and 2010, Nick was Senior Policy Adviser to Gordon Brown, then UK Prime Minister, specialising in business policy and the stabilisation of the UK economy after the 2008 financial crash. Between 2007 and 2009, Nick served as Chairman of the Cambridge Centre for Energy Studies based at the Judge Business School, University of Cambridge.

Prior to his economic consultancy work, Nick held several senior positions at BP plc (BP.L) including Group Vice-President for Strategy and Policy Development, advising the Chief Executive and the Executive Committee on climate change, mergers and acquisitions, organisational change and major new ventures; Group Policy Adviser to the Chief Executive on all aspects of policy; Head of External Affairs, responsible for the company’s links with stakeholders, including NGOs, the financial community, investors, the media and Government; and Head of Investor Relations for upstream exploration and production.

Sarah Cope – Non-Executive DirectorSarah has over 20 years’ experience as an investment banker in London, advising small and mid-sized companies at Board level on corporate governance, growth strategy, acquisitions and disposals, capital markets and regulatory compliance. Over the last ten years, she has specialised in the oil and gas sector, assisting listed oil and gas companies to raise finance for their exploration, development and production projects around the world. Her most recent role was with Cantor Fitzgerald Europe, the global investment bank and brokerage business, where she was until very recently Managing Director and Co-Head of Energy. Prior to this, Sarah was Head of Oil & Gas at RFC Ambrian and at finnCap. She has also been Director of Equity Capital Markets at RBC Capital Markets and Director of Corporate Finance at Seymour Pierce.

Brian Moritz – Non-Executive DirectorBrian is a former senior partner of Grant Thornton, London. He formed Grant Thornton’s Capital Markets Team, which floated over 100 companies on AIM under his chairmanship. In 2004, he retired to concentrate on bringing new companies to the market as a director. He focuses on natural resources companies, primarily in Africa, and was formerly Chairman of African Platinum PLC and Metal Bulletin PLC as well as currently being chairman of several junior mining companies. Brian is chairman of AIM-listed Goldplat plc and Keras Resources plc, where he has responsibility for corporate governance issues and compliance with AIM. He is a fellow of the Institute of Chartered Accountants in England and Wales.



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Income statement 2016A 2017E 2018E 2019E 2020EYear end: DecSales £m 0.0 0.2 1.6 8.4 10.8Cost of sales £m 0.0 -0.3 -1.0 -0.6 -0.5Gross profit £m 0.0 -0.1 0.6 7.8 10.3Operating expenses £m -0.9 -3.1 -1.2 -1.2 -1.2EBITDA (adjusted) £m -0.9 -3.2 -0.6 6.6 9.1Depreciation £m 0.0 -0.1 -0.1 -0.5 -0.6Amortisation £m 0.0 0.0 0.0 0.0 0.0EBIT (adjusted) £m -0.9 -3.3 -0.7 6.1 8.5Associates/other £m 0.0 0.0 0.0 0.0 0.0Net interest £m -0.0 -0.1 0.0 0.1 0.1PBT (adjusted) £m -0.9 -3.4 -0.6 6.2 8.6restructuring costs £m 0.0 0.0 0.0 0.0 0.0share based payments £m 0.0 0.0 0.0 0.0 0.0other adjustments £m 0.0 0.0 0.0 0.0 0.0Total adjustments £m 0.0 0.0 0.0 0.0 0.0PBT (stated) £m -0.9 -3.4 -0.6 6.2 8.6Tax charge £m 0.0 -0.0 0.0 0.0 0.0tax rate % n/a n/a n/a 0.0 0.0Minorities £m 0.0 0.0 0.0 0.0 0.0Reported earnings £m -0.9 -3.4 -0.6 6.2 8.6Tax effect of adjustments / other £m 0.0 0.0 0.0 0.0 0.0Adjusted earnings £m -0.9 -3.4 -0.6 6.2 8.6

shares in issue (year end) mshares in issue (weighted average) m 42.4 52.4 122.5 162.1 162.1shares in issue (fully diluted) m 42.4 69.5 162.1 162.1 162.1EPS (adjusted, fully diluted) p -2.2 -4.9 -0.4 3.8 5.3EPS (stated) p -2.2 -6.5 -0.5 3.8 5.3DPS p 0.0 0.0 0.0 1.4 2.2

Growth analysis (adjusted basis where applicable)Sales growth % n/m n/m 606.7% 432.1% 28.5%EBITDA growth % n/m -248.7% 81.8% n/m 36.9%EBIT growth % n/m -256.8% 79.5% 998.5% 39.1%PBT growth % n/m -260.5% 81.0% n/m 39.2%EPS growth % n/m -120.4% 91.9% n/m 39.2%DPS growth % n/m n/m n/m n/m 51.9%

Profitability analysis (adjusted basis where applicable)Gross margin % n/m -50.1% 38.6% 93.4% 95.4%EBITDA margin % n/m n/m -37.4% 79.1% 84.3%EBIT margin % n/m n/m -43.3% 73.1% 79.1%PBT margin % n/m n/m -40.7% 73.9% 80.0%Net margin % n/m n/m -40.7% 73.9% 80.0%



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Cash flow 2016A 2017E 2018E 2019E 2020EYear end: DecEBITDA £m -0.9 -3.2 -0.6 6.6 9.1Net change in working capital £m 0.8 1.5 0.0 0.0 0.0Share based payments £m 0.0 0.0 0.0 0.0 0.0Profit/(loss) on sale of assets £m 0.0 0.0 0.0 0.0 0.0Net pensions charge £m 0.0 0.0 0.0 0.0 0.0Change in provision £m 0.0 0.0 0.0 0.0 0.0Other items £m 0.1 -0.0 0.0 0.1 0.1Cash flow from operating activities £m -0.0 -1.7 -0.5 6.7 9.2Cash interest £m 0.0 -0.1 0.0 0.1 0.1Tax paid £m 0.0 0.0 0.0 0.0 0.0Capex £m 0.0 -7.9 -3.3 -1.5 -1.5Free cash flow £m -0.0 -9.7 -3.8 5.3 7.8Disposals £m 0.0 0.0 0.0 0.0 0.0Acquisitions £m 0.0 0.0 0.0 0.0 0.0Dividends on ord shares £m 0.0 0.0 0.0 -2.3 -3.6Other cashflow items £m 0.1 -1.1 -0.6 0.0 0.0Issue of share capital £m 0.0 13.5 7.4 0.0 0.0Net change in cash flow £m 0.0 2.7 3.0 2.9 4.2Opening net cash (debt) £m 0.0 0.0 2.7 5.6 8.5Closing net cash (debt) £m 0.0 2.7 5.6 8.5 12.8

Cash flow analysisCash conversion (op cash flow / EBITDA) % n/m n/m n/m 101.1% 101.2%Cash conversion (free cash flow / EBITDA) % 5.3% 297.6% 648.3% 79.2% 85.6%Underlying free cash flow (capex = depreciation) £m -0.0 -1.9 -0.6 6.3 8.7Cash quality (underlying FCF / adjusted earnings) % 5.2% 55.2% 93.6% 101.1% 101.2%Investment rate (capex / depn) x n/m 105.0 36.0 3.0 2.7Interest cash cover x n/a n/a net cash n/a n/aDividend cash cover x n/a n/a n/a 2.2 2.2



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Balance sheet 2016A 2017E 2018E 2019E 2020EYear End: DecTangible fixed assets £m 0.0 2.4 5.7 6.7 7.6Goodwill £m 0.0 0.0 0.0 0.0 0.0Other intangibles £m 0.0 5.4 5.4 5.4 5.4Other non current assets £m 0.0 0.0 0.0 0.0 0.0

inventories £m 0.0 0.0 0.0 0.0 0.0trade receivables £m 0.1 0.9 0.9 0.9 0.9trade payables £m -1.0 -3.3 -3.3 -3.4 -3.5Net working capital £m -0.9 -2.4 -2.4 -2.5 -2.6Other assets £m 0.0 0.0 0.0 0.0 0.0Other liabilities £m 0.0 0.0 0.0 0.0 0.0Gross cash & cash equivalents £m 0.0 2.7 5.6 8.5 12.8Capital employed £m -0.9 8.1 14.2 18.1 23.2

Gross debt £m 0.1 0.0 0.0 0.0 0.0Net pension liability £m 0.0 0.0 0.0 0.0 0.0Shareholders equity £m -1.0 8.1 14.2 18.1 23.2Minorities £m 0.0 0.0 0.0 0.0 0.0Capital employed £m -0.9 8.1 14.2 18.1 23.2

Leverage analysisNet debt / equity % n/a no debt no debt no debt no debtNet debt / EBITDA x n/a n/a n/a no debt no debtLiabilities / capital employed % n/a 0.0% 0.0% 0.0% 0.0%

Working capital analysisNet working capital / sales % n/m n/m -153.8% -29.7% -24.1%Net working capital / sales days n/m n/m -561 -109 -88Inventory (days) days n/m 0 0 0 0Receivables (days) days n/m 1,446 205 38 30Payables (days) days n/m 5,345 766 147 118

Capital efficiency & intrinsic valueAdjusted return on equity % 94.9% -41.9% -4.5% 34.3% 37.3%RoCE (EBIT basis, pre-tax) % 99.4% -41.2% -4.8% 33.9% 36.8%RoCE (underlying free cash flow basis) % 5.2% -23.1% -4.2% 34.7% 37.8%NAV per share pNTA per share p



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NOTES



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NOTES



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Research Mark Brewer 020 7220 0556 [email protected] Guy Hewett 020 7220 0549 [email protected] Buxton 020 7220 0542 [email protected] Nik Lysiuk 020 7220 0546 [email protected] Daniel 020 7220 0545 [email protected] Mark Paddon 020 7220 0541 [email protected] Darley 020 7220 0547 [email protected] Martin Potts 020 7220 0544 [email protected] Grime 020 7220 0550 [email protected] Peter Smedley 020 7220 0548 [email protected] Greaves 020 7220 0553 [email protected] Jonathan Wright 020 7220 0543 [email protected] Broking Andrew Burdis 020 7220 0524 [email protected] Alice Lane 020 7220 0523 [email protected] Chambers 020 7220 0514 [email protected] Tim Redfern 020 7220 0515 [email protected] Camille Gochez 020 7220 0518 [email protected] Abigail Wayne 020 7220 0594 [email protected] Jain 020 3772 4652 [email protected] Stephen Joseph 020 7220 0520 [email protected] Louise Talbot 020 3772 4651 [email protected] de Silva 020 7220 0521 [email protected] Malar Velaigam 020 7220 0526 [email protected] Morris 020 7220 0511 [email protected] Rhys Williams 020 7220 0522 [email protected] Norcross 020 7220 0513 [email protected] Relations Lianne Tucker 020 7220 0527 [email protected] Lisa Welch 020 7220 0519 [email protected] Nicholls 020 7220 0528 [email protected] Trading Kai Buckle 020 7220 0529 [email protected] Danny Smith 020 7220 0533 [email protected] Fidgen 020 7220 0536 [email protected] Oliver Toleman 020 7220 0531 [email protected] Makers Steve Asfour 020 7220 0539 [email protected] James Revell 0207 220 0532 [email protected] CompaniesJohnny Hewitson 020 7720 0558 [email protected] Mark Whitfeld 020 3772 4697 [email protected] Tepes 020 3772 4698 [email protected]

60 New Broad StreetLondon EC2M 1JJTel 020 7220 0500Fax 020 7220 0597Email [email protected] www.finncap.comfinnCap is registered as a company in England with number 06198898. Authorised and regulated by the Financial Conduct Authority. Member of the London Stock Exchange

* finnCap is contractually engaged and paid by the issuer to produce this material on an ongoing basis and it is made available at the same time to any person wishing to receive it.

A marketing communication under FCA Rules, this document 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.

This research cannot be classified as objective under finnCap Ltd research policy. Visit www.finncap.com

The recommendation system used for this research is as follows. We expect the indicated target price to be achieved within 12 months of the date of this publication. A ‘Hold’ indicates expected share price performance of +/-10%, a ‘Buy’ indicates an expected increase in share price of more than 10% and a ‘Sell’ indicates an expected decrease in share price of more than 10%.

Approved and issued by finnCap Ltd for publication only to UK persons who are authorised persons under the Financial Services and Markets Act 2000 and to Professional customers. Retail customers who receive this document should ignore it. finnCap Ltd uses reasonable efforts to obtain information from sources which it believes to be reliable, but it makes no representation that the information or opinions contained in this document are accurate, reliable or complete. Such information and opinions are provided for the information of finnCap Ltd's clients only and are subject to change without notice. finnCap Ltd’s salespeople, traders and other representatives may provide oral or written market commentary or trading strategies to our clients that reflect opinions contrary to or inconsistent with the opinions expressed herein. This document should not be copied or otherwise reproduced. finnCap Ltd and any company or individual connected with it may have a position or holding in any investment mentioned in this document or a related investment. finnCap Ltd may have been a manager of a public offering of securities of this company within the last 12 months, or have received compensation for investment banking services from this company within the past 12 months, or expect to receive or may intend to seek compensation for investment banking services from this company within the next three months. Nothing in this document should be construed as an offer or solicitation to acquire or dispose of any investment or to engage in any other transaction. finnCap Ltd is authorised and regulated by the Financial Conduct Authority, London E14 5HS, and is a member of the London Stock Exchange.


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