PTR.L Regulatory News (PTR)

PetroNeft Resources plc

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

2011 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 2011 and to provide an operations update. In addition, PetroNeft announces that the Company's Annual Report and Accounts for the year ended 31 December 2011 and Notice of AGM will be posted to shareholders today (29 June 2012) and is now available online at the Company's website www.petroneft.com.

Operational Highlights

·; Average production of 2,049 bopd.

·; Group 2P reserves increase 36% to 131.7 mmbbls.

·; Group P1 reserves increase 50% to 20.0 mmbbls.

·; Sibkrayevskoye discovery in August 2011 was the largest single discovery made by PetroNeft to date. It contains 49.8 mmbbls of 2P reserves.

·; Expanding the central processing facility capacity at Licence 61 to 14,800 bfpd.

Financial Highlights

·; First full year of production with 748,079 barrels produced, up from 189,508 in prior year.

·; Capital expenditure of US$52 million.

·; Improved Macquarie Debt facility agreed in April 2011.

·; New US$15 million loan facility with Arawak Energy agreed in May 2012.

June 2012 Operations Update

·; Arbuzovskoye No.1 well producing at 350 bopd without fracture stimulation.

·; Current total production steady at 2,200 bopd exclusive of wells temporarily shut-in for pressure transient testing.

The Arbuzovskoye No. 1 discovery well is now in production and has been producing with an electric submersible pump at a rate of about 350 bopd since mid-May 2012. So far it has shown essentially no decline and a water cut of less than 2%. This is comparable to the best wells drilled at Pad 1 at the Lineynoye oil field, prior to fracture stimulation, and is in line with the excellent test results achieved on this well when it was first drilled in November 2010.

It is expected that a drilling crew will arrive on site at Arbuzovskoye in the coming weeks to commence drilling new production wells, the first of which we expect to bring into production in Q3 of this year.

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

"Overall, 2011 was a busy year with mixed results. PetroNeft's first full year of production and its largest ever work programme resulted in great exploration success but disappointing productivity. However, production levels have been stabilised and we are delighted with the rate being achieved from the Arbuzovskoye No. 1 well at present which bodes well for future production at the field and for our future cash flows.

Positioning the Group well financially in the years ahead such that it can fully exploit the many opportunities available to it is of crucial importance. To this end, we have initiated discussions with a range of strategic investors about possible farm-outs, long term off-take agreements and potential equity or asset investments which in the long term would strengthen the Group's financial position. "

For further information, contact:

PetroNeft Resources plc

Final Results

for the year ended 31 December 2011

A busy but mixed year

2011 was a busy year. It was PetroNeft's first full year of production and saw its largest ever work programme with 14 production wells and five exploration and delineation wells. Whilst we had great success with our exploration wells the production wells were disappointing despite having shown initial promise.

Production

14 new production wells were drilled at the Lineynoye oil field, 12 at Pad 2 and two at Pad 3. A programme of hydraulic fracturing was carried out on ten of these wells in November 2011. The initial response was positive and the field peaked at 3,000 bopd in December; however, production from the Pad 2 wells decreased rapidly and has now stabilised at around 2,200 bopd.

The Pad 1 wells which were drilled in 2010 responded very quickly to the pressure maintenance programme that we initiated in June 2011. There are currently three injection wells on Pad 1 and the production decline has now halted in many wells and in some cases started to reverse. We will convert additional Pad 2 wells to water injection wells in the coming months with the aim of restoring some of the reservoir pressure and increasing production.

The next field in our development programme is Arbuzovskoye where we plan to drill up to ten production wells in 2012. The Arbuzovskoye No. 1 exploration well is now producing about 350 bopd which is an excellent rate prior to fracture stimulation. This also confirms that we should not see similar issues to Lineynoye Pad 2 at Arbuzovskoye.

Reserves growth

The Company drilled five exploration and delineation wells in 2011, all of which were successful. We are especially delighted with the new discoveries at Sibkrayevskoye and Cheremshanskoye which we feel will prove to be major oil fields with further seismic and well delineation. These are both especially important discoveries as they prove our strategy of following up on previously drilled structures by re-interpreting old well data using modern software and techniques to identify by-passed pay.

Independent reserve auditor Ryder Scott has completed an assessment of PetroNeft's petroleum reserves and resources on Licence 61 as at 1 January 2012. As a result, total proved and probable ("2P") reserves net to PetroNeft, including our share of Licence 67, have risen by 36% from 96.9 million bbls to 131.7 million bbls. Total proved reserves ("P1") have increased by 50% from 13.3 million bbls to 20.0 million bbls in spite of the results with the Lineynoye Pad 2 wells.

Ryder Scott did not update the reserves in Licence 67 at the end of 2011 as all of the well testing was not completed. 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 increased to US$17,913,356 from US$7,125,394 in 2010. The main reason for the increase in the net loss is the impairment of oil and gas properties of US$5,000,000 and an increase of US$4,977,291 in foreign exchange loss on US Dollar denominated loans from PetroNeft to its wholly owned subsidiary, Stimul-T whose functional currency is the Russian Rouble. This loss arises due to the weakening of the Russian Rouble against the US Dollar in the last year. Administrative expenses were consistent with 2010 while the share-based payment expense increased from US$460,500 to US$1,108,446 primarily because of a full year's charge relating to share options which were issued in December 2010.

Revenue, Cost of Sales and Gross Margin

Revenue from oil sales was US$29,031,693 for the year (2010: US$5,155,646). Cost of sales includes depreciation of US$3,968,704 (2010: US$530,235). 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 748,079 barrels of oil (2010: 189,508 barrels) in the year and sold 719,422 barrels of oil (2010: 158,295 barrels) of oil achieving an average oil price of US$40.35 per barrel (2010: US$32.57 per barrel). The increase in production and barrels sold is a result of 2011 being the first year of all round production for the Group. All of our oil was sold on the domestic market in Russia.

Finance Costs

Finance costs of US$2,501,070 (2010: US$1,356,918) relate to interest on loans, arrangement fees in relation to the loan facilities and the unwinding of discount on the decommissioning provision. The reason for the increase is the increased drawdown on debt facilities during the year.

Finance Revenue

Finance revenue of US$59,854 (2010: US$126,595) 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.

Capital Investment

Several major capital projects were completed in 2011 and further significant investment is planned in 2012. 2011 projects included:

·; Drilling and completion of 14 development wells and one water source well at the Lineynoye oil field

·; Expansion of oil processing and oil storage facilities at the Lineynoye oil field.

·; Drilling and completion of five exploration and delineation wells.

In 2012, funding permitting, the Group intends to invest up to US$20 million principally to develop the Arbuzovskoye oil field which was sanctioned by the Board in November 2011.

Current and Future Funding of PetroNeft

In April 2011 a revised borrowing base loan facility was agreed with Macquarie Bank Limited for up to US$75 million with availability of US$30 million subject to six monthly reviews. To date the availability under the loan facility has remained at US$30 million with the next review due to take place on 30 June 2012.

In May 2012 PetroNeft entered into a new loan facility for US$15 million with our partner Arawak Energy. This loan carries an interest rate of LIBOR plus 6% and 4,000,000 warrants were granted to Arawak. It is a three year loan repayable in one lump sum in May 2015.

The Lineynoye Pad 2 results meant that certain production and cash flow covenants that were part of the Macquarie facility were not met during the year, at and post the year-end. While Macquarie waived these targets at year-end, it meant that it was not possible to increase the amount available under the facility. Also, Macquarie have indicated that they would prefer to reduce the available amount by approximately US$7.5 million, however they are giving the Group time to work this out while continuing to support the ongoing development at Arbuzovskoye. Macquarie supported and agreed to the Arawak additional debt facility and did not seek repayment of their own debt facility as they want to see Arbuzovskoye coming into production as it offers the best option for increasing Group production and cash flows.

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.

Macquarie remain a committed lender and are also the largest shareholder of the Company and are prepared to give us time to allow the Arbuzovskoye field come into production thereby allowing either an increase in the available amount under the loan agreement as more reserves move to the proved reserves category, or some repayment of the loan facility out of the resulting cash flows.

The Group is also in discussions with a range of strategic investors about possible farm-outs, long term off-take agreements and potential equity or asset investments which would strengthen the Group's financial position.

Business development

The principal near-term objective of the Group remains the development of the northern oil fields on Licence 61. However, we have not lost sight of our longer term objective of securing assets outside of Licence 61 to provide growth for the future.

The acquisition of Licence 67 (Ledovy) in January 2010 was a first step in this growth. Licence 67 was acquired under the August 2008 Area of Mutual Interest ("AMI") with Arawak where they have exercised their right to acquire 50% of the Licence. Licence 67 has now provided collateral in a new US$15 debt financing with Arawak and on 30 May 2012, PetroNeft entered into a new three-year AMI with Arawak. Under the agreement the two companies will continue to jointly pursue new opportunities in Western Siberia, building on the success of the previous AMI agreement that ran for three years to August 2011.

We have a good working relationship with Arawak and look forward to working with them to develop Licence 67 and acquire new assets under the AMI. We continue to actively examine a number of acquisition opportunities in the Tomsk region and elsewhere in Russia and will update shareholders in more detail at the appropriate time.

Corporate development

We have now 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 as a result most new positions being filled by excellent candidates from within our own organisation. We intend to operate the new Arbuzovskoye field with our existing workforce. The Group headcount now stands at 174 employees.

I would like to thank all of our employees for their dedication to the Company and their hard work in 2011.

Summary

Overall, 2011 was a busy year with mixed results. PetroNeft's first full year of production and its largest ever work programme resulted in great exploration success but disappointing productivity in the Pad 2 production wells.

PetroNeft has moved quickly to understand the production issues at Pad 2 and I am confident we can avoid similar problems at Arbuzovskoye and Sibkrayevskoye which are the next two major developments.

With the Arbuzovskoye and Sibkrayevskoye oil fields the Group can generate significant cash in the coming years that should enable it 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 continue to add shareholder value.

Annual report and AGM

The annual report will be mailed to shareholders and published on the Company's website on 29 June 2012. The annual general meeting will be held in Dublin on 19 September 2012.

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

Consolidated Cash Flow Statement (continued)

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 29 June 2012.

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2011 or 2010, but is derived from those accounts. Statutory accounts for 2010 have been delivered to the Registrar of Companies and those for 2011 will be delivered following the Company's annual general meeting. The auditors have reported on those accounts. Both reports were unqualified, but the 2011 report did draw attention to going concern issues as described in note 2 below by way of emphasis of matter.

Adoption of new IFRS

The Group has adopted the following new and amended IFRS and IFRIC interpretations in respect of the 2011 financial year-end:

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

2. Going concern

In April 2011 a revised borrowing base loan facility was agreed with Macquarie Bank Limited ("Macquarie") for up to US$75 million, with US$30 million immediately available subject to six monthly reviews. Refer to note 11 for further detail. To date the availability under the borrowing base loan facility has remained at US$30 million with the next review due to take place on 30 June 2012.

In May 2012 PetroNeft entered into a new loan facility for US$15 million with our partner Arawak Energy Russia B.V. ("Arawak"). Refer to note 11 for further details. 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.

The Lineynoye Pad 2 results meant that certain production and cash flow covenants that were part of the Macquarie facility were not met during, at and post the year-end. While Macquarie waived these covenants at the year-end, it meant that it was not possible to increase the amount available under the borrowing base loan facility. Macquarie supported and agreed to the Arawak additional loan facility and did not seek repayment of their base loan facility as Macquarie prefer to see Arbuzovskoye coming into production as it offers the best option for increasing Group production and cash flows.

Although Macquarie remains a supportive lender and key shareholder, they have indicated, absent any alternative funding option, their preference that the debt be reduced by about US$7.5 million over the next 12 months. However they did not seek a repayment out of the proceeds of the Arawak loan facility and remain supportive of the Group's plans to bring the Arbuzovskoye oil field into production this year particularly in light of the recent rates achieved from the Arbuzovskoye No. 1 well. The Board has a plan to bring the Arbuzovskoye oil field into production in the coming months thereby increasing the Group's long-term cash flows.

2. Going concern (continued)

The Board remain positive about the resilience of the Group despite the pressures outlined above. The Group has analysed its cash flow requirements through to 31 December 2013 in detail. The cash flow includes estimates for a number of key variables including timing of cash flows of development expenditure, oil price, production rates, and with the ongoing support of its lenders and management of working capital the Directors believe that the Group's cash flow forecasts represent the Group's best estimate of the actual results over the forecast period at the date of approval of the financial statements. The cash flow is stress tested to assess the adverse effect arising from reasonable changes in circumstance. It is recognised that the cash flow impact of these changes could result in additional funding being required. The Group is also in discussions with a range of strategic investors about possible farm-outs, long term off-take agreements and potential equity or asset investments which would strengthen the Group's financial position.

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 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 2011 and 2010.

·; Warrants - At 31 December 2011, 6,700,000 (2010: 6,200,000) Ordinary Shares are subject to warrants being exercised. These potential Ordinary Shares are anti-dilutive for the years ended 31 December 2011 and 2010.

5. Assets held for sale

In January 2010, the Group acquired and registered Licence 67. Under the August 2008 Area of Mutual Interest agreement, Arawak Energy exercised their option to participate as a 50% partner in the development of Licence 67, which will be operated by PetroNeft. PetroNeft Resources Plc entered into an agreement with Arawak to jointly own and control a holding company (Russian BD Holdings B.V.) which holds all of the shares of LLC Lineynoye, an entity involved in oil and gas exploration and the registered holder of Licence 67. The legal agreements and documentation relating to the jointly controlled entity were completed in September 2011 when the assets were transferred to the jointly controlled entity. At 31 December 2010, assets in connection with Licence 67 were classified as held for sale.

On 9 September 2011, Russian BD Holdings B.V., which was previously a 100% subsidiary of PetroNeft, became a jointly controlled entity, resulting in a profit on disposal on consolidation of US$223,222 comprised as follows:

The net book value at 31 December 2011 includes US$24,395,926 (2010: US$17,288,826) in respect of assets under construction, which are not yet being depreciated.

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.

Expenditure of US$43,931,481 was incurred mainly in connection with the Lineynoye oil field, primarily relating to production wells, the Central Procession Facility (CPF) and oilfield infrastructure.

Loss on disposal of oil and gas properties

During the year, 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.

6. Oil and gas properties (continued)

Impairment loss

An impairment of US$5 million (2010: US$Nil) was recognised in respect of the Lineynoye oil field. The trigger for the impairment test was primarily the effect of worse than expected production from Pads 2 and 3 at the Lineynoye oil field during the year. In addition, this triggered reduced estimates of the quantities of oil recoverable from this particular field.

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 oil field

The calculation of value in use for the Lineynoye oil field ("CGU") is 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.

The Group generally estimates value in use for the oil exploration and production CGU using a discounted cash flow model. The future cash flows are discounted to their present value using a pre-tax discount rate of 16% 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.

The long-term forecast Urals blend oil price used of US$80 per barrel is based on management's estimates and available market data.