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
$ '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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