PTR.L Regulatory News (PTR)

28 June 2013

PetroNeft Resources plc

("PetroNeft" or the "Group" or the "Company")

2012 Final Results

Operations Update

PetroNeft (AIM: PTR) owner and operator of Licences 61 and 67, Tomsk Oblast, Russian Federation, is pleased to report its final results for the year ended 31 December 2012 and to provide an operations update. In addition, PetroNeft announces that the Company's Annual Report and Accounts for the year ended 31 December 2012 and Notice of AGM will be mailed to shareholders today and is now available online at the Company's website www.petroneft.com. The latest report on Licence 61 from independent petroleum consultants, Ryder Scott, is also now available on the website.

2012 Operational Highlights

·; Average production of 2,204 bopd (2011: 2,049 bopd); FY production of 806,761 barrels

·; Arbuzovskoye oil field brought to year-round production

·; Group 2P reserves 131 mmbbls

2012 Financial Highlights

·; Revenue US$34.6 million (2011: US$29.0m)

·; Pre-tax loss for year narrows to US$2.8 million (2011: US$16.4m)

·; Capital expenditure of US$14 million (2011: US$52 m)

June 2013 Operations Update

·; Current total production steady at 2,600 bopd

·; Water injection commenced at Arbuzovskoye oil field

·; Monthly repayments to Macquarie commenced

·; Farmout and refinancing discussions ongoing

In April 2013, one oil production well at Arbuzovskoye was converted to a water injection well. This is working well but it will take several months to see the full benefit of this injection well. Current production is steady at 2,600 bopd.

In March 2013, we commenced repayments of US$650,000 per month to Macquarie Bank Limited and we continue to make these payments from our own resources. To support the Company's growth aspirations we have appointed financial advisors, Evercore Partners LLP, to assist with negotiations in relation to a potential farmout of up to 50% of Licence 61 and are currently in discussions with a number of parties. We are also in active negotiation with a number of Russian and International banks to refinance the Macquarie debt facility with a longer term arrangement which more appropriately reflects the long term production profile and growth potential of our asset base.

Dennis Francis, Chief Executive Officer of PetroNeft Resources plc, commented:

"Overall, 2012 was a challenging year. While we are pleased we brought a second oil field into production, regrettably this success was overshadowed by the production results from Pad 2 at Lineynoye and the consequent financial constraints that have slowed the Group's development.

With the Arbuzovskoye, Sibkrayevskoye and Tungolskoye oil fields the Group can generate significant cash in the coming years utilising the infrastructure already in place as well as through the addition of yet to be discovered reserves from our portfolio of exploration prospects. The combination of proven production and operating experience, high quality undeveloped reserves and extensive regional infrastructure makes PetroNeft's portfolio highly attractive to a range of financial and industry partners."

For further information, contact:

PetroNeft Resources plc

Final Results

for the year ended 31 December 2012

PetroNeft Resources plc

Chairman's Statement

A challenging year

2012 was a difficult year for the Group. Exploration discoveries and operational successes like the pressure maintenance programme at Pad 1 in the Lineynoye oil field and the development of our second producing field at Arbuzovskoye were unable to fully compensate for the poor results from the previous year's drilling on Pad 2 at Lineynoye. As a result production and cash flows were lower than expected which restricted availability under our Macquarie debt facility and thus impeded our ability to carry out the investment programmes necessary to realise the full potential of our portfolio.

Operations

The Pad 1 wells which were drilled in 2010 have responded well to the pressure maintenance programme that we initiated in June 2011 and production here is stable with minimal decline. In the first quarter of 2012 we constructed a ten kilometre pipeline and utility line to connect the Arbuzovskoye oil field to the central processing facilities at Lineynoye. The Arbuzovskoye No. 1 exploration well was brought into production through the pipeline in May 2012 and production drilling commenced in August 2012 with good results achieved in the wells drilled to date.

The annual report details much of the innovative work that has been done to move forward with the development at Arbuzovskoye and understand the problem at Pad 2 so that it could be remedied and avoided in the future. It has been determined that there was a deterioration in rock quality and oil saturation as we got lower structurally in the Pad 2 area, which cannot be effectively remediated. In our other discovered fields we should be able to avoid this issue as most of our reserves are located higher structurally than the existing wells that have been tested successfully.

Reserves

In early 2012 the Company successfully completed the last exploration well on Licence 67 from the 2011 programme at the Ledovoye oil field where two oil pools were encountered. At Licence 61 we carried out a project to reinterpret the seismic data in the central to northern end of the licence area using the most up to date well information and more modern software since the last remapping in 2007. It shows that the southern end of Arbuzovskoye appears to be slightly smaller than previously interpreted and that both Tungolskoye and Sibkrayevskoye appear to be larger than previously interpreted.

Independent reserve auditor Ryder Scott has completed an assessment of PetroNeft's petroleum reserves and resources on Licence 61 as at 1 April 2013. Total Proved and Probable (2P) reserves stand at 117 million barrels, essentially unchanged from the previous assessment. This, combined with the portfolio of undrilled but seismically-defined structures in the north and south of Licence 61, confirms the Group's strong reserve base.

Ryder Scott did not update the reserves in Licence 67 as further work is required to establish the full potential of this Licence. Studies are now underway to better define the three new oil pools discovered at Cheremshanskoye and two oil pools at Ledovoye.

Net Loss

The net loss for the year decreased to US$4,566,143 from US$17,913,356 in 2011. The decrease in the net loss can be attributed to an improvement in gross margin as a result of increased production and oil price, an impairment of oil and gas properties of US$5,000,000 in 2011 and a foreign exchange gain of US$4,538,236 (2011: loss of US$5,114,345) on US Dollar denominated loans from PetroNeft to its wholly owned subsidiary, Stimul-T whose functional currency is the Russian Rouble. This gain arises due to the strengthening of the Russian Rouble against the US Dollar in the last year. Administrative expenses were largely consistent with 2011.

Revenue, Cost of Sales and Gross Margin

Revenue from oil sales was US$34,581,257 for the year (2011: US$29,031,693). Cost of sales includes depreciation of US$4,219,955 (2011: US$3,968,704). We would expect the gross margin to improve in future periods as our facilities and field operations are fully staffed and can handle additional production from the Arbuzovskoye oil field under the current cost structure. We produced 806,761 barrels of oil (2011: 748,079 barrels) in the year or an average of 2,204 bopd (2011: 2,050 bopd) and sold 812,006 barrels of oil (2011: 719,422 barrels) achieving an average oil price of US$42.86 per barrel (2011: US$40.35 per barrel). The increase in production and barrels sold is a result of more wells producing in 2012. All of our oil was sold on the domestic market in Russia.

Finance Costs

Finance costs of US$4,216,548 (2011: US$2,501,070) relate to interest on loans, arrangement fees in relation to the loan facilities, interest paid for late payment to suppliers and unwinding of discount on the decommissioning provision. The primary reason for the increase is the addition of the new loan from Arawak during the year along with a higher average outstanding balance on the Macquarie loan.

Finance Revenue

Finance revenue of US$77,233 (2011: US$59,854) primarily arises from interest earned on bank deposits.

Taxation

The current tax charge arises on interest earned from bank deposits. The deferred tax charge arises on interest earned by PetroNeft on loans to its wholly owned subsidiary Stimul-T.

Cost management

A number of initiatives during the year were undertaken to reduce and manage costs. While the average number of employees in the Group for the year was 188 this had reduced to 170 by year end. This has been achieved through a hiring embargo whereby department managers must first try to reallocate duties of a departing employee to other employees and can only replace a departing employee having demonstrated that this is not possible. Also, when the Arbuzovskoye oil field was brought into operation we reallocated existing employees from Lineynoye to operate the Arbuzovskoye oil field. With very few exceptions no pay rises have been awarded since January 2011.

Also during 2012 we renegotiated the contract with our supplier of electric submersible pumps ("ESP"). The cost of renting, maintaining and repairing ESPs is the largest operating cost in the field after wages and salaries. We agreed a contract to essentially fix the cost of rental, maintenance and repair of ESPs. This ensures that these costs are predictable based on the number of wells in operation.

Capital Investment

During 2012 the capital expenditure was lower than 2011 as the Group concentrated on bringing the Arbuzovskoye field into year round production including:

·; Stocking Arbuzovskoye for drilling up to 10 wells.

·; Construction of a ten kilometre pipeline and utility line from Lineynoye to Arbuzovskoye.

·; Drilling four new wells at Arbuzovskoye.

·; Mobilising two exploration rigs and stocking for same at Licence 61.

In early 2013 an additional two oil production wells and one water source well were drilled at the Arbuzovskoye oil field and, funding permitting, the Group intends to drill at least three further production wells at Arbuzovskoye as well as two exploration/delineation wells at Sibkrayevskoye and West Lineynoye and commence a programme of seismic acquisition at Sibkrayevskoye later in 2013.

Current and Future Funding of PetroNeft

In October 2012 a revised borrowing base was agreed with Macquarie Bank Limited whereby US$7.5 million was repaid from the proceeds of an equity issue completed in November 2012 and US$1 million was converted to shares of PetroNeft at 5 pence per share. It was also agreed to commence monthly repayments of US$650,000 on 31 March 2013. These repayments have now commenced and the Company is meeting them from its own resources. In addition, the revised borrowing base is subject to certain financial covenants and lender approvals for the application of certain funds typical of a facility of this nature.

The Macquarie loan matures in May 2014 at which time a final payment of US$8.4 million, net of US$4 million in restricted cash held by Macquarie, will be required. The Group is evaluating a number of alternatives to refinance or repay its debt facilities and strengthen its financial position well in advance of that date.

In order to continue the development and exploration of our assets we need to strengthen the Group's financial position. In consultation with major shareholders and finance providers we have concluded that a farmout of up to 50% of Licence 61 while remaining as operator could represent the best way to achieve this goal. In that regard we have contracted Evercore Partners, a London based financial adviser and M&A specialist with proven experience in Russia and the FSU, to conduct a formal process to seek an industry partner to join in the development and exploration of the licence. We have set up an extensive electronic data room and are in detailed discussions with a number of potential partners and hope these discussions will come to fruition in the coming months. We are also in discussions with a number of Russian and international banks with a view to re-financing the existing debt facilities. While the board will evaluate both these alternatives, we remain convinced that a farmout of Licence 61 represents the best strategic option for generating shareholder value by supporting the Group's ambitious investment plans for Licence 61 and optimising the use of our existing infrastructure in the region.

These circumstances represent a material uncertainty that may cast significant doubt upon the Group's ability to continue as a going concern which is described in more detail in Note 2.

Corporate development

In recent years we have transitioned from an exploration company to an exploration and production company. The management structure in Tomsk has been revised over the past couple of years with most new positions being filled by excellent candidates from within our own organisation. We are operating the new Arbuzovskoye oil field without having expanded our workforce. The Group headcount now stands at 170 employees.

I would like to thank all of our employees for their dedication and their hard work in 2012.

Summary

With the Arbuzovskoye, Sibkrayevskoye and Tungolskoye oil fields the Group can generate significant cash in the coming years utilising the infrastructure already in place as well as through the addition of yet to be discovered reserves from our portfolio of exploration prospects. This is an attractive proposition for a new partner or financier with a long-term view and should enable PetroNeft to expand its oil reserve base both through exploration and delineation in current licence areas and through business development opportunities in Tomsk and further afield in Russia.

PetroNeft is fortunate to have a highly experienced and dedicated team whose knowledge and experience have enabled us to meet the array of challenges facing the Group in recent years. I am confident that this team will enable PetroNeft to provide shareholders with better returns in the future.

While 2012 was a challenging year operationally and in the overall market, shareholders should not lose sight of the strong Proved and Probable reserve base. Many lessons have been learned and, along with the results of new technical studies, we have further improved our knowledge and understanding of our extensive licence acreage. We are producing from less than 15% of our reserve base and the substantial investment in infrastructure made in recent years leaves us well placed to deliver significant and profitable growth once the necessary funding is available.

Annual report and AGM

The annual report will be mailed to shareholders and published on the Company's website on 28 June 2013. The annual general meeting will be held in Dublin on 11 September 2013.

Finally, I know that I speak for all the Directors, management and staff of the Group in giving sincere thanks to our shareholders, both old and new, for your continued support through the past year.

David Golder

Non-Executive Chairman

Notes to the Final Results

For the year ended 31 December 2012

1. Basis of Accounting and Presentation of Financial Information

While the financial information included in this announcement has been prepared in accordance with the Group's accounting policies under International Financial Reporting Standards (IFRS) as adopted by the European Union, this announcement does not itself contain sufficient information to comply with IFRS. The Company is distributing the full financial statements that comply with IFRS on 28 June 2013.

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2012 or 2011, but is derived from those accounts. Statutory accounts for 2011 have been delivered to the Registrar of Companies and those for 2012 will be delivered following the Company's annual general meeting. The auditors have reported on those accounts. Both reports were unmodified, but the 2012 report did draw attention to going concern issues as described in note 2 below by way of emphasis of matter.

Adoption of new IFRS's

The Group has adopted the following new and amended IFRS and IFRIC interpretations in respect of the 2012 financial year-end:

There were no significant changes necessary arising from the above amendments to the Group during the year.

2. Going concern

In October 2012 a revised borrowing base was agreed with Macquarie Bank Limited ("Macquarie") whereby US$7.5 million was repaid from the proceeds of an equity issue completed in November 2012 and US$1 million was converted into shares of PetroNeft at 5 pence per share. It was also agreed to commence monthly repayments of US$650,000 on 31 March 2013. The revised borrowing base is subject to certain financial covenants and lender approvals for the application of funds typical of a facility of this nature and are subject to periodic review. The Company has received waivers from Macquarie in respect of breaches at year-end and for any subsequent breaches to the latest review date. The Macquarie loan matures in May 2014 at which time a final payment of US$8.4 million (in addition to the US$4 million restricted cash held by Macquarie) will be required.

In May 2012 PetroNeft entered into a new loan facility for US$15 million with our partner Arawak Energy Russia B.V. ("Arawak"). This loan carries an interest rate of LIBOR plus 6%. 4,000,000 warrants were granted to Arawak as part of this loan facility. The Arawak loan facility is a three year loan repayable in one lump sum in May 2015. Refer to note 22 for further details.

The Group has analysed its cash flow requirements through to 31 December 2014 in detail. The monthly repayments from operating cash flows of US$650,000 to Macquarie commenced in March 2013, however, based on our current cash flow forecasts the Group will need to obtain additional funding in order to repay in full the final amount of US$8.4 million due in May 2014. The cash flow includes estimates for a number of key variables including timing of cash flows of development expenditure, oil price, production rates, and management of working capital. The Directors believe that the Group's cash flow forecasts represent the Group's best estimate of the results over the forecast period as at the date of approval of the financial statements. As part of the Directors' overall consideration of the appropriateness of going concern, the cash flow is stress tested to assess the potential adverse effect arising from reasonable changes in circumstance. It is recognised that the cash flow impact of these changes could result in further funding being required. In addition, under the revised borrowing base the Group has to remain in compliance with certain financial covenants and lender approvals.

2. Going concern (continued)

The Company has entered into discussions with a number of parties and is currently pursuing two independent funding strategies. In consultation with major shareholders and finance providers we have concluded that a farmout of up to 50% of Licence 61, while remaining as operator, represents the best way to provide the necessary finance to strengthen the Group's financial position and allow it to realise the full potential of its substantial asset base. In that regard we have contracted Evercore Partners to run a formal process to seek an industry partner to join in the development and exploration of the licence. We have set up an extensive electronic data room and are in discussions with a number of potential partners. Secondly, we are also in discussions with certain Russian and international banks with a view to re-financing the existing debt facilities, however, the farmout option remains the preference of the Board of Directors. The aim of these discussions is to deliver a long term solution to the Group's finances to enable it to fully exploit its portfolio of reserves and prospects.

While, as at the date of approval of these financial statements, no commitment has been received in respect of either a farmout or re-financing, and there can be no certainty that additional funding will ultimately be received, the Directors remain confident about the outcome of these discussions and the resilience of the Group despite the pressures outlined above. These circumstances represent a material uncertainty that may cast significant doubt upon the Group and the Company's ability to continue as a going concern. Nevertheless, after making enquiries, and considering the uncertainties described above, the Directors are confident that the Group and the Company will have adequate resources to continue in operational existence for the foreseeable future. For these reasons, the Directors continue to adopt the going concern basis in preparing the annual report and accounts.

Accordingly, these financial statements do not include any adjustments to the carrying amount or classification of assets and liabilities that would result if the Group or Company was unable to continue as a going concern.

3. Segment information

At present the Group has one reportable operating segment, which is oil exploration and production. As a result, there are no further disclosures required in respect of the Group's reporting segment.

The risk and returns of the Group's operations are primarily determined by the nature of the activities that the Group engages in, rather than the geographical location of these operations. This is reflected by the Group's organisational structure and the Group's internal financial reporting systems.

Management monitors and evaluates the operating results for the purpose of making decisions consistently with how it determines operating profit or loss in the consolidated financial statements.

Geographical segments

All of the Group's sales are in Russia. Substantially all of the Group's capital expenditures are in Russia.

4. Loss per Ordinary Share

Basic loss per Ordinary Share amounts are calculated by dividing net loss for the year attributable to ordinary equity holders of the Parent by the weighted average number of Ordinary Shares outstanding during the year.

Basic and diluted earnings per Ordinary Share are the same as the potential Ordinary Shares are anti-dilutive.

The Company has instruments in issue that could potentially dilute basic earnings per Ordinary Share in the future, but are not included in the calculation for the reasons outlined below:

·; Employee Share Options - These potential Ordinary Shares are anti-dilutive for the years ended 31 December 2012 and 2011.

·; Warrants - At 31 December 2012, 14,100,000 (2011: 6,700,000) Ordinary Shares are subject to warrants being exercised. These potential Ordinary Shares are anti-dilutive for the years ended 31 December 2012 and 2011.

The net book value at 31 December 2012 includes US$8,369,828 (2011: US$24,395,926) in respect of assets under construction, which are not yet being depreciated.

Expenditure of US$11,842,430 was incurred mainly in connection with the Arbuzovskoye oil field, primarily relating to production wells and oilfield infrastructure.

In November 2011 the Board sanctioned the development of the Arbuzovskoye oilfield. Exploration and evaluation costs of US$2,914,767 in relation to the Arbuzovskoye oilfield were transferred to oil and gas properties.

Loss on disposal of oil and gas properties

During 2011, the Group disposed of pipeline and facilities relating to the decommissioning of the Lineynoye No. 1 well and the conversion of the Lineynoye No. 6 well to a water injection well resulting in a loss on disposal of US$391,188.

Impairment loss

No impairment was recognised in 2012. In 2011, an impairment of US$5 million was recognised in respect of the Lineynoye oil field. The trigger for the 2011 impairment test was primarily the effect of lower than expected production from Pads 2 and 3 at the Lineynoye oil field during the year. An impairment test in 2012 was triggered by a reduction in reserves at the Arbuzovskoye oil field as a result of thinner than expected net pays in some new wells drilled there in the year and a narrowing of the southern end of the structure based on a new seismic interpretation carried out. In addition, the reduction in the market capitalisation of the Company below the carrying value of the net assets of the Group was also an indicator of potential impairment of the carrying value of oil and gas properties and exploration and evaluation expenditure as a whole.

In assessing whether impairment is required, the carrying value of an asset or cash-generating unit ("CGU") is compared with its recoverable amount. The recoverable amount is the higher of the asset's/CGU's fair value less costs to sell and value in use. Given the nature of the Group's activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers are taking place. Consequently, the recoverable amount used in assessing the impairment charges described below is value in use. The Group generally estimates value in use using a discounted cash flow model.

Key assumptions used in value-in-use calculations for the Lineynoye and Arbuzovskoye oil fields

The calculations of value-in-use for the Lineynoye and Arbuzovskoye oil field CGU are most sensitive to the following assumptions:

·; Production volumes.

·; Discount rates.

·; Crude oil prices.

Estimated production volumes are based on detailed data for the fields and take into account development plans for the fields agreed by management as part of the long-term planning process and estimated by Ryder Scott Petroleum Consultants in their report on the Group's reserves. It is estimated that, if all production were to be reduced by 15% for the whole of the next 20 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amounts of the CGU to zero. Consequently, management believes no reasonably possible change in the production assumption would cause the carrying amount of the CGU to exceed the recoverable amount.

The Group generally estimates value in use for the oil exploration and production CGU and total oil and gas properties using a discounted cash flow model. The future cash flows are discounted to their present value using a pre-tax discount rate of 17% that reflects current market assessments of the time value of money and the risks specific to the asset. This discount rate is derived from the Group's post-tax weighted average cost of capital ("WACC"), with appropriate adjustments made to reflect the risks specific to the asset/CGU and to determine the pre-tax rate. The WACC takes into account both debt and equity. The cost of equity is derived from the expected return on investment by the Group's investors. The cost of debt is based on its interest bearing borrowings the Group is obliged to service. Segment specific risk is incorporated by applying individual beta factors. The beta factors are evaluated annually based on publicly available market data. Management also believes that currently there is no reasonably possible change in discount rate which would cause the carrying amount of the oil and gas properties to exceed their recoverable amount.

The long-term forecast Urals blend oil price used of US$95 per barrel is based on management's estimates and available market data. It is estimated that if the long-term price of Urals blend crude oil fell by 15% for the whole of the next 20 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amounts of the oil and gas properties to zero. Consequently, management believes no reasonably possible change in the oil price assumption would cause the carrying amount of oil and gas properties to exceed their recoverable amount.