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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Urals EN. | LSE:UEN | London | Ordinary Share | CY0107130912 | ORD USD0.126 (DI) |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 35.00 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Jul 2019 to Jul 2024
TIDMUEN
RNS Number : 8919E
Urals Energy Public Company Limited
07 June 2012
7 June, 2012
Urals Energy Public Company Limited
("Urals Energy", or the "Company")
Annual Report and Accounts
Urals Energy (LSE: UEN), the independent exploration and production company with operations in Russia, is pleased to announce its audited financial results for the year ended 31 December 2011.
Overview
-- 2011 was a year of recovery with a focus on reducing costs and inefficiencies, improving cash liquidity and resolving certain legacy issues.
Operational
-- Significant workovers of the onshore Petrosakh and Arcticneft licenses commenced in 2011 focusing on exploring the potential of the surrounding resources.
-- In October 2011 the Company successfully completed the shipment of 28,982 tons of crude oil (227,525 bbls) from Arcticneft, which represented an 11.4% increase on 25,999 tons in 2010, loaded and exported in accordance with the Company's operational plans.
Financial
-- In 2011, total gross revenues increased by $4.9 million to 64.2m (2010: 59.3m) as a result of a higher crude oil net back price of $52.68 per barrel in 2011 ($36.88 per barrel in 2010) and higher average net back prices for petroleum (refined) products of $52.38 per barrel in 2011 ($43.51 in 2010).
-- In late 2011 Urals Energy transferred the loans owing to it by Taas-YuriakhNeftegazodobycha ("Taas") to Nagelfar Trade and Invest Ltd resulting in Urals Energy receiving $26 million in cash, which allowed it to substantially reduce the debt to Petraco by paying US$10m, and close an outstanding debt of US$4.4m to Finfund.
Outlook
-- Current production at Petrosakh is 1,349 BOPD.
-- At the end of May 2012 the Company successfully finished the drilling of well #41. Well #41 is undergoing final production testing and completion. It is expected to increase daily production by at least 180 BOPD.
-- The drilling of an additional new well (#53) is to be started later this year.
-- The Company has engaged several respected oil service companies in order to evaluate future steps regarding well #51 which was temporarily abandoned due to difficult drilling conditions.
-- With the successful completion of well #41, the present production capabilities of the Company have improved and strengthened and are well suited for future drilling and existing well improvement works.
-- Current production at Arcticneft is stable and stands at 710 BOPD.
-- Further potential may be identified at Arcticneft, as a result of the planned drilling of a deep exploration well by ArcticMorNefteGazRazvedka ("AMNGR") in the lower Paleozoic horizon of the Peschanoozerskoye field.
-- With a more liquid balance sheet and renewed expansion strategy, Urals is well placed to seek and add new acreage, as well as finance its existing and additional operations.
Alexei Maximov, Chief Executive, commented:
"Following the disappointment of well #51 caused by unpredictable geological conditions, with the successful completion of well #41, the present production capabilities of the Company have improved and strengthened and are well suited for future drilling and existing well improvement works.
"Financially, the Company is in much better position than in 2009 and 2010 and 2012 has opened new challenges for the Company, which will be predominantly focused on closing the historical issues (debt to Petraco and Rovneiko loan), after which a more sustainable balance sheet and renewed expansion strategy, we will be in a position to seek and add new acreage, as well as finance its existing and additional operations, while maintaining healthy conservatism regarding new deals and possible alliances. We are optimistic regarding the further improvement of operations at Petrosakh and Arcticneft, and Urals Energy is prepared for the next evolutionary transformation."
Enquiries:
Allenby Capital Limited Nominated adviser and broker +44 (0)20 3328 5656 Nick Naylor/Alex Price Pelham Bell Pottinger +44 (0)20 7861 3232 Mark Antelme Maria Blank
The annual report and accounts for the year ending 31 December 2011 will be posted to shareholders and will shortly be available from the Company's website www.uralsenergy.com in accordance with AIM Rule 20.
CEO STATEMENT AND ANNUAL REPORT TO SHAREHOLDERS
2011 for Urals Energy was a year of recovery. The Company continued to steadily cut costs and inefficiencies, improve cash liquidity and rid itself of legacy issues. In addition, downsizing measures resulted in a major change in the corporate culture which is now focused less on deal-making and more on daily operations implemented by a leaner number of dedicated employees.
At the end of 2011, after almost nine months of negotiations, Urals Energy transferred the loans owing to it by its former join venture Taas-YuriakhNeftegazodobycha ("Taas") and not repayable until 2015 to Nagelfar Trade and Invest Ltd resulting in Urals Energy receiving $26 million in cash, which allowed it to substantially reduce the debt to Petraco by paying US$10m, and close an outstanding debt of US$4.4m to Finfund(the "Settlement Fee"). Remaining net proceeds were used for development of the Company's assets and financing of working capital
In October 2011 the Company successfully completed the shipment of 28,982 tons of crude oil (227,525 bbls) from Arcticneft, which represented an 11.4% increase on 25,999 tons in 2010, loaded and exported in accordance with the Company's operational plans. Subsequently, the Company made a payment of $8.0 million to Petraco Oil Company Limited ("Petraco") in line with the restructured terms of the debt repayment agreement. This payment and repayment from the Tass-Yuriakh deal reduced the total amount of outstanding debt to approximately $10.0 million.
Significant workovers of the onshore Petrosakh and Arcticneft licenses commenced in 2011 focusing on exploring the potential of the surrounding resources. Fifteen workovers were performed in both subsidiaries in 2011 which allowed both the increase of production in Arcticneft and stabilization of production at Petrosakh.
As previously announced, management believe that further potential may be identified at Arcticneft, as a result of the planned drilling of a deep exploration well by ArcticMorNefteGazRazvedka ("AMNGR") in the lower Paleozoic horizon of the Peschanoozerskoye field. Since both Arcticneft and AMNGR operate the same field (albeit different blocks), we anticipate that AMNGR's results, if positive, may provide a strong indication for the potential for Urals to increase its reserves in the same area and formation. We expect to receive AMNGR's results in Q4 2012 and further announcements will be made at the appropriate time.
High oil prices in 2011 increased the profitability of the Company's operations, however at the same time this fact has also affected the Company's working capital position, especially at Arcticneft, where production taxes are paid at a higher tax rate. This fact was partly mitigated by changes in the export duty tax introduced in October 2011. Decrease in export duty for crude oil resulted in approximately $5/bbl of additional net back to the Company.
For the remainder of 2012 management will continue to concentrate on increasing the efficiency of the Company's existing operations. We are planning an incremental growth through our well workover program and will continue the drilling program in accordance with the fields' development plans. In downstream, the company will work to increase refining depth and improving our customer base.
Finally, the Company will continue with its selective search for further opportunities to add value and complement the existing portfolio.
2011 Financial
Operating Environment
2011 was characterised by a stable crude oil market price at an average level of $110 per barrel. Domestic prices for light oil products ranged from $88 to $127 per barrel thus securing the Company's operating cash flows at a level sufficient to maintain its operations and comply with license requirements at both fields.
The tanker from Arcticneft was shipped at the end of October 2011.
Operating Results
Hot Features
Premium
$ '000 Year ended 31 December
-----------------------------
2011 2010
------------------------------------------------ -------------------- -------
Gross revenues before excise and export duties 64,160 59,307
Net revenues after excise, export duties and
VAT 48,307 43,501
Gross profit 4,493 79,193
Operating (loss)/profit (23,143) 61,086
Normalised management EBITDA (unaudited) 4,665 2,400
Total net finance benefits 62 1,709
(Loss)/profit for the year (24,707) 52,909
------------------------------------------------ -------------------- -------
Production Year ended 31 December
-------------------------
2011 2010
--------------------------- ------------ -----------
Petrosakh bbls 505,267 528,855
Arcticneft bbls 254,445 251,194
Petrosakh BOPD (average) 1,384 1,449
Arcticneft BOPD (average) 697 688
Summary table: Gross Revenues before excise and export duties ($'000)
Year ended 31 December
------------------------------------------------ -------------------------
2011 2010
------------------------------------------------ ------------ -----------
Crude oil 28,447 34,332
Export sales 25,340 18,315
Export sales of purchased crude oil from
AMNGR - 13,079
Domestic sales (Russian Federation) 3,107 2,938
Petroleum (refined) products - domestic sales 34,913 24,130
Other sales 800 845
Total gross revenues before excise and export
duties 64,160 59,307
------------------------------------------------ ------------ -----------
In 2011, total gross revenues increased by $4.9 million as a result of a higher crude oil net back price of $52.68 per barrel in 2011 ($36.88 per barrel in 2010) and higher average net back prices for petroleum (refined) products of $52.38 per barrel in 2011 ($43.51 in 2010). Netback for domestic product sales is defined as gross product sales minus VAT, transportation costs, excise tax and refining costs.
In 2011 all domestic sales of crude oil and almost all petroleum (refined) products related to Petrosakh. In 2011 Arcticneft sold petroleum (refined) products for $308,000 ($875,000 in 2010).
Summary table: Net backs ($/bbl)
Year ended 31 December:
----------------------------------------------- --------------------------
2011 2010
----------------------------------------------- ------------ ------------
Crude oil 52.68 36.88
Export sales 57.55 40.59
Export sales (AMNGR crude oil) N/A 32.45
Domestic sales (Russian Federation) 37.82 36.52
Petroleum (refined) products - domestic sales 52.38 43.51
Other sales N/A N/A
----------------------------------------------- ------------ ------------
Gross profit (net revenues less cost of sales) in 2011 decreased to $4.5 million from a gross profit of $79.2 million in 2010. The main driver of the decreased profit in 2011 was an impairment release of $nil (2010: $70.5 million associated with Arcticneft and Petrosakh). According to IFRS, this release was included in the cost of sales. Without this release, the Gross Profit in 2011 and 2010 would have been $4.5 million and $8.7 million respectively.
Cost of sales (before impairment) in 2011 totaled $43.8 million as compared with $34.8 million in 2010 of which $8.3 million and $3.7 million respectively represented non-cash items, principally Depreciation, Amortization and Depletion. Also included in these costs are $5.4 million in 2010 of crude oil purchased from Arcticneft's neighboring operator on Kolguyev Island, FGUP AMNGR. Urals Energy purchased this oil from AMNGR and resold it together with its own produced oil for a modest profit margin, but a lesser profit margin than would be the case if Arcticneft had produced the oil itself. Other increase in operating costs is due to the increase in unified production tax by $4.8 million to $15.2 million from $10.4 million as a result of increased world oil prices.
Selling, General and Administrative expenses decreased during the year 2011 by $7.3 million to $10.4 million from $17.6 million in 2010. Without the charge for the provision for doubtful accounts receivable $0.7 million in 2011 and $5.3 million in 2010 Selling, General and Administrative expenses would have decreased during the year 2011 by $2.7 million. This was primarily caused by the one tanker shipment in Arcticneft in 2011 as compared with two shipments in 2010.
The net finance benefits during the 2011 were $0.1 million and net interest income was $2.2 million (for the 2010: net finance benefits of $1.7 million and net interest income of $3.1 million).
Net loss for the year attributable to shareholders in 2011 was $24.7 million as compared with net profit attributable to shareholders of $52.9 million in 2010, which was primarily driven by non-cash transactions associated with the impairment release of property, plant and equipment in Arcticneft and Petrosakh in 2010 discussed above and due to loss from disposal of the Taas loan.
Increase of Net revenues and decrease of Selling, General and Administrative expenses in 2011 resulted in Consolidated normalized management EBITDA increase by $2.3 million to $4.7 million in 2011 compared with $2.4 million in 2010, with EBITDA margins of 9.7 % and 5.5 % respectively.
Management EBITDA ($'000) - Unaudited
Year ended 31 December:
----------------------------------------------- --------------------------
2011 2010
----------------------------------------------------- ---------- --------------
Profit for the year (24,707) 52,909
Income tax charge 1,626 9,886
Net interest and foreign currency income (62) (1,709)
Depreciation, depletion and amortization 6,987 4,544
----------------------------------------------- ---------------- --------------
Total non-cash expenses 8,551 12,721
Loss from disposal of the Taas loans 16,470 -
Charge of unused vacation provision 2,079 -
Charge of bad debt provision 706 5,250
Share-based payments 457 2,012
Release of inventory provision (151) (892)
Release of impairment of property, plant
and equipment - (70,476)
Other non-recurrent losses 1,260 876
----------------------------------------------- ---------------- --------------
Total non-recurrent and non-cash items 20,821 (63,230)
Normalized EBITDA 4,665 2,400
----------------------------------------------- ---------------- --------------
Net debt Position
At 31 December 2011 the cash liquidity had substantially improved following a disposal of the Taas loans at the end of December 2011.
As at 31 December 2011 the Company had net debt of $1.4 million (calculated as Long-term and Short-term debt less cash in bank and Loans issued to related parties). As at 31 December 2010 net cash was $13.3 million.
At 8 December 2011 under the terms of an assignment agreement, the Company has assigned the full benefit of the Taas loans (together with all accrued interest) to Nagelfar for the total sum of $26 million. The book value of the Taas loans as at 8 December 2011 was $41 million (including the accrual of relevant interest) and transaction costs amounted $1.5 million. A loss of $16.5 million was recorded as a result of this transaction in the profit and loss section of the consolidated statement of comprehensive income. In December 2011 a payment of $21.6 million net of the non-cash settlement the payable to Finfund Limited of $4.4 million was received.
The Company repaid the tranche of the loan $4.0 million to Petraco in January 2011 and settled the tranche of the loan $8 million in November 2011. In December 2011 following the disposal of the Taas loans the Group partly discharged the debt to Petraco in the amount of $10 million. As at 31 December 2011 the long-term and short-term part amounted to $10.0 million (31 December 2010: $30.1 million).
During 2011 the Group fully impaired interest income accrued on loan to related party (Vyatcheslav Rovneiko) by $0.7 million. (during 2010 the Group impaired loan to related party by $5.2 million). This amount relates to a loan to a shareholder and former member of the management of the Group. This loan is overdue and is secured by a pledge on an entity whose primary asset is real estate properties located in Moscow. In October 2010 management became aware of the fact that the same real estate had been additionally pledged to secure funding from external banks. This fact was divulged to management and this was considered to be misconduct on behalf of the related party resulting in a devaluation of the Group's collateral. The Board has formally informed this related party that it is aware of this fact and demanded repayment of the full amount by 20 May 2011. By 20 May 2011 the Board had not received any response from the related party and the Company therefore filed the claim to the London Court of International Arbitration. The date for the hearing is set for mid-July 2012. For accounting purposes management has reassessed the carrying value of the loan and has impaired this fully. However, this does not reduce the validity of the legal claim against this related party.
Operational update
Petrosakh
Current production at Petrosakh is 1,310 BOPD. The management continuously performs detailed reviews of the wells' performance and in 2012 intends to complete workovers on four wells. Five wells are going to be transferred to artificial lift using sucker-rod pumping units. Moreover, based on analysis performed this year, the Company is planning on testing diverter technology using high-viscosity fluids. We believe that all these steps will stabilize, and hopefully, increase the level of oil production.
At the end of May 2012 the Company successfully finished the drilling of well #41. Target depth of 1,670 meters was reached. At the moment well #41 is undergoing final production testing and completion. We expect that it will increase daily production at least by 150 BOPD.
After completion of well #41, the management has reevaluated its future drilling plans. The field development plan provides for further drilling of six wells in the Southern part of the Okruzhnoye field. The drilling of an additional new well (#53) is to be started later this year. At the same time, the Company has engaged several respected oil service companies in order to evaluate future steps regarding well #51 which was temporarily abandoned due to difficult drilling conditions. The management believes that well #51 still has good potential and intends to finish its completion after receiving a detailed recovery plan.
The management has made significant personnel changes at Petrosakh, including assignment of a corporate VP Production to head all drilling and related works, hiring of en external (at this point) drilling supervisor, rearrangement of shift personnel with elimination of duplicative functions and roles. As a result, the time and effort that went into completing well #41 was reduced. This work will continue with well #53 and other functions in the Company.
The license for the Okruzhnoye field expires at the end of 2012. At the beginning of the year, the Company has applied for its renewal. According to our information, in the middle of May 2012 the Federal Subsoil Service Commission made a decision in our favor, and we expect that the license will be extended for another 20 years.
Downstream
Petrosakh continues to refine and sell 100% of its crude oil production. At the end of 2011 the Federal Law providing for the indexation of excise rates for gasoline for the period 2012-2014 years was signed. In 2012 excise tax for fuel increased by more than 30% and represented 6,822 Rubles per ton for Euro 4 gasoline and 7,382 R (in the first half of 2012) and 7,882 R (in the second half of 2012) for Euro 3. In order to mitigate the negative effects on the Company's profitability Petrosakh at the end of 2011 upgraded certification of gasoline produced from Euro 3 to Euro 4.
During the recent (end of May) visit to Sakhalin, the management met with the representatives of the Sakhalin Government and ministry of natural resources and discussed possible ways to obtain certain tax preferences (mineral restoration tax), as well as possible use of tolling schemes for the Petrosakh refinery in order to increase its capacity utilization. While difficult, given the fact that Rosneft holds an almost monopoly position on Sakhalin regarding the shipment of refined products, the management remains optimistic in a possible solution that would satisfy all parties.
We are currently evaluating the feasibility of returning to export shipments from Petrosakh, particularly of refined products, as well as shifting the emphasis to higher margin products sold on the local market. At the same time, in order to utilize more capacity of the refinery, the Company is looking for the possibility of some additional volume of oil shipments to the refinery from other oil fields in Sakhalin.
Arcticneft
Current production at Arcticneft is stable and stands at 710 BOPD. As of 27 May 2012 crude oil in stock was 90,850 bbls. The tanker is planned to be loaded in late 2012.
Following the approval of the field development plan by the State Central Development Committee and based on its current liquidity position, the Company plans to drill 3 sidetracks in 2012. At the moment drilling is scheduled for the second half of the year, since delivery of the required materials to Arcticneft can be made only during the open navigation period, which starts in June-July.
The management anticipates that several initiatives are expected to be approved by the Russian Government this year regarding establishing a preferential rate of export duty on crude oil. The management is presently analyzing the possibility of obtaining such a tax preference, which will significantly improve the liquidity position of Arcticneft taking into account its' seasonality of cash flow.
In addition, the personnel changes which were implemented and resulted in success at PSK, will be also introduced at Arcticneft and we expect a similar result in cost cutting and efficiencies.
Auditor's report
The audit report for the present financial statement has been modified with a qualification related to non-consolidation of a former subsidiary - Chepetskoe NGDU. This subsidiary was sold in January 2009, however the Group retained a call option to re-purchase the assets - the option expired in January 2010. Therefore, this error impacts the 2010 comparative information included in the accompanying 2011 consolidated financial statements with the modification being a repetition from the audit reports issued in prior years.
Going concern
Following the settlement of the Taas loan, the Group's liquidity has improved significantly. Management no longer believes that there is a material uncertainty that casts doubt over Urals Energy's ability to continue as a going concern, There are still minor funding and liquidity constraints, but based on cash flow projections and in line with prior years, the management considers that the application of the going concern assumption for the preparation of these consolidated financial statements is appropriate.
Petraco loan
After the payment of $10 million following the Taas loan assignment, the remaning debt to Petraco is presently $10.1 million, due in part ($6 million) by 30th July and ($1.3 million) by 30thNovember, with the remainder to be paid by the end of November 2013. The management is confident that the payment will be made, most likely with a delay tied to the shipment of the tanker in October. In addition, as part of the debt restructuring agreement with Petraco, further details of which were announced on 12 April 2012, following the successful repayment of the Taas loan, Petraco will free one of the assets following a third-party valuation agreeable to both parties. We are presently receiving proposals from a list of third parties that will perform a valuation of both Patrosakh and Arcticneft, after which we will agree with Petraco on a release.
Provisions for 13 milllion shares and related parties transactions
The Company has recorded a provision for the potential reimbursement of 3 shareholders, which have pledged their shares (in a total amount of 13 mln) to Finfund during the initial Taas deal. While this provision has been made in accordance with IFRS, the management strongly believes that the company is under no obligation to reimburse these shareholders for their loss of shares, which they have pledged at their own free will and under no obligation or pressure from the Company. Thus, unless enforced by a Court decision, the Company is under no obligation to reimburse the pledge.
Along with other unsubstantiated claims, this issue has been the subject of a legal action the Company has brought against its former co-founder, director and shareholder Vyatcheslav Rovneiko, in the London Court of Arbitration. The Court proceedings are scheduled to take place in July and the management hopes the after a year-long process it will prevail in defending its position.
Outlook
Following the disappointment of well #51 caused by unpredictable geological conditions, with the successful completion of well #41, the present production capabilities of the Company have improved and strengthened and are well suited for future drilling and existing well improvement works.
Personnel changes introduced at Petrosakh, as well as at headquarters and subsequently at Arcticneft, provide a firm cornerstone for further operations improvement; in addition the management is seeking to strengthen its technical team and are in talks with potential candidates, as well as outside technology service providers, which can add immediate value to our geological capabilities.
Financially, the Company is in much better position than in 2009 and 2010, and the repayment of the Taas loan has strengthened our ability to service the Petraco loan while reducing our largest legacy issue. The management believes that the early repayment of the Taas loan has enabled the Company to address immediate problems and reduce concerns over the ability of going concern, which has been present during the last several years. In addition, the improvement of relations with Finfund, has strengthened our position vis a vis our shareholder base, and eliminated the need to plan for potential legal issues.
2012 has opened new challenges for the Company, which will be predominantly focused on closing the historical issues (debt to Petraco and Rovneiko loan), after which with a more sustainable balance sheet and renewed expansion strategy, we will be in a position to seek and add new acreage, as well as finance its existing and additional operations, while maintaining healthy conservatism regarding new deals and possible alliances. We are optimistic regarding the further improvement of operations at Petrosakh and Arcticneft, and Urals Energy is prepared for the next evolutionary transformation.
Urals Energy Public Company Limited
Consolidated Statement of Financial Position
(presented in US$ thousands)
31 December
----------------------
Note 2011 2010
----------------------------------------- ----- ---------- ----------
Assets
Current assets
Cash in bank and on hand 7,722 987
Accounts receivable and prepayments 8 4,769 14,928
Inventories 9 10,019 12,911
Total current assets 22,510 28,826
----------------------------------------- ----- ---------- ----------
Non-current assets
Property, plant and equipment 10 118,267 128,817
Supplies and materials for capital
construction 2,695 2,655
Other non-current assets 11 1,147 39,426
----------------------------------------- ----- ---------- ----------
Total non-current assets 122,109 170,898
----------------------------------------- ----- ---------- ----------
Total assets 144,619 199,724
----------------------------------------- ----- ---------- ----------
Liabilities and equity
Current liabilities
Accounts payable and accrued expenses 12 4,782 10,781
Provisions 2,199 2,559
Income tax payable 5,128 5,118
Other taxes payable 5,118 5,151
Short-term borrowings and current
portion of long-term borrowings 7,316 12,172
Advances from customers 1,705 4,259
Total current liabilities 26,248 40,040
----------------------------------------- ----- ---------- ----------
Long-term liabilities
Long term borrowings 2,655 18,653
Long term finance lease obligations - 329
Dismantlement provision 1,398 1,232
Deferred income tax liabilities 13,347 12,387
Total long-term liabilities 17,400 32,601
----------------------------------------- ----- ---------- ----------
Total liabilities 43,648 72,641
----------------------------------------- ----- ---------- ----------
Equity
Share capital 1,569 1,543
Share premium 656,875 656,444
Translation difference (30,672) (28,858)
Accumulated deficit (527,684) (503,016)
----------------------------------------- ----- ---------- ----------
Equity attributable to shareholders
of Urals Energy Public Company Limited 100,088 126,113
----------------------------------------- ----- ---------- ----------
Non-controlling interest 883 970
----------------------------------------- ----- ---------- ----------
Total equity 100,971 127,083
----------------------------------------- ----- ---------- ----------
Total liabilities and equity 144,619 199,724
----------------------------------------- ----- ---------- ----------
Approved on behalf of the Board of Directors on 6 June 2012
A.D. Maximov Chief Executive Officer S.E. Uzornikov Chief Financial Officer -------------------------
Urals Energy Public Company Limited
Consolidated Statement of Comprehensive Income
(presented in US$ thousands)
Year ended 31 December
----------------------------
Note 2011 2010
------------------------------------------------------------ ----- ------------- -------------
Revenues after excise taxes and export
duties 13 48,307 43,501
Cost of sales (43,814) (34,784)
Impairment release 7 - 70,476
Gross profit 4,493 79,193
------------------------------------------------------------ ----- ------------- -------------
Selling, general and administrative
expenses (10,372) (17,639)
Other operating loss (794) (468)
Loss from disposal of the Taas loans 4 (16,470) -
Operating (loss)/profit (23,143) 61,086
Interest income 3,913 4,395
Interest expense (1,697) (1,248)
Foreign currency loss (2,154) (1,438)
Total net finance benefits 62 1,709
(Loss)/profit before income tax (23,081) 62,795
Income tax charge (1,626) (9,886)
(Loss)/profit for the year (24,707) 52,909
------------------------------------------------------------ ----- ------------- -------------
(Loss)/profit for the year attributable
to:
* Non-controlling interest (39) 949
* Shareholders of Urals Energy Public Company Limited (24,668) 51,960
------------------------------------------------------------ ----- ------------- -------------
(Loss)/earnings per share from profit
attributable to
shareholders of Urals Energy Public
Company Limited:
- Basic (loss)/earnings per share
(in US dollar per share) (0.10) 0.28
- Diluted (loss)/earnings per share
(in US dollar per share) (0.10) 0.27
Weighted average shares outstanding
attributable to:
- Basic shares 248,984,245 186,187,874
- Diluted shares 254,236,011 195,274,469
(Loss)/profit for the year (24,707) 52,909
Other comprehensive loss:
- Effect of currency translation (1,862) (488)
Total comprehensive (loss)/profit
for the year (26,569) 52,421
------------------------------------------------------------ ----- ------------- -------------
Attributable to:
- Non-controlling interest (87) 946
- Shareholders of Urals Energy Public
Company Limited (26,482) 51,475
------------------------------------------------------------ ----- ------------- -------------
Urals Energy Public Company Limited
Consolidated Statements of Cash Flows
(presented in US$ thousands)
Year ended 31 December
-------------------------
Note 2011 2010
-------------------------------------------- ----- ----------- ------------
Cash flows from operating activities
(Loss)/profit before income tax (23,081) 62,795
Adjustments for:
Depreciation, amortization and depletion 6,987 4,544
Share-based payments 457 2,012
Interest income (3,913) (4,395)
Interest expense 1,697 1,248
Release of provision on inventory 9 (151) (892)
Change in provision on claims 13 (360) 360
Impairment release 7 - (70,476)
Loss from disposal of the Taas loans 4 16,470 -
Gain on disposal of property, plant
and equipment (1,230) (1,151)
Change in fair value of warrants - 22
Charge of provision for doubtful
accounts receivable 706 5,250
Foreign currency loss, net 2,154 1,438
Other non-cash transactions 2,246 3,594
Operating cash flows before changes
in working capital 1,982 4,349
Decrease in inventories 3,249 5,213
Increase in accounts receivables
and prepayments (7,188) (5,780)
Decrease in accounts payable and
accrued expenses (4,087) (6,849)
(Decrease)/increase in advances
from customers (2,463) 2,185
Increase in other taxes payable 345 2,791
-------------------------------------------- ----- ----------- ------------
Cash (used in)/generated from operations (8,162) 1,909
Interest received 62 -
Interest paid (140) -
Income tax paid (201) (61)
-------------------------------------------- ----- ----------- ------------
Net cash (used in)/generated from
operating activities (8,441) 1,848
Cash flows from investing activities
Purchase of property, plant and
equipment and intangible assets (2,780) (1,608)
Disposal of the Taas loans 4 21,600 -
Proceeds on loans issued 62 -
Proceeds from sale of property,
plant and equipment 1,886 1,770
-------------------------------------------- ----- ----------- ------------
Net cash generated from investing
activities 20,768 162
Cash flows from financing activities
Repayment of borrowings (14,000) (3,000)
Finance lease principal payments (289) (392)
Cash proceeds from issuance of ordinary 8,750 -
shares, net
Net cash used in financing activities (5,539) (3,392)
Effect of exchange rate changes
on cash in bank and on hand (53) 8
-------------------------------------------- ----- ----------- ------------
Net increase/(decrease) in cash
in bank and on hand 6,735 (1,374)
Cash in bank and on hand at the
beginning of the year 987 2,361
-------------------------------------------- ----- ----------- ------------
Cash in bank and on hand at the
end of the year 7,722 987
-------------------------------------------- ----- ----------- ------------
Urals Energy Public Company Limited
Consolidated Statements of Changes in Shareholders's Equity
(presented in US$ thousands)
Equity
attributable
to
Difference Shareholders
from of Urals
conversion Energy
of share Cumulative Public
Share Share capital Translation Accumulated Company Non-controlling Total
Note capital premium into US$ Adjustment deficit Limited interest equity
Balance at 31 December
2009 1,131 644,248 (113) (28,373) (554,976) 61,917 24 61,941
----------------------- -------- --------- ----------- ------------ ------------ ------------- ---------------- ---------
Effect of currency
translation - - - (485) - (485) (3) (488)
Profit for the year - - - - 51,960 51,960 949 52,909
-------- --------- ----------- ------------ ------------ ------------- ---------------- ---------
Total comprehensive
income - - - (485) 51,960 51,475 946 52,421
Issuance of shares 71 1,929 - - - 2,000 - 2,000
Share-based payment - 2,012 - - - 2,012 - 2,012
Private placement 341 8,840 - - - 9,181 - 9,181
Expenses related to
private placement - (472) - - - (472) - (472)
Balance at 31 December
2010 1,543 656,557 (113) (28,858) (503,016) 126,113 970 127,083
----------------------- -------- --------- ----------- ------------ ------------ ------------- ---------------- ---------
Effect of currency
translation - - - (1,814) - (1,814) (48) (1,862)
Loss for the year - - - (24,668) (24,668) (39) (24,707)
-------- --------- ----------- ------------ ------------ ------------- ---------------- ---------
Total comprehensive
loss - - - (1,814) (24,668) (26,482) (87) (26,569)
Issuance of shares 26 (26) - - - - - -
Share-based payment - 457 - - - 457 - 457
Balance at 31 December
2011 1,569 656,988 (113) (30,672) (527,684) 100,088 883 100,971
----------------------- -------- --------- ----------- ------------ ------------ ------------- ---------------- ---------
Urals Energy Public Company Limited
Notes to the Consolidated Financial Statements
(presented in US$ thousands)
1 Activities
Urals Energy Public Company Limited ("Urals Energy" or the "Company" or "UEPCL") was incorporated as a limited liability company in Cyprus on 10 November 2003. Urals Energy and its subsidiaries (the "Group") are primarily engaged in oil and gas exploration and production in the Russian Federation and processing of crude oil for distribution on both the Russian and international markets.
The registered office of Urals Energy is at 31 Evagorou Avenue, Suite 34, CY-1066, Nicosia, Cyprus. UEPCL's shares are traded on the AIM Market operated by the London Stock Exchange.
The Group comprises UEPCL and the following main subsidiaries:
Effective ownership interest
at 31 December
---------------------------------------------------------------- ----------------- -------------------------------
Entity Jurisdiction 2011 2010
---------------------------------------------------------------- ----------------- --------------- --------------
Exploration and production
ZAO Petrosakh ("Petrosakh") Sakhalin 97.2% 97.2%
ZAO Arcticneft ("Arcticneft") Nenetsky Region 100% 100%
Management company
OOO Urals Energy Moscow 100% 100%
Urals Energy (UK) Limited (dormant starting from May 2007) (1) United Kingdom - 100%
(1) As at 5 January 2011 Urals Energy (UK) Limited is considered a liquidated entity.
2 Summary of Significant Accounting Policies
Basis of preparation. The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU) under the historical cost convention as modified by the change in fair value of financial instruments.
The preparation of consolidated financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the reporting date and the reported amounts of revenues and expenses during the reporting period. These policies have been consistently applied to all the periods presented, unless otherwise stated. Critical accounting estimates and judgments are disclosed in Note 6. Actual results could differ from the estimates.
Functional and presentation currency. The United States dollar ("US dollar or US$ or $") is the presentation currency for the Group's operations as management have used the US dollar accounts to manage the Group's financial risks and exposures, and to measure its performance. Financial statements of the Russian subsidiaries are measured in Russian Roubles, their functional currency.
The functional currency of the Company is the US Dollar as substantially all the cash flows affecting the Company are in US Dollars.
Translation to functional currency.Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the rate of exchange ruling at the reporting date. Any resulting exchange differences are included in the profit or loss component of the consolidated statement of comprehensive income. Non-monetary assets and liabilities that are measured at historical cost and denominated in a foreign currency are translated into the functional currency using the rates of exchange as at the dates of the initial transactions. The US dollar to Russian Rouble exchange rates were 32.20 and 30.48 as of 31 December 2011 and 2010, respectively.
Translation to presentation currency. The Group's consolidated financial statements are presented in US dollars in accordance with IAS 21, The Effects of Changes in Foreign Exchange Rates. The results and financial position of each group entity having a functional currency different from the presentation currency are translated into the presentation currency as follows:
(i) Assets and liabilities for each statement of financial position presented are translated at the closing rate at the date of that statement of financial position. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the rate of exchange ruling at the reporting date. Any resulting exchange differences are included in the profit or loss component of the consolidated statement of comprehensive income. Non-monetary assets and liabilities that are measured at historical cost and denominated in a foreign currency are translated into the functional currency the Company using the rates of exchange as at the dates of the initial transactions. Goodwill and fair value adjustments arising on the acquisitions are treated as assets and liabilities of the acquired entity.
(ii) Income and expenses for each statement of comprehensive income are translated to the functional currency of the Company at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions).
(iii) All resulting exchange differences are recognised as a separate component of equity.
When a subsidiary is disposed of through sale, liquidation, repayment of share capital or abandonment of all, or part of, that entity, the exchange differences deferred in other comprehensive income are reclassified to the profit and loss.
Comparatives. Where necessary, comparative figures have been adjusted to conform with changes in presentation in the current year.
Consolidated financial statements. Subsidiaries are those companies and other entities (including special purpose entities) in which the Group, directly or indirectly, has an interest of more than one half of the voting rights or otherwise has power to govern the financial and operating policies so as to obtain benefits. The existence and effect of potential voting rights that are presently exercisable or presently convertible are considered when assessing whether the Group controls another entity. Subsidiaries are consolidated from the date on which control is transferred to the Group (acquisition date) and are deconsolidated from the date on which control ceases.
The purchase method of accounting is used to account for the acquisition of subsidiaries. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date, irrespective of the extent of any non-controlling interest.
The Group measures non-controlling interest that represents present ownership interest and entitles the holder to a proportionate share of net assets in the event of liquidation on a transaction by transaction basis, either at: (a) fair value, or (b) the non-controlling interest's proportionate share of net assets of the acquiree. Non-controlling interests that are not present ownership interests are measured at fair value.
Goodwill is measured by deducting the net assets of the acquiree from the aggregate of the consideration transferred for the acquiree, the amount of non-controlling interest in the acquiree and fair value of an interest in the acquiree held immediately before the acquisition date. Any negative amount ("negative goodwill") is recognised in profit or loss, after management reassesses whether it identified all the assets acquired and all liabilities and contingent liabilities assumed and reviews appropriateness of their measurement.
The consideration transferred for the acquiree is measured at the fair value of the assets given up, equity instruments issued and liabilities incurred or assumed, including fair value of assets or liabilities from contingent consideration arrangements but excludes acquisition related costs such as advisory, legal, valuation and similar professional services. Transaction costs related to the acquisition and incurred for issuing equity instruments are deducted from equity; transaction costs incurred for issuing debt as part of the business combination are deducted from the carrying amount of the debt and all other transaction costs associated with the acquisition are expensed.
Intercompany transactions, balances and unrealised gains on transactions between group companies are eliminated; unrealised losses are also eliminated unless the cost cannot be recovered. The Company and all of its subsidiaries use uniform accounting policies consistent with the Group's policies.
Non-controlling interest is that part of the net results and of the equity of a subsidiary attributable to interests which are not owned, directly or indirectly, by the Company. Non-controlling interest forms a separate component of the Group's equity.
Purchases and sales of non-controlling interests. The Group applies the economic entity model to account for transactions with owners of non-controlling interest. Any difference between the purchase consideration and the carrying amount of non-controlling interest acquired is recorded as a capital transaction directly in equity. The Group recognises the difference between sales consideration and carrying amount of non-controlling interest sold as a capital transaction in the consolidated statement of changes in equity.
Property, plant and equipment. Property, plant and equipment acquired as part of a business combination is recorded at fair value at the acquisition date and adjusted for accumulated depreciation, depletion and impairment. All subsequent additions are recorded at historical cost of acquisition or construction and adjusted for accumulated depreciation, depletion and impairment. Oil and gas exploration and production activities are accounted for in a manner similar to the successful efforts method. Costs of successful development and exploratory wells are capitalised. The cost of property, plant and equipment includes provisions for dismantlement, abandonment and site restoration (see Provisions below).
The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources. Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are initially capitalised as an intangible asset within oil and gas properties until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. If hydrocarbons are not found, the exploration expenditure is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, which may include the drilling of further wells (exploration or exploratory-type stratigraphic test wells), are likely to be capable of commercial development, the costs continue to be carried as an asset. All such carried costs are subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to the tangible part of oil and gas properties and an impairment review of the property is undertaken at that time.
Development and production assets are accumulated generally on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them to production together with Exploration and Evaluation (E&E) expenditures incurred in finding commercial reserves and transferred from the intangible E&E assets described above. The cost of development and production assets also include the costs of acquisitions and purchases of such assets, directly attributable overheads, finance costs capitalised and the costs of recognising provisions for future restoration and decommissioning.
Depletion of capitalized costs of proved oil and gas properties is calculated using the unit-of-production method for each field based upon proved reserves for property acquisitions and proved developed reserves for exploration and development costs. Oil and gas reserves for this purpose are determined in accordance withSociety of Petroleum Engineers definitions and were last estimated by DeGolyer and MacNaughton, the Group's independent reservoir engineers in 2007. The DeGolyer and MacNaughton information from the 2007 reserves review is updated annually by management by reference to production information and the equivalent Russian ABC reserves classification. Gains or losses from retirements or sales of oil and gas properties are included in the determination of profit for the year.
Depreciation of non oil and gas property, plant and equipment is calculated using the straight-line method over their estimated remaining useful lives, as follows:
Estimated useful life
-------------------------------- ----------------------
Refinery and related equipment 19
Buildings 20
Other assets 6 to 20
-------------------------------- ----------------------
The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. Gains and losses on disposals are determined by comparing the proceeds with the carrying amount and are recognised within 'Other operating loss' in the profit and loss section of consolidated statement of comprehensive income.
Intangible assets. The Group measures intangible assets at cost less accumulated amortisation and impairment losses. All of the Group's other intangible assets have finite useful lives and primarily include capitalised computer software and licences.
Acquired computer software licences are capitalised on the basis of the costs incurred to acquire and bring them to use.
Development costs that are directly associated with identifiable and unique software controlled by the Group are recorded as intangible assets if probable future economic benefits will be generated. Capitalised costs include staff costs of the software development team and an appropriate portion of relevant overheads. All other costs associated with computer software, e.g. its maintenance, are expensed when incurred.
Intangible assets are amortised using the straight-line method over their useful lives:
Estimated useful
life
------------------------------------------- -----------------
Software licences 1-5
Capitalised internal software development
costs 3
Other licences 5 to 7
------------------------------------------- -----------------
Provisions. Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events and when it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made.
Provisions, including those related to dismantlement, abandonment and site restoration, are evaluated and re-estimated annually, and are included in the consolidated financial statements at each reporting date at the present value of the expenditures expected to be required to settle the obligation using pre - tax discount rates which reflect the current market assessment of the time value of money and the risks specific to the liability.
Changes in provisions resulting from the passage of time are reflected in the profit and loss section of consolidated statement of comprehensive income each year under financial items. Other changes in provisions, relating to a change in the expected pattern of settlement of the obligation, changes in the discount rate or in the estimated amount of the obligation, are treated as a change in accounting estimate in the period of the change. Changes in provisions relating to dismantlement, abandonment and site restoration are added to, or deducted from, the cost of the related asset in the current period. The amount deducted from the cost of the asset should not exceed its carrying amount. If a decrease in the liability exceeds the carrying amount of the asset, the excess is recognised immediately in profit or loss.
The provision for dismantlement liability is recorded on the consolidated statement of financial position, with a corresponding amount being recorded as part of property, plant and equipment in accordance with IAS 16.
Leases. Leases of property, plant and equipment where the Group has substantially all the risks and rewards of ownership are classified as finance leases. Finance leases are capitalised at the commencement of the lease at the lower of the fair value of the leased property or the present value of the minimum lease payments. The corresponding rental obligations, net of finance charges, are presented as finance lease obligations on the consolidated statement of financial position. The interest element of the finance cost is charged to the consolidated statement of comprehensive income over the lease period. Property, plant and equipment acquired under finance leases are depreciated over the shorter of the useful life of the asset or the lease term.
Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases are charged to the consolidated statement of comprehensive income on a straight-line basis over the period of the lease.
Impairment of assets. Assets that are subject to depreciation and depletion are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell or value in use. For the purposes of assessing impairment, assets are grouped by license areas, which are the lowest levels for which there are separately identifiable cash flows (cash-generating units).
Reversal of impairment. Non-financial assets other than goodwill that suffered an impairment are reviewed for possible reversal of impairment at each reporting date.
Inventories. Inventories of extracted crude oil, oil products, materials and supplies and construction materials are valued at the lower of the weighted-average cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business, less the estimated cost of completion and selling expenses. General and administrative expenditure is excluded from inventory costs and expensed in the period incurred.
Trade receivables. Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, net of provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of receivables. Such objective evidence may include significant financial difficulties of the debtor, an increase in the probability that the debtor will enter bankruptcy or financial reorganization, and actual default or delinquency in payments. The amount of the provision is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate. The change in the amount of the provision is recognised in the profit and loss section of consolidated statement of comprehensive income.
Cash and cash equivalents. Cash and cash equivalents includes cash in hand, deposits held at call with banks, and other short-term highly liquid investments with original maturities of three months or less. Cash and cash equivalents are carried at amortised cost using the effective interest method. Restricted balances are excluded from cash and cash equivalents for the purposes of the consolidated statement of cash flow. Balances restricted from being exchanged or used to settle a liability for at least twelve months after the reporting date are included in other non-current assets. Restricted cash balances are segregated from cash available for the business to use until such time as restrictions are removed.
Value added tax. Output value added tax related to sales is payable to tax authorities on the earlier of (a) collection of receivables from customers or (b) delivery of goods or services to customers. Input VAT is generally recoverable against output VAT upon receipt of the VAT invoice. The tax authorities permit the settlement of VAT on a net basis. VAT related to sales and purchases is recognised in the consolidated statement of financial position on a gross basis and disclosed separately as an asset and liability. Where provision has been made for impairment of receivables, impairment loss is recorded for the gross amount of the debtor, including VAT.
Borrowings. Borrowings are recognised initially at the fair value of the liability, net of transaction costs incurred. In subsequent periods, borrowings are stated at amortised cost using the effective interest method; any difference between amount at initial recognition and the redemption amount is recognised as interest expense over the period of the borrowings. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the reporting date.
Capitalisation of borrowing costs. Borrowing costs directly attributable to the acquisition, construction or production of assets that necessarily take a substantial time to get ready for intended use or sale (qualifying assets) are capitalised as part of the costs of those assets.
The commencement date for capitalisation is when (a) the Group incurs expenditures for the qualifying asset; (b) it incurs borrowing costs; and (c) it undertakes activities that are necessary to prepare the asset for its intended use or sale.
Capitalisation of borrowing costs continues up to the date when the assets are substantially ready for their use or sale.
The Group capitalises borrowing costs that could have been avoided if it had not made capital expenditure on qualifying assets. Borrowing costs capitalised are calculated at the group's average funding cost (the weighted average interest cost is applied to the expenditures on the qualifying assets), except to the extent that funds are borrowed specifically for the purpose of obtaining a qualifying asset. Where this occurs, actual borrowing costs incurred less any investment income on the temporary investment of those borrowings are capitalised.
Loans receivable. The loans advanced by the Group are classified as "loans and receivables" in accordance with IAS 39 and stated at amortised cost using the effective interest method. These loans are individually tested for impairment at each reporting date.
Income taxes. Income taxes have been provided for in the consolidated financial statements in accordance with legislation enacted or substantively enacted by the end of the reporting period. The income tax charge or benefit comprises current tax and deferred tax and is recognised in profit or loss for the year except if it is recognised in other comprehensive income or directly in equity because it relates to transactions that are also recognised, in the same or a different period, in other comprehensive income or directly in equity.
Current tax is the amount expected to be paid to or recovered from the taxation authorities in respect of taxable profits or losses for the current and prior periods. Taxes other than on income are recorded within operating expenses.
Deferred income tax is provided using the balance sheet liability method for tax loss carry forwards and temporary differences arising between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. In accordance with the initial recognition exemption, deferred taxes are not recorded for temporary differences on initial recognition of an asset or a liability in a transaction other than a business combination if the transaction, when initially recorded, affects neither accounting nor taxable profit. Deferred tax balances are measured at tax rates enacted or substantively enacted at the end of the reporting period, which are expected to apply to the period when the temporary differences will reverse or the tax loss carry forwards will be utilised. Deferred tax assets and liabilities are netted only within the individual companies of the Group. Deferred tax assets for deductible temporary differences and tax loss carry forwards are recorded only to the extent that it is probable that future taxable profit will be available against which the deductions can be utilised.
Uncertain tax positions.The Group's uncertain tax positions are reassessed by management at the end of each reporting period. Liabilities are recorded for income tax positions that are determined by management as more likely than not to result in additional taxes being levied if the positions were to be challenged by the tax authorities. The assessment is based on the interpretation of tax laws that have been enacted or substantively enacted by the end of the reporting period, and any known court or other rulings on such issues. Liabilities for penalties, interest and taxes other than on income are recognised based on management's best estimate of the expenditure required to settle the obligations at the end of the reporting period.
Employee benefits. Wages, salaries, contributions to the Russian Federation state pension and social insurance funds, paid annual leave and sick leave, bonuses, and non-monetary benefits (such as health services and kindergarten services) are accrued in the year in which the associated services are rendered by the employees of the Group. The Group has no legal or constructive obligation to make pension or similar benefit payments beyond the payments to the statutory defined contribution scheme.
Social costs. The Group incurs employee costs related to the provision of benefits such as health insurance. These amounts principally represent an implicit cost of employing production workers and, accordingly, are included in the cost of inventory.
Prepayments. Prepayments are carried at cost less provision for impairment. A prepayment is classified as non-current when the goods or services relating to the prepayment are expected to be obtained after one year, or when the prepayment relates to an asset which will itself be classified as non-current upon initial recognition. Prepayments to acquire assets are transferred to the carrying amount of the asset once the Group has obtained control of the asset and it is probable that future economic benefits associated with the asset will flow to the Group. Other prepayments are written off to profit or loss when the goods or services relating to the prepayments are received. If there is an indication that the assets, goods or services relating to a prepayment will not be received, the carrying value of the prepayment is written down accordingly and a corresponding impairment loss is recognised in profit or loss.
Revenue recognition. The Group recognises revenue when the amount of revenue can be reliably measured and it is probable that economic benefits will flow to the entity, typically when crude oil or refined products are dispatched to customers and title has transferred.
Interest income is recognised on a time-proportion basis using the effective interest method. When a receivable is impaired, the Group reduces the carrying amount to its recoverable amount, being the estimated future cash flow discounted at the original effective interest rate of the instrument, and continues unwinding the discount as interest income. Interest income on impaired loans is recognised using the original effective interest rate.
Segments. The Group operates in one business segment which is crude oil exploration and production. The Group assesses its results of operations and makes its strategic and investment decisions based on the analysis of its profitability as a whole. The Group operates within geographic segments as disclosed in note 14.
Warrants. Warrants issued that allow the holder to purchase shares of the Group's stock are recorded at fair value at issuance and recorded as liabilities unless the number of equity instruments to be issued to settle the warrants and the exercise price are fixed in the issuing entities' functional currency at the time of grant, in which case they are recorded within shareholders' equity. Changes in the fair value of warrants recorded as liabilities are recorded in the consolidated statement of comprehensive income.
Financial derivatives. The fair value of options is evaluated using market prices at the grant date if available, taking into account the terms and conditions of the options, upon which those derivative instruments were issued. If market prices are not available, the fair value of the derivative equity instruments granted is estimated using a valuation technique to estimate what the price of those equity instruments would have been on the measurement date in an arm's length transaction between knowledgeable, willing parties.
Share capital. Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares are shown in equity as a deduction, net of tax, from the proceeds. Any excess of the fair value of consideration received over the par value of shares issued is presented in the notes as a share premium.
Share-based payments. The fair value of the employee services received in exchange for the grant of options is recognised as an expense. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted, using market prices, taking into account the terms and vesting conditions upon which those equity instruments were granted.
Earnings per share. Earnings per share are determined by dividing the profit or loss attributable to equity holders of the Group by the weighted average number of participating shares outstanding during the reporting year.
Initial recognition of related party transactions. In the normal course of business the Group enters into transactions with its related parties. IAS 39 requires initial recognition of financial instruments based on their fair values. Judgement is applied in determining if transactions are priced at market or non-market interest rates, where there is no active market for such transactions. The basis for judgement is pricing for similar types of transactions with unrelated parties and effective interest rate analyses.
3 Going Concern
A significant portion of the Group's consolidated net assets of $100.1 million (31 December 2010: $127.1 million) comprises undeveloped mineral deposits requiring significant additional investment. The Group is dependent upon external debt to fully develop the deposits and realise the value attributed to such assets.
The Group had net current liabilities of $3.7 million as of 31 December 2011 (31 December 2010: $11.2 million). The most significant creditor as of 31 December 2011 was $10.0 million loan from Petraco (31 December 2010: $30.7 million). Following the settlement of the Taas loans (Note 4) the Group liquidity has improved significantly.
Management have prepared monthly cash flow projections for periods throughout 2012 and 2013. Judgements which are significant to management's conclusion that no material uncertainty exists for going concern this year include future oil prices and planned production which were required for the preparation of the cash flow projections and model. Positive overall cash flows are dependant on future oil prices (a price of $90 per barrel has been used for 2012 and for 2013). Despite the above matters, the Group still has funding and liquidity constraints, though these are less severe than in the prior year. Despite the uncertainties and based on cash flow projections performed, management considers that the application of the going concern assumption for the preparation of these consolidated financial statements is appropriate.
4 Disposal of Taas loans
The Taas-Yuryakh Neftegazodobycha loans (the "Taas loans") represented US dollar denominated long-term loans (interest inclusive) of $37.8 million at 31 December 2010 issued by UEPCL to Taas, as part of the Taas acquisition agreement. The loans were used to pay organisation fees for a $600.0 million project finance loan facility provided by Savings Bank of Russian Federation ("Sberbank") for the development of the SRB field, financing of interest payments and repayment of third party loans at Taas. The loans bear interest of 12% and mature in February 2015. These loans were considered to be fully performing as of 31 December 2010. The loans were unsecured.
At 8 December 2011 under the terms of an assignment agreement, the Company has assigned the full benefit of the Taas loans (together with all accrued interest) to Nagelfar for the total sum of $26 million. The book value of the Taas loans as at 8 December 2011 was $41 million (including the accrual of relevant interest) and transaction costs amounted $1.5 million. A loss of $16.5 million was recorded as a result of this transaction in the profit and loss section of the consolidated statement of comprehensive income. In December 2011 a payment of $21.6 million net of the non-cash settlement the payable to Finfund Limited of $4.4 million (Note 12) was received.
5 Adoption of New or Revised standards and interpretations and New accounting pronouncements
The following new standards and interpretations became effective for the Group from 1 January 2011:
Amendment to IAS 24, Related Party Disclosures (issued in November 2009 and effective for annual periods beginning on or after 1 January 2011). IAS 24 was revised in 2009 by: (a) simplifying the definition of a related party, clarifying its intended meaning and eliminating inconsistencies; and by (b) providing a partial exemption from the disclosure requirements for government-related entities. As a result of the revised standard, the Group now also discloses contractual commitments to purchase and sell goods or services to its related parties.
Improvements to International Financial Reporting Standards (issued in May 2010 and effective from 1 January 2011).The improvements consist of a mixture of substantive changes and clarifications in the following standards and interpretations: IFRS 1 was amended (i) to allow previous GAAP carrying value to be used as deemed cost of an item of property, plant and equipment or an intangible asset if that item was used in operations subject to rate regulation, (ii) to allow an event driven revaluation to be used as deemed cost of property, plant and equipment even if the revaluation occurs during a period covered by the first IFRS financial statements and (iii) to require a first-time adopter to explain changes in accounting policies or in the IFRS 1 exemptions between its first IFRS interim report and its first IFRS financial statements; IFRS 3 was amended (i) to require measurement at fair value (unless another measurement basis is required by other IFRS standards) of non-controlling interests that are not present ownership interest or do not entitle the holder to a proportionate share of net assets in the event of liquidation, (ii) to provide guidance on the acquiree's share-based payment arrangements that were not replaced, or were voluntarily replaced as a result of a business combination and (iii) to clarify that the contingent considerations from business combinations that occurred before the effective date of revised IFRS 3 (issued in January 2008) will be accounted for in accordance with the guidance in the previous version of IFRS 3; IFRS 7 was amended to clarify certain disclosure requirements, in particular (i) by adding an explicit emphasis on the interaction between qualitative and quantitative disclosures about the nature and extent of financial risks, (ii) by removing the requirement to disclose carrying amount of renegotiated financial assets that would otherwise be past due or impaired, (iii) by replacing the requirement to disclose fair value of collateral by a more general requirement to disclose its financial effect, and (iv) by clarifying that an entity should disclose the amount of foreclosed collateral held at the reporting date, and not the amount obtained during the reporting period; IAS 1 was amended to clarify the requirements for the presentation and content of the statement of changes in equity; IAS 27 was amended by clarifying the transition rules for amendments to IAS 21, 28 and 31 made by the revised IAS 27 (as amended in January 2008); IAS 34 was amended to add additional examples of significant events and transactions requiring disclosure in a condensed interim financial report, including transfers between the levels of fair value hierarchy, changes in classification of financial assets or changes in business or economic environment that affect the fair values of the entity's financial instruments; and IFRIC 13 was amended to clarify measurement of fair value of award credits. The above amendments resulted in additional or revised disclosures, but had no material impact on measurement or recognition of transactions and balances reported in these financial statements. The financial effect of collateral required to be disclosed by the amendments to IFRS 7 is presented in these financial statements by disclosing collateral values separately for (i) those financial assets where collateral and other credit enhancements are equal to, or exceed, carrying value of the asset ("over-collateralised assets") and (ii) those financial assets where collateral and other credit enhancements are less than the carrying value of the asset ("under-collateralised assets").
Other revised standards and interpretations effective for the current period.IFRIC 19 "Extinguishing financial liabilities with equity instruments", amendments to IAS 32 on classification of rights issues, clarifications in IFRIC 14 "IAS 19 - The limit on a defined benefit asset, minimum funding requirements and their interaction" relating to prepayments of minimum funding requirements and amendments to IFRS 1 "First-time adoption of IFRS", did not have any impact on these consolidated financial statements.
Since the Group has published its last annual consolidated financial statements, certain new standards and interpretations have been issued that are mandatory for the Group's annual accounting periods beginning on or after 1 January 2012 or later and which the Group has not early adopted:
IFRS 9 was issued in November 2009 and replaces those parts of IAS 39 relating to the classification and measurement of financial assets. Key features are as follows:
- Financial assets are required to be classified into two measurement categories: those to be measured subsequently at fair value, and those to be measured subsequently at amortised cost. The decision is to be made at initial recognition. The classification depends on the entity's business model for managing its financial instruments and the contractual cash flow characteristics of the instrument.;
- An instrument is subsequently measured at amortised cost only if it is a debt instrument and both (i) the objective of the entity's business model is to hold the asset to collect the contractual cash flows, and (ii) the asset's contractual cash flows represent only payments of principal and interest (that is, it has only "basic loan features"). All other debt instruments are to be measured at fair value through profit or loss.;
- All equity instruments are to be measured subsequently at fair value. Equity instruments that are held for trading will be measured at fair value through profit or loss. For all other equity investments, an irrevocable election can be made at initial recognition, to recognise unrealised and realised fair value gains and losses through other comprehensive income rather than profit or loss. There is to be no recycling of fair value gains and losses to profit or loss. This election may be made on an instrument-by-instrument basis. Dividends are to be presented in profit or loss, as long as they represent a return on investment.; and
- Most of the requirements in IAS 39 for classification and measurement of financial liabilities were carried forward unchanged to IFRS 9. The key change is that an entity will be required to present the effects of changes in own credit risk of financial liabilities designated as at fair value through profit or loss in other comprehensive income.
While adoption of IFRS 9 is mandatory from 1 January 2015, earlier adoption is permitted. The Group is considering the implications of the standard, the impact on the Group and the timing of its adoption by the Group.
IFRS 10, Consolidated Financial Statements (issued in May 2011 and effective for annual periods beginning on or after 1 January 2013), replaces all of the guidance on control and consolidation in IAS 27 "Consolidated and separate financial statements" and SIC-12 "Consolidation - special purpose entities". IFRS 10 changes the definition of control so that the same criteria are applied to all entities to determine control. This definition is supported by extensive application guidance. The Group is currently assessing the impact of the new standard on its consolidated financial statements.
IFRS 11, Joint Arrangements. IFRS 11 was issued in May 2011 and supersedes IAS31 Interests in Joint Ventures, and SIC-13 Jointly Controlled Entities - Non-Monetary Contributions by Venturers.
- IFRS 11 classifies joint arrangements as either joint operations (combining the existing concept of jointly controlled operations) or joint ventures (equivalent of existing concept of a jointly controlled entity).
- IFRS 11 requires the use of equity method of accounting for interests in joint ventures thereby eliminating the proportionate consolidation method.
The effective date of IFRS 11 is 1 January 2013, with earlier application permitted under certain circumstances.The Group is currently assessing the impact of the new standard on its consolidated financial statements.
IFRS 12, Disclosure of Interests in Other Entities. IFRS 12 was issued in May 2011. The standard requires extensive disclosures relating to an entity's interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities. An entity is required to disclose information that helps users of its financial statements evaluate the nature of and risks associated with its interests in other entities and effects of those interests on its consolidated financial statements.
The effective date of IFRS 11 is 1 January 2013, entities are permitted to incorporate any of the new disclosures into their financial statements before that date. The Group is currently assessing the impact of the new standard on its consolidated financial statements.
IFRS 13, Fair value measurement, (issued in May 2011 and effective for annual periods beginning on or after 1 January 2013), aims to improve consistency and reduce complexity by providing a revised definition of fair value, and a single sourceof fair value measurement and disclosure requirements for use across IFRSs. The Group is currently assessing the impact of the amended standard on disclosures in its consolidated financial statements.
(issued on 12 May 2011, applicable to annual reporting periods, beginning on or after 1 January 2013). IAS 27 applies when an entity prepares separate financial statements that comply with IFRS. The amendment is not expected to have any material impact on the Group's consolidated financial statements.
Investments in Associates and Joint ventures - Amendment to IAS 28(issued on 12 May 2011, applicable to annual reporting periods, beginning on or after 1 January 2013). The standard prescribes accounting for investments in associates and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures. The amendment is not expected to have any material impact on the Group's consolidated financial statements.
Disclosures - Transfers of Financial Assets - Amendments to IFRS 7 (issued in October 2010 and effective for annual periods beginning on or after 1 July 2011). The amendment requires additional disclosures in respect of risk exposures arising from transferred financial assets. The amendment includes a requirement to disclose by class of asset the nature, carrying amount and a description of the risks and rewards of financial assets that have been transferred to another party yet remain on the entity's balance sheet. Disclosures are also required to enable a user to understand the amount of any associated liabilities, and the relationship between the financial assets and associated liabilities. Where financial assets have been derecognised but the entity is still exposed to certain risks and rewards associated with the transferred asset, additional disclosure is required to enable the effects of those risks to be understood. The Group is currently assessing the impact of the amended standard on disclosures in its consolidated financial statements.
Presentation of Financial Statements - Amendments to IAS 1(issued June 2011, effective for annual periods beginning on or after 1 July 2012), changes the disclosure of items presented in other comprehensive income. The amendments require entities to separate items presented in other comprehensive income into two groups, based on whether or not they may be reclassified to profit or loss in the future. The suggested title used by IAS 1 has changed to 'statement of profit or loss and other comprehensive income'. The Group expects the amended standard to change presentation of its financial statements, but have no impact on measurement of transactions and balances.
Employee Benefits - Amended IAS 19 (issued in June 2011, effective for periods beginning on or after 1 January 2013), makes significant changes to the recognition and measurement of defined benefit pension expense and termination benefits, and to the disclosures for all employee benefits. The standard requires recognition of all changes in the net defined benefit liability (asset) when they occur, as follows: (i) service cost and net interest in profit or loss; and (ii) remeasurements in other comprehensive income. The Group is currently assessing the impact of the amended standard on its consolidated financial statements.
Disclosures-Offsetting Financial Assets and Financial Liabilities - Amendments to IFRS 7 (issued in December 2011 and effective for annual periods beginning on or after 1 January 2013). The amendment requires disclosures that will enable users of an entity's financial statements to evaluate the effect or potential effect of netting arrangements, including rights of set-off. The amendment will have an impact on disclosures but will have no effect on measurement and recognition of financial instruments.
Offsetting Financial Assets and Financial Liabilities - Amendments to IAS 32(issued in December 2011 and effective for annual periods beginning on or after 1 January 2014). The amendment added application guidance to IAS 32 to address inconsistencies identified in applying some of the offsetting criteria. This includes clarifying the meaning of 'currently has a legally enforceable right of set-off' and that some gross settlement systems may be considered equivalent to net settlement. The Group is considering the implications of the amendment, the impact on the Group and the timing of its adoption by the Group.
Other revised standards and interpretations: The amendments to IFRS 1 "First-time adoption of IFRS", relating to severe hyperinflation and eliminating references to fixed dates for certain exceptions and exemptions, the amendment to IAS 12 "Income taxes", which introduces a rebuttable presumption that an investment property carried at fair value is recovered entirely through sale, and IFRIC 20, "Stripping Costs in the Production Phase of a Surface Mine", which considers when and how to account for the benefits arising from the stripping activity in mining industry, will not have any impact on these consolidated financial statements.
Unless otherwise described above, the new standards and interpretations are not expected to affect significantly the Group's consolidated financial statements.
6 Critical Accounting Estimates and Judgements in Applying Accounting Policies
The Group makes estimates and assumptions that affect the amounts recognised in the consolidated financial statements and the carrying amounts of assets and liabilities within the next financial year. Estimates and judgements are continually evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Management also makes certain judgements, apart from those involving estimations, in the process of applying the accounting policies. Judgements that have the most significant effect on the amounts recognised in the consolidated financial statements and estimates that can cause a significant adjustment to the carrying amount of assets and liabilities within the next financial year include:
Tax legislation. Russian tax and customs legislation is subject to varying interpretations, and changes, which can occur frequently. Management's interpretation of such legislation as applied to the transactions and activity of the Group may be challenged by the relevant authorities.
Initial recognition of related party transactions. In the normal course of business the Company enters into transactions involving various financial instruments with its related parties. IAS 39, Financial Instruments: recognition and measurement, requires initial recognition of financial instruments based on their fair values. Judgement was applied in determining if transactions are priced at market or nonmarket interest rates, where there is no active market for such transactions.This judgement was based on the pricing for similar types of transactions with unrelated parties and effective interest rate analyses.
Estimation of oil and gas reserves. Engineering estimates of hydrocarbon reserves are inherently uncertain and are subject to future revisions. Accounting measures such as depreciation, depletion and amortization charges, impairment assessments and asset retirement obligations that are based on the estimates of proved reserves are subject to change based on future changes to estimates of oil and gas reserves.
Proved reserves are defined as the estimated quantities of hydrocarbons which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions. Proved reserves are estimated by reference to available reservoir and well information, including production and pressure trends for producing reservoirs. Furthermore, estimates of proved reserves only include volumes for which access to market is assured with reasonable certainty. All proved reserves estimates are subject to revision, either upward or downward, based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans. In some cases, substantial new investment in additional wells and related support facilities and equipment will be required to recover such proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change over time as additional information becomes available.
The Group last obtained an independent reserve engineers report as at 31 December 2007. Management believes that these reserves have not changed, other than through production, as the amount of subsequent additional drilling has been minimal.
In general, estimates of reserves for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and depleted. As those fields are further developed, new information may lead to further revisions in reserve estimates. Reserves have a direct impact on certain amounts reported in the consolidated financial statements, most notably depreciation, depletion and amortization as well as impairment expenses. Depreciation rates on production assets using the units-of-production method for each field are based on proved developed reserves for development costs, and total proved reserves for costs associated with the acquisition of proved properties. Assuming all variables are held constant, an increase in proved developed reserves for each field decreases depreciation, depletion and amortization expenses. Conversely, a decrease in the estimated proved developed reserves increases depreciation, depletion and amortization expenses. Moreover, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is present. The possibility exists for changes or revisions in estimated reserves to have a significant effect on depreciation, depletion and amortization charges and, therefore, reported net profit/(loss) for the year.
Deferred income tax asset recognition. The recognised deferred tax asset represents income taxes recoverable through future deductions from taxable profits and is recorded in the statement of financial position. Deferred income tax assets are recorded to the extent that realisation of the related tax benefit is probable. The future taxable profits and the amount of tax benefits that are probable in the future are based on the medium term business plan prepared by management and extrapolated results thereafter. The business plan is based on management expectations that are believed to be reasonable under the circumstances. Key assumptions in the business plan are an average oil price of $90 for 2012 and $90 in real terms for future sales.
Impairment provision for receivables. The impairment provision for receivables (including loans issued) is based on management's assessment of the probability of collection of individual receivables. Significant financial difficulties of the debtor/lender, probability that the debtor/lender will enter bankruptcy or financial reorganization, and default or delinquency in payments are considered indicators that the receivable is potentially impaired. Actual results could differ from these estimates if there is deterioration in a debtor's/lender's creditworthiness or actual defaults are higher than the estimates.
When there is no expectation of recovering additional cash for an amount receivable, the expected amount receivable is written off against the associated provision.
Future cash flows of receivables that are evaluated for impairment are estimated on the basis of the contractual cash flows of the assets and the experience of management in respect of the extent to which amounts will become overdue as a result of past loss events and the success of recovery of overdue amounts. Past experience is adjusted on the basis of current observable data to reflect the effects of current conditions that did not affect past periods and to remove the effects of past conditions that do not exist currently.
Asset retirement obligations. Management makes provision for the future costs of decommissioning hydrocarbon production facilities, pipelines and related support equipment based on the best estimates of futurecost and economic lives of those assets. Estimating future asset retirement obligations is complex and requires management to make estimates and judgments with respect to removal obligations that will occur many years in the future. Changes in the measurement of existing obligations can result from changes in estimated timing, future costs or discount rates used in valuation.
Useful lives of non-oil and gas properties. Items of non-oil and gas properties are stated at cost less accumulated depreciation. The estimation of the useful life of an asset is a matter of management judgement based upon experience with similar assets. In determining the useful life of an asset, management considers the expected usage, estimated technical obsolescence, physical wear and tear and the physical environment in which the asset is operated. Changes in any of these conditions or estimates may result in adjustments to future depreciation rates. Useful lives applied to oil and gas properties may exceed the licence term where management considers that licences will be renewed. Assumptions related to renewal of licences can involve significant judgment of management.
Impairment. As discussed further in Note 7, management have estimated the recoverable amount of cash generating units.
7 Impairment
Year ended 31 December 2011
At each balance sheet date management assesses whether there is any indication that the recoverable value has declined below the carrying value of the property, plant and equipment. As of 31 December 2011 no impairment indicators were identified by management.
Year ended 31 December 2010
At the end of 2010 the Group's management reassessed the impairment of production assets and cash generating units due to an increase in the forecast crude oil prices. As at 31 December 2010 the Group fully released the impairment provision of $32.8 million and $37.7 million for Arcticneft and Petrosakh cash generating units, respectively.
In assessing whether a write-down is required in the carrying value of a potentially impaired item of property, plant and equipment or an equity-accounted investment, its carrying value is compared with its recoverable amount. The recoverable amount is the higher of the asset'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 assets is usually difficult to obtain unless negations with potential purchasers are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment charges described below is value-in-use. The Group estimated value-in-use using a discounted cash flow model.
An average oil price of $90 for 2011 and $90 in real terms for future sales was estimated for the impairment calculation and a discount rate of 12% in real terms was used to discount the estimated future cash flows. The discount rate of 12% in real terms was derived from the Group's approximate pre-tax weighted average cost of capital.
A summary of the impairment reverse for the year ended 31 December 2010 is presented below:
Year ended
31 December
2010
------------ ------------
Arcticneft (32,815)
Petrosakh (37,661)
(70,476)
------------ ------------
8 Accounts Receivable and Prepayments
Year ended 31 December
------------------------------------------- -------------------------
2011 2010
------------------------------------------- ----------- ------------
Due from shareholders - 8,750
Loans issued to related parties 362 455
Trade accounts and notes receivable 1,183 794
Receivables from related parties - 1
------------------------------------------- ----------- ------------
Total financial assets 1,545 10,000
------------------------------------------- ----------- ------------
Recoverable and prepaid taxes including
VAT 944 2,073
Prepaid expenses 645 1,156
Advances to suppliers 1,582 1,292
Other 53 407
Total accounts receivable and prepayments 4,769 14,928
------------------------------------------- ----------- ------------
Included in total accounts receivable and prepayments are $1.0 million and $0.5 million at 31 December 2011 and 2010, respectively, denominated in US dollars and substantially all remaining amounts are denominated in Russian Roubles, except accounts receivable due from shareholders $8.75 million at 31 December 2010 which were denominated in Great Britain Pounds (GBP).
Trade accounts receivable arise primarily from sales to ongoing customers with standard payment terms. The category 'Other' primarily relates to prepaid amounts to customs and tax authorities, which will be returned to the Group either in cash or through an off-set against future payments.
Changes in the provision for impairment of trade and other receivables related to the recognition of a provision against receivables from related parties are as follows:
Year ended 31 December
------------------------------------------ -------------------------
2011 2010
------------------------------------------ ------------ -----------
At 1 January 5,250 -
Accrual of additional provision against
related party 706 5,185
Accrual of provision against third party
accounts receivable - 47
Using of provision against third party
accounts receivable (65)
Effect of currency translation 3 18
At 31 December 5,894 5,250
------------------------------------------ ------------ -----------
The carrying values of trade and other receivables approximate their fair value. The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivables mentioned above. The Group does not hold any collateral as security for trade and other receivables.
Trade and other receivables that are less than three months past due are generally not considered for impairment unless other indicators of impairment exist, such as indication of significant financial difficulty or bankruptcy. Trade and other receivables of $0.1 million and $0.4 million at 31 December 2011 and 2010, respectively were past due but not impaired. The ageing analysis of these past due but not impaired trade and other receivables are as follows:
31 December
--------------
2011 2010
--------------------------------- ------ ------
Up to 90 days past-due - -
91 to 360 days past-due - 375
Over 360 days past-due 88 73
--------------------------------- ------ ------
Total past due but not impaired 88 448
--------------------------------- ------ ------
The main part of past due receivables related to the members of independent customers for whom there are no recent history of defaults and was subsequently repaid.
9 Inventories
31 December
------------------
2011 2010
------------------------ -------- --------
Crude oil 4,046 4,629
Oil products 1,941 2,135
Materials and supplies 4,032 6,147
------------------------ -------- --------
Total inventories 10,019 12,911
------------------------ -------- --------
Inventory provision
Year ended 31 December
----------------------------------------- -------------------------
2011 2010
----------------------------------------- ------------ -----------
At 1 January 1,012 1,924
Additional provisions - -
Release of provision (151) (901)
Release of adjustment on net realizable
value - 9
Utilization of provision (861) -
Effect of currency translation - (20)
At 31 December - 1,012
----------------------------------------- ------------ -----------
Release of inventory provision was triggered by the fact that the company has made an updated analysis of market value of inventories, impaired in 2009.
10 Property, Plant and Equipment
Oil and gas Refinery and Assets under
Cost at properties related equipment Buildings Other Assets construction Total
------------------- ------------------- ------------------ ---------- ------------- ------------------ ---------
1 January 2010 91,991 5,394 1,207 5,096 3,443 107,131
Translation
difference (907) (52) (8) (42) (40) (1,049)
Reclassification
as intangible
assets - - - - (283) (283)
Additions - - - 1 1,633 1,634
Capitalised
borrowing costs - - - - 234 234
Transfers 363 39 - 9 (411) -
Impairment release
(Note 7) 64,612 3,219 214 1,417 1,014 70,476
Disposals (107) - (485) (467) - (1,059)
31 December 2010 155,952 8,600 928 6,014 5,590 177,084
Translation
difference (8,480) (459) (49) (302) (368) (9,658)
Reclassification
as intangible
assets - - - - - -
Additions 1,162 - - 158 2,232 3,552
Capitalised
borrowing costs - - - - 34 34
Transfers 1,248 - - - (1,248) -
Disposals (669) - - (382) (236) (1,287)
31 December 2011 149,213 8,141 879 5,488 6,004 169,725
------------------- ------------------- ------------------ ---------- ------------- ------------------ ---------
Additions to assets under construction included capitalised depreciation in the amount of $155 thousand (for the year ended 31 December 2010: $82 thousand). Average capitalisation rate for the year ended 31 December 2011 is 5.5% (for the year ended 31 December 2010: 6.0%).
Accumulated Depreciation, Amortization and Oil and gas Refinery and Assets under Depletion at properties related equipment Buildings Other Assets construction Total ------------------- ------------------ ------------------ ---------- ------------- ------------------ ---------- 1 January 2010 (38,783) (2,171) (648) (3,005) - (44,607) Translation difference 309 17 5 24 - 355 Depreciation (3,830) (204) (14) (407) - (4,455) Disposals 21 - 120 299 - 440 31 December 2010 (42,283) (2,358) (537) (3,089) (48,267) Translation difference 2,735 167 33 194 - 3,129 Depreciation (5,728) (469) (48) (706) - (6,951) Disposals 251 - - 380 - 631 31 December 2011 (45,025) (2,660) (552) (3,221) - (51,458) ------------------- ------------------ ------------------ ---------- ------------- ------------------ ---------- Net Book Value at 31 December 2010 113,669 6,242 391 2,925 5,590 128,817 31 December 2011 104,188 5,481 327 2,267 6,004 118,267 ------------------- ------------------ ------------------ ---------- ------------- ------------------ ----------
Included within oil and gas properties at 31 December 2011 and 2010 were exploration and evaluation assets:
Cost at Cost at
31 December Translation 31 December
2010 Additions difference 2011
---------------------------- ------------- ---------- ------------ -------------
Exploration and evaluation
assets
Arcticneft 16,909 - (903) 16,006
Petrosakh 30,783 - (1,647) 29,136
---------------------------- ------------- ---------- ------------ -------------
Total cost of exploration
and evaluation assets 47,692 - (2,550) 45,142
---------------------------- ------------- ---------- ------------ -------------
Cost at Additions: Cost at
31 December Impairment Translation 31 December
2009 reverse difference 2010
---------------------------- ------------- ------------ ------------ -------------
Exploration and evaluation
assets
Arcticneft 7,414 9,583 (88) 16,909
Petrosakh 17,688 13,273 (178) 30,783
---------------------------- ------------- ------------ ------------ -------------
Total cost of exploration
and evaluation assets 25,102 22,856 (266) 47,692
---------------------------- ------------- ------------ ------------ -------------
The Group's oil fields are situated in the Russian Federation on land owned by the Russian government. The Group holds production mining licenses and pays production taxes to extract oil and gas from the fields. The licenses expire between 2012 and 2067, but may be extended. Management intends to renew the licences as the properties are expected to remain productive subsequent to the license expiration date.
Estimated costs of dismantling oil and gas production facilities, including abandonment and site restoration costs, amount to $1.4 million and $1.2 million at 31 December 2011 and 2010, respectively, are included in the cost of oil and gas properties. The Group has estimated its liability based on current environmental legislation using estimated costs when the expenses are expected to be incurred.
11 Other Non-Current Assets
Year ended 31 December
------------------------------------------- -------------------------
2011 2010
------------------------------------------- ----------- ------------
Loans receivable (Note 4) - 37,810
Loans issued to related parties 851 834
Advances to contractors and suppliers for
construction in process 110 218
Intangible assets 186 564
Total other non-current assets 1,147 39,426
------------------------------------------- ----------- ------------
At 31 December 2010 loans receivable represent US dollar denominated long-term loans (interest inclusive) of $37.8 million issued by UEPCL to Taas. In 2011 the Company has assigned the full benefit of the Taas loans (Note 4).
12 Accounts Payable and Accrued Expenses
Year ended 31 December
----------------------------------------------- -------------------------
2011 2010
----------------------------------------------- ----------- ------------
Trade payables 503 1,588
Payable to Finfund Limited - 4,412
Accounts payable for construction in process 96 691
Wages and salaries 2,325 1,227
Advances from and payables to related parties - 13
Other payable and accrued expenses 1,858 2,850
----------------------------------------------- ----------- ------------
Total accounts payable and accrued expenses 4,782 10,781
----------------------------------------------- ----------- ------------
In December 2011 the Group fully discharged the payable of $4.4 million to Finfund by non-cash settlement transactions (Note 4).
Total accounts payable and accrued expenses in the amount of $1.0 million and $6.2 million at 31 December 2011 and 2010, respectively, are denominated in US dollars and substantially all remaining amounts are denominated in Russian Roubles.
13 Revenues
Year ended 31
December
------------------------------------------------ ---------------------
2011 2010
------------------------------------------------ --------- ----------
Crude oil
Export sales 25,340 31,394
Domestic sales (Russian Federation) 3,107 2,938
Petroleum (refined) products - domestic sales 34,913 24,130
Other sales 800 845
------------------------------------------------ --------- ----------
Total proceeds from sales 64,160 59,307
------------------------------------------------ --------- ----------
Less: excise taxes (3,723) (1,659)
Less: export duties (12,130) (14,147)
------------------------------------------------ --------- ----------
Revenues after excise taxes and export duties 48,307 43,501
------------------------------------------------ --------- ----------
Substantially all of the Group's export sales are made to third party traders with title passing at the Russian border. Accordingly, management does not monitor the ultimate consumers of its export sales.
14 Segment information
Effective 1 January 2009, the Group adopted IFRS 8, Operating Segments ("IFRS 8"), which replaces IAS 14, Segment Reporting. IFRS 8 introduces new requirements and guidelines regarding the disclosures of operating segments.
Operating segments are defined as components of the Group where separate financial information is available and reported regularly to the chief operating decision maker (hereinafter referred to as "CODM", represented by the Board of Directors of the Company), which decides how to allocate resources and assesses operational and financial performance using the information provided.
The CODM receives monthly IFRS based financial information for its production entities. There were two production entities in both 2011 and 2010. Management has determined that the operations of these production entities are sufficiently homogenous for these to be aggregated for the purpose of IFRS 8. The Group has other entities that engage as either head office / corporate or as holding companies. Consequently, management has concluded that due to the above aggregation criteria there is only one reportable segment.
Geographical information.The Group operates in three major geographical areas of the world. In the Russian Federation, its home country, the Group is mainly engaged in the exploration, development, extraction and sales of crude oil, and refining and sale of oil products. Activities outside the Russian Federation are restricted to sales activities where title passes upon tanker loading. Sales are made to Europe (sales of crude oil). Information on the geographical location of the Group's revenues is set out below.
For the year ended 31 December 2011:
Russian Europe Total
Federation
------------------------------ ------------ -------- --------
Crude oil 3,107 25,340 28,447
Petroleum (refined) products 34,913 - 34,913
Other sales 800 - 800
------------------------------ ------------ -------- --------
Total proceeds from sales 38,820 25,340 64,160
------------------------------ ------------ -------- --------
For the year ended 31 December 2010:
Russian Europe Total
Federation
------------------------------ ------------ -------- --------
Crude oil 2,938 31,394 34,332
Petroleum (refined) products 24,130 - 24,130
Other sales 845 - 845
------------------------------ ------------ -------- --------
Total proceeds from sales 27,913 31,394 59,307
------------------------------ ------------ -------- --------
Revenue from external customers is based on the geographical location of customers although all revenues are generated by assets in the Russian Federation. Substantially all of the Group's assets are located in the Russian Federation.
Major customers. For the year 2011, the Group has one major customer to whom individual revenues represent 39 percent of total external revenues (2010: one major customer that represented 52 percent).
15 Other matters
This statement was approved by the directors on 7 June 2012. The financial information for the year ended 31 December 2011 set out in this announcement does not constitute financial statements but is based on the financial statements for the year then ended.
The auditors have reported on those financial statements and their report contains a qualified opinion in relation to the Company's investment in Chepetskoye NGDU which was incorrectly deconsolidated from January 2009 prior to the expiry of a call option on 28 January 2010. As a result, Chepetskoye NGDU should have been deconsolidated at the expiration of the call option with an associated gain or loss on the disposal being recognized in the income statement as of that date. This error affects the 2010 comparative information included in the 2011 accompanying consolidated financial statements with the modification being a repetition from the audit reports issued in prior years. The auditor's report of the accounts for the year ended 31 December 2010 contained an emphasis of matter in relation to the Company's ability to continue as a going concern but was otherwise unqualified.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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