RNS Number:5649B
Urals Energy Public Company Limited
18 April 2006
Urals Energy Public Company Limited
Preliminary Results for the year ended 31 December 2005
Urals Energy Public Company Limited (LSE: UEN), the international oil and gas
exploration and production company which was admitted to the Alternative
Investment Market of the London Stock exchange in August 2005, raising US$131
million, today announces its preliminary results for the year ended 31 December
2005.
In a separate announcement today, the Company announced the signing of a
definitive Sales Purchase Agreement for the $148 million acquisition of the
significant Dulisminskoye oil, condensate and gas field together with the LTK
transportation and treating facilities, all located in the Irkutsk region of
Eastern Siberia, close to Transneft's proposed East Siberian Pipeline. The
Dulisminskoye Field is currently producing 1,000 bopd and Urals Energy intends
to move rapidly to increase production from this field through infield
development to approximately 12,000 bopd by the end of 2008 and approximately
30,000 bopd by 2011.
Operating Highlights:
* Completion and integration of ZAO Arcticneft, OOO Dinyu and OOO Urals Nord
acquisitions
* Near fivefold increase in average annual production from 1,146 to 5,263
bopd
* Current production increased to 9,000 bopd
* 2P reserves rose 31% to 116 million barrels (2004: 89.6 million barrels)
* 107% reserve replacement at a cost of $2.50 per barrel due to successful
development drilling
Financial and Corporate Highlights
* Admission to AIM and $131 million equity raising in August 2005
* Turnover increased to $92.9 million (2004: $8.2 million)
* Operating profit of $11.3 million (2004: loss of $3.7 million)
* Post tax profit of $7.1 million (2004: loss of $3.6 million)
* Adjusted EBITDA of $16.9 million
Outlook
* $40 million capex plan (excluding Dulisma acquisition) across 20 new
development wells and 2 high impact exploration wells
* Production (excluding Dulisma acquisition) targeted to increase by 33% to
approximately 12,000 bopd by end 2006
* Integration and development of Dulisma acquisition projected to add
incremental 12,000 bopd to group production by end 2008
* Continued focus on acquiring under exploited assets in Russia and the FSU
William R. Thomas, Chief Executive Officer, commented:
"2005 was a landmark year which saw Urals Energy establishing a solid production
and operational base in Russia which has delivered strong financial results.
The outlook for 2006 is excellent with an intense development and exploration
programme planned which will further increase production.
Today's announcement of the proposed acquisition of the Dulisma Field is an
important development for Urals giving us significant oil and gas reserves at an
attractive price and strategically located near the proposed East Siberia
pipeline."
18 April 2006
Pelham PR
James Henderson 020 7743 6673
Gavin Davis 020 7743 6677
CHAIRMAN'S AND CHIEF EXECUTIVE'S STATEMENT
2005 was a landmark year for Urals Energy - we outperformed our initial
objectives and built on our solid reserve and production base. Our strategy of
growing the company through development, exploration and acquisition is already
generating significant returns for shareholders. During the year we made three
successful acquisitions (ZAO Arcticneft, OOO Dinyu and OOO Urals Nord), average
yearly production increased almost fivefold from 1,146 to 5,263 bopd and current
production increased to 9,000 bopd resulting in an increased target of at least
14,000 bopd by the end of 2007. Proved and probable reserves rose significantly
from 89.6 to 116 million barrels, or approximately 31%, and we replaced 107% of
our produced reserves through development drilling at a cost of approximately
$2.50 per barrel. We also began an important exploration programme offshore
Sakhalin Island.
Underpinning this growth was the $131 million of new equity capital we raised in
our August 2005 IPO on the Alternative Investment Market (AIM) of the London
Stock Exchange.
Urals Energy's continued growth is based on a three-pronged strategy of (i)
increasing production through low-risk development drilling, (ii) adding
reserves by exploring our resource base offshore Sakhalin Island and onshore
Timan Pechora, and (iii) making new and larger acquisitions of Russian oil
companies. It is a strategy intended to create a balanced portfolio of upstream
assets which is managed and developed in a highly efficient and cost effective
manner. The cost to acquire and develop our proved and probable reserves to
date is approximately $1.73 per barrel, not including the Dulisma acquisition
announced separately today. We believe this is a proven strategy that will
continue to deliver significant returns to our shareholders.
Financial Results
In 2005, Urals Energy focussed on the acquisition and development of new
companies and assets and their integration into the Group. Our three new
acquisitions are consequently reflected in our overall financial results:
revenues totalled $93 million, adjusted EBITDA was $17 million, and profits
after tax were $7 million - all of which were significant increases over 2004's
results. Prices received for oil and products sold in 2005 averaged $43.24 and
$51.89 per barrel respectively while overall netback prices (gross price less
export taxes, transport and marketing costs and net of VAT) averaged $30.02 per
barrel. The price for domestic oil sold in Russia increased dramatically in
2005 from approximately $15 to $30 per barrel. This is the result of increased
domestic demand and improved margins for Russian refineries, a trend we expect
to continue during 2006.
Total cash operating costs were approximately $12 million, excluding DD&A,
production taxes, and other non-cash items. On a per barrel basis and as
compared to revenues, our cost structure is higher than other more mature
production operations in Russia. This is the result of acquiring only partially
developed fields and consolidating seven stand-alone companies within two years.
As we execute our development plans and production volumes grow, our per
barrel operating costs are expected to decline and profits increase
commensurately. We also expect to lower operating costs in our producing
subsidiaries by reducing headcount and streamlining operations.
We ended the year with $32.3 million in cash after having acquired OOO Dinyu for
$70 million cash in November 2005. In the same month, we closed a $100 million
revolving five year reserve-based lending facility with BNP Paribas. The net
amount drawn against this facility at year-end was $69 million. We are pleased
by the inherent recognition of creditworthiness this facility provides us. It
is now in syndication and preliminary results are very encouraging.
At 31 December 2005, our balance sheet was funded with approximately $200
million in shareholders equity and $81 million of bank and subordinated debt.
We believe this is a prudent debt to equity ratio for a rapidly growing business
like Urals Energy.
During 2006, we expect to maintain our planned level of capital expenditure of
approximately $40 million (excluding the proposed development spend on the
Dulisma acquisition announced today), almost all of which will be invested in
increasing production. By the end of 2006, our plan is to increase production
to approximately 12,000 BOPD from our existing assets. This should result in a
sustainable core production base that is generating strong cash flow and the
opportunity for further growth.
Operations
Sakhalin Island
At ZAO Petrosakh, both exploration and development activity continues at a rapid
pace.
Testing continues on our first offshore exploration well, East Okruzhnoye No. 1,
in the Pogranichny Block offshore Sakhalin Island, and results are expected
shortly.
Further planned exploration work during 2006 includes a second exploration well,
seismic studies and preparations for a possible marine drilling program in 2007.
We recently awarded a tender for the processing and interpretation of a combined
onshore and offshore 3D seismic data set that should further enhance our
understanding of both the onshore Okruzhnoye Field and the eleven exploration
prospects that lie directly offshore. Following the extension of our offshore
license for an additional five years, we believe a logical next step is to drill
several vertical exploration wells to test our best offshore prospects. This
will require mobilizing a marine drilling unit, probably a jackup, and extensive
pre-drilling preparations. Further details of this program will be announced
later in 2006.
As previously announced, the further development of the onshore Okruzhnoye Field
has been deferred until the interpretation of a new 3D seismic program is
completed. We have acquired a new mobile Russian drilling rig for this field
and expect development drilling to begin in June 2006. A total of three new
development wells and three re-entries are planned this year for the Okruzhnoye
Field.
We have also begun preparations for a fracture stimulation program at Petrosakh
and our other oil producing subsidiaries. Equipment has been purchased in
western Canada and is being refurbished prior to shipment to Sakhalin Island
this summer. Given the reservoir characteristics of the Okruzhnoye Field, we
expect good results from fraccing. After completing the Okruzhnoye Field
stimulation program, we will move the equipment to Komi and Timan Pechora where
we also believe we will boost production by fraccing.
Komi Republic and Timan Pechora
The acquisition of OOO Dinyu helped create a new core area for Urals Energy in
the Komi Republic which sits in the southern half of the prolific Timan Pechora
basin. In Komi, we produce from three fields at Dinyu and CNPSEI. Development
operations have continued at Dinyu since its acquisition with the drilling of
two producing wells, numbers 32 and 51. For Dinyu in 2006, we expect to drill a
total of nine development wells and one exploration well and have set a year-end
production target of approximately 4,000 BOPD.
Further north, the Timan Pechora basin extends to the Nenets Autonomous Okrug
where we have two operating subsidiaries, Arcticneft and Urals Nord. At
Arcticneft, we are now completing a comprehensive geological model to assist in
selecting well locations in preparation for our development drilling programme
this summer. During 2006, we expect to drill four development wells at
Arcticneft.
At Urals Nord, we are planning on drilling our first exploration well to test
the Nadezhdinsky prospect. Situated approximately 60 kilometers from the port
of Varandey, this prospect has high impact potential and if successful would be
developed to deliver oil to the LUKoil terminal now under construction at
Varandey.
Udmurtia
Our production and development operations at Chepetskoye NGDU continue on track
with the recent completion of the 3D seismic interpretation of the Potaposkvoye
Field. Development drilling operations will begin shortly for a planned four
well program in 2006.
Corporate
In line with our strategy, we are actively reviewing a number of new acquisition
opportunities, as evidenced by today's announcement of the proposed acquisition
of the Dulisma Field. The number and quality of potential acquisition
opportunities remain strong. Our business model is to acquire under-exploited
assets in Russia and the FSU, invest in development and exploration, and
monetize through either production or divestiture at the appropriate time. This
consolidation strategy is a proven business model, and we believe we have the
track record, highlighted by our acquisition and development costs to date of
$1.73 per barrel, to execute such strategies. With a strong track record of
success, Urals Energy is well positioned to take advantage of this attractive
market opportunity.
Outlook
The outlook for 2006 is positive. Production volumes are expected to grow to
approximately 12,000 BOPD by year-end as we further develop our oil fields
across Russia by drilling 20 new development wells. This development plan also
includes the introduction of new, mobile fracture-stimulation equipment designed
to quickly enhance production for an attractive cost. Our high-impact
exploration program offshore Sakhalin Island is expected to continue with
enhanced data and further developed understanding of the geology and petroleum
system. We also expect to spud our first exploration well in northern Timan
Pechora. Financially, the Group expects to generate stronger cash flow and
profits. Additionally, we continue to examine a number of potential acquisition
opportunities.
The Russian government is considering certain changes to the existing oil tax
regime. Should this occur in 2006, it could have a significant financial impact
on Urals Energy as we operate in many of the frontier areas that may become
eligible for tax holidays and other investment incentives. Revenue-based taxes
are our single largest cost item, approximately 29% of gross revenues, and we
and the industry as a whole continue to maintain an active dialogue with the
government on this important issue.
Finally, the backbone of our company and its most important advantage are our
employees. They have helped transform Urals Energy over the past 12 months to
become a successful international E&P company producing 9,000 BOPD with reserves
of 116 million barrels and a current market capitalization of approximately $600
million. It is their hard work, enthusiasm and skill that makes Urals Energy
successful.
Viatcheslav V. Rovneiko William R. Thomas
Chairman of the Board Chief Executive Officer
18 April 2006
FINANCIAL REPORT
Operating Environment
2005 was characterized by strong increases in world oil and gas prices and a
surge in exploration and production activity and investment. Brent oil prices
began the year at $39.50 per barrel, reached a peak of $67.49 per barrel and
ended the year at $58.21 per barrel. The Russian oil industry was similarly
affected by this changing price environment. Industry average domestic oil
prices began at $13 per barrel and averaged approximately $29 per barrel for the
year. Russian export prices rose with world market prices and resulted in
steadily increasing export taxes that absorbed much of the net export revenue
available to producers. This loss of export revenues was mostly offset by the
increase of domestic prices and resulting netback parity.
Increased oil and gas prices, particularly domestic prices, have resulted in
stronger demand for oilfield services in Russia. Rig availability for certain
types of specialized drilling is declining. Overall production costs are
increasing due to rising industry demand and the strengthening Rouble.
Production and Revenues
Crude oil production during the year increased by 359% from 418,000 barrels in
2004 to 1.92 million barrels in 2005, with average daily production increasing
from 1,146 barrels per day in 2004 to 5,263 in 2005. The total production
increase of 4,117 bopd was the result of both development drilling (740 bopd)
and additions from acquisitions (3,377 bopd).
During the period the Company's gross revenues totalled $92.9 million versus
$8.2 million in 2004. Net revenues increased to $66.1 million from $7.4 million
in the prior year. This revenue increase is the result of both the Group selling
2.1 million barrels of additional crude oil and products than in 2004 and higher
commodity prices. The Group realized a weighted average price of $43.24 per
barrel of oil sold in 2005. Export sales prices for the Group averaged $49.29
per barrel, and domestic sales prices averaged $28.96 per barrel. Domestic
refined product prices averaged $51.89 per barrel.
Net revenues received by the Company strengthened during the year as world oil
prices increased and the disparity between export and domestic prices narrowed.
Net revenues for 2005 totalled $66.1 million as compared to $7.4 million in
2004. Netback prices are defined as, in the case of exports, gross oil sales
price less export duty, customs charges, marketing costs and transportation,
and, in the case of domestic crude sales, gross sales price net of VAT. The
weighted average netback for crude oil sales during 2005 was $29.38 per barrel.
Netbacks for export sales were $31.36 per barrel and $24.15 per barrel for
domestic sales. Netback prices for domestic product sales are defined as gross
product sales price minus VAT, transportation, excise tax and refining costs.
The average products netback for the year was $34.87 per barrel.
Gross profit for the year, (net revenues minus the cost of production), was
$15.5 million as compared to $3 million in 2004. Production costs totalled
$50.4 million but included $20.7 million of non-cash items. These non-cash
charges included $12.5 million of crude oil inventory in place at Arcticneft
when acquired and subsequently sold at a zero book profit margin. Because of
these non-cash items included in its cost of production, the Company believes
the strength of the Group's operating performance is not fully reflected in its
gross profit result.
SG&A costs increased to $13.9 million as compared to $4.4 million in 2004. The
largest component increase in SG&A, wages and salaries, reflects a significantly
increased workforce and management team due to acquisitions and increased scope
of activity. Total audit and professional fees reflected the Company's
continued growth through acquisitions and related financing activities.
Interest expense for the period was $6.9 million as compared to $574 thousand in
2004. Increased interest expense primarily reflects the cost of financing
acquisitions and capital expenditures. $5.5 million of this was directly
related to interest on acquisitions payments.
Net profit for the year attributable to shareholders was $7.1 million as
compared to a loss of $3.7 million in 2004. Basic earnings per share were 12
cents versus a loss of 19 cents in 2004.
Adjusting for the Arcticneft inventory purchase, non-recurring mobilization
costs and other standard non-cash items, the Company's management-adjusted
EBITDA for the period was $16.9 million, or 24.6% of net revenues. Including
the full-year results of two companies acquired during 2005, Arcticneft and
Dinyu, pro-forma management-adjusted EBITDA was $22.6 million. At 31 December
2005 and based on year-end prices, an additional $3.9 million in potential
revenues and $1.9 million in EBITDA was held in the crude oil inventories at
Petrosakh and Arcticneft and stored for export in 2006.
Taxes
Russia has a relatively high cost tax regime and the Company pays a variety of
taxes that are levied as a result of production, exported oil, assets and
profits. The largest taxes for the Group as a percentage of revenues during 2005
were export duties (29%) and the unified production tax (18%). The Company paid
a total of $69.6 million in cash taxes for the year. Unified production taxes
are calculated based on production revenues and in 2005 the Group paid $24.5
million. Export duties are set according to a fixed schedule that increases as
export prices rise with a maximum rate of 65% of gross export prices above $25
per barrel. High export prices in 2005 resulted in an average export duty for
the Company of 40%, and $23.2 million of cash paid. VAT payments totalled $12.5
million.
At 31 December 2005, the Group's deferred tax liability was $51.1 million. This
is a non-cash liability and is the result of the difference between the Group's
consolidated IFRS-calculated profit taxes versus actual taxes paid by the
Group's operating subsidiaries. The Company expects this deferred tax liability
to be reflected on its balance sheet indefinitely.
Cash Flow
For the period, operating cash flow before working capital changes was $3.9
million. Changes in working capital resulted in a negative cash flow from
operations of $27.6 million. This is primarily due to a combined $12.4 million
increase in receivables for crude oil sales plus increased tax prepayments, and
a decrease in payables to suppliers compared with the start of the year.
Capital expenditures for exploration and development in 2005 were $16.4 million
of which $13.2 million was invested at Petrosakh, and $2.5 million at
Chepetskoye NGDU. The cost of acquisitions during 2005 was $93.7 million,
resulting in a total use of cash of $156.8 million.
At 31 December 2004, the Group's short and long-term debt was $38.5. During
2005, a total of $101.4 million in new debt was borrowed and $82.6 million in
debt repaid or converted to equity. As of 31 December 2005, total outstanding
debt was $81.1 million.
Through both a private-placement of common stock and the primary sale of shares
in a public offering, the company raised $150.7 million in cash. The
combination of debt and equity financing activities resulted in a total addition
to cash of $187.8 million.
Cash Position
The combined use of $156.8 million for operations, acquisitions and capital
expenditures was funded by the net addition of $187.8 million in cash from
borrowings and the sale of equity. This resulted in a change to the cash
position of $30.9 million by year end.
Hedging
The Company does not hedge any of its crude oil or product sales, costs or
currency conversions.
International Financial Reporting Standards (IFRS)
On 23 February 2006, the Company restated the interim results ending 30 June
2005. The restated results resulted in a net loss of $800,000 as compared with
the originally announced net loss of $1.145 million. The difference was
primarily the result of minor adjustments in gross revenues, cost of production,
and interest costs and had no material effect on the Company's cash flows.
The implementation of IFRS accounting procedures has resulted in a number of
non-cash adjustments and non-recurring costs in the accounts. Management
believes that certain large items distort the actual cash operating
characteristics of the business.
As previously mentioned, the Company's deferred tax liability of $51.1 million
is a non-cash item and is due to the difference between the Group consolidated
profit taxes calculated for IFRS purposes versus those actually paid by each
subsidiary as federal income taxes are accrued. These amounts are not due for
payment by the Company, and are likely to continue to increase in subsequent
statements.
Under IFRS purchase accounting, the excess of the purchase price paid for a
property over the fair market value of its tangible assets must be depleted over
time using a unit of production formula. The result is an increase to the
Company's Depreciation and Depletion, and will adjust depending on the estimate
of future proven and producing barrels of oil.
IFRS treatment for the excess of the fair market value of the tangible assets at
Arcticneft over the amount paid for the business by the Company resulted in
$16.8 million of negative goodwill for the period. This non-cash item increased
operating profits by a corresponding amount.
Under IFRS methodology, the Company applies successful efforts accounting to
exploration and development expenses. Certain expenses have been capitalized
pending the determination of the success of the related exploration or
development program. The non-recurring mobilization costs for the period relate
to the cost of mobilizing an exploratory drilling rig that was not ultimately
used for drilling. This expense item is not included in cost of production.
Urals Energy Public Company Limited
Consolidated Balance Sheets
(presented in US$ thousands)
31 December:
Note 2005 2004
Assets
Current assets
Cash and cash equivalents 32,334 1,395
Restricted cash - 26
Accounts receivable and prepayments 5 23,788 3,706
Inventories 6 12,641 2,773
Total current assets 68,763 7,900
Non-current assets
Property, plant and equipment 7 287,485 102,754
Other non-current assets 2,098 292
Total assets 358,346 110,946
Liabilities and equity
Current liabilities
Accounts payable and accrued expenses 8 7,932 3,748
Income taxes payable 9 6,039 387
Other taxes payable 9 5,448 1,530
Short-term borrowings and current 10 34,117 38,486
portion of long-term borrowings
Advances from customers 523 5,103
Amount due for acquisition of ZAO Petrosakh 4 - 9,899
Total current liabilities 54,059 59,153
Long-term liabilities
Long-term borrowings 10 47,005 -
Long-term finance lease obligations 1,357 1,556
Dismantlement provision 11 813 950
Deferred tax liability 9 51,100 18,390
Other long term liabilities 580 1,590
Total long-term liabilities 100,855 22,486
Total liabilities 154,914 81,639
Equity
Share capital 12 460 209
Share premium 12 201,355 42,172
Unpaid capital 12 - (11,324)
Translation difference (2,296) 1,264
Retained earnings (accumulated deficit) 2,714 (4,341)
Equity attributable to shareholders 202,233 27,980
of Urals Energy Public Company Limited
Minority interest 1,199 1,327
Total equity 203,432 29,307
Total liabilities and equity 358,346 110,946
Urals Energy Public Company Limited
Consolidated Statements of Operations
(presented in US$ thousands)
Year ended 31 December:
Note 2005 2004
Revenues
Gross revenues 13 92,918 8,184
Less: excise taxes and export duties (26,783) (783)
Net revenues 66,135 7,401
Operating costs
Cost of production 14 (50,442) (4,352)
Selling, general and administrative expenses 15 (13,968) (6,825)
Non-recurring mobilization costs 16 (7,170) -
Excess of net assets acquired over purchase price 4 16,793 -
Total operating costs (54,787) (11,177)
Operating profit (loss) 11,348 (3,776)
Interest income 913 82
Interest expense (6,911) (574)
Foreign currency gains (losses) (185) 211
Other non-operating gains (losses) (457) 222
Income (loss) before income tax 4,708 (3,835)
Current income tax 9 (890) (103)
Deferred income tax benefit 9 3,155 280
Profit (loss) for the period 6,973 (3,658)
Attributable to
Minority interest (82) 14
Shareholders of Urals Energy Public Company Limited 7,055 (3,672)
Earnings (loss) per share of profit attributable to
shareholders of Urals Energy Public Company Limited (adjusted
for share split and expressed in US dollars per share)
- Basic earnings per share 0.11 (0.1898)
- Diluted earnings per share 0.11 (0.1898)
Weighted average shares outstanding
- Basic earnings per share 59,915,473 19,344,262
- Diluted earnings per share 59,939,038 19,344,262
Urals Energy Public Company Limited
Consolidated Statements of Cash Flows
(presented in US$ thousands)
Year ended 31 December:
2005 2004
Cash flows from operating activities
Profit (loss) before income tax 4,708 (3,835)
Adjustments for:
Depreciation and depletion 9,394 522
Non-cash expenses 42 1,928
Interest income (913) (82)
Interest expense 6,911 574
Loss on disposal of long-lived assets 640 -
Excess of net assets acquired over purchase price (16,793) -
Effect of currency translation 185 211
Other non-cash transactions (213) -
Operating cash flows before 3,961 (682)
changes in working capital
Decrease (increase) in inventories 3,234 (374)
Increase in accounts receivables and prepayments (12,374) (1,097)
Increase (decrease) in accounts payable and accrued expenses (18,644) 2,152
Decrease in other current assets 178 -
Decrease in income and other taxes payable (785) (140)
Increase in other liabilities and provisions (3,182) 307
Cash generated from (used in) operations (27,612) 166
Interest received 913 52
Interest paid (2,685) -
Income tax paid (2,862) -
Net cash generated from
(used in) operating activities (32,246) 218
Cash flows from investing activities
Acquisitions of subsidiaries, net of cash acquired 4 (106,500) (39,976)
Purchase of property, plant and equipment (18,087) (1,146)
Acquisition of associates - (264)
Net cash used in investing activities (124,587) (41,386)
Cash flows from financing activities
Proceeds from borrowings 101,412 28,937
Repayment of borrowings (56,313) -
Finance lease principle payments (404) -
Contributions from shareholders - 871
Cash proceeds from issuance of ordinary shares 143,100 12,797
Net cash generated from financing activities 187,795 42,605
Effect of exchange rate changes (49) (26)
on cash and cash equivalents
Net increase in cash and cash equivalents 30,913 1,411
Cash and cash equivalents 1,421 10
at the beginning of the period
Cash and cash equivalents
at the end of the period 32,334 1,421
Urals Energy Public Company Limited
Consolidated Statements of Changes in Shareholders' Equity
(presented in US$ thousands)
Notes Share Share Unpaid Retained Equity Minority Total
capital premium capital earnings attributable interest equity
(accumulated to
deficit) Shareholders
Cumulative of Urals
Translation Energy Public
Adjustment Company
Limited
Balance at 31 December 20 10 - - (669) (639) - (639)
2003
Effect of currency 1,264 - 1,264 1 1,265
translation
Loss for the year - (3,672) (3,672) 14 (3,658)
Total recognized income 1,264 (3,672) (2,408) 15 (2,393)
(loss)
Acquisitions - - - - - - 1,312 1,312
Issuance of shares 12 189 41,291 (11,324) - - 30,156 - 30,156
Contribution from 12 - 871 - - - 871 - 871
shareholders
Balance at 31 December 209 42,172 (11,324) 1,264 (4,341) 27,980 1,327 29,307
2004
Effect of currency (3,560) - (3,560) (46) (3,606)
translation
Profit for the year - 7,055 7,055 (82) 6,973
Total recognized income (3,560) 7,055 3,495 (128) 3,367
(loss)
Acquisitions - - - - - - -
Issuance of shares 12 251 159,141 11,324 - - 170,716 - 170,716
Share-based payment 12 - 42 - - - 42 - 42
Balance at 31 December 460 201,355 - (2,296) 2,714 202,233 1,199 203,432
2005
Urals Energy Public Company Limited
Notes to the Consolidated Financial Statements
(in US dollars, tabular amounts in US$ thousands, except as indicated)
1 Activities
Urals Energy Public Company Limited ("Urals Energy" or the "Company") was
incorporated as a limited liability company in Cyprus on 10 November 2003. The
Company was formed to act as a holding company for investments in the Russian
oil and gas exploration and production sector. Pursuant to a Shareholder
Agreement dated 28 July 2004, certain shareholders contributed certain assets
including AO Cheptskoye NGDU to the Company, (Notes 4 and 12).
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. In July 2005, the Company changed its name to Urals
Energy Public Company Limited. The Group's primary office in Russia is located
at 6 Oktyabrskaya Ul. Moscow, 127018, Russian Federation.
The Group comprises the following subsidiaries:
Entity Jurisdiction Effective interest
at 31 December:
2005 2004
Exploration and production
ZAO Petrosakh ("Petrosakh") Sakhalin 97.2% 97.2%
ZAO Arcticneft ("Arcticneft") Nenetsky 100.0% -
OOO CNPSEI ("CNPSEI") Komi 100.0% 100.0%
ZAO Chepetskoye NGDU ("Chepetskoye") Udmurtia 100.0% 100.0%
OOO Dinyu ("Dinyu") Komi 100.0% -
OOO Michayuneft ("Michayuneft") Komi 100.0% -
Management company
OOO Urals Energy Moscow 100.0% 100.0%
Service company
Urals Energy (UK) Limited United Kingdom 100.0% 100.0%
Exploration
OOO Urals-Nord ("Urals-Nord")* Nenetsky 100.0% 50.0%
Trading
UENEXCO Limited ("UENEXCO")** Cyprus 100.0% -
* Urals-Nord was an equity associate of the Group at 31 December 2004.
** UENEXCO was incorporated during 2005 for trading purposes.
2 Basis of Preparation of the Financial Statements and Significant
Accounting Policies
Basis of preparation. These consolidated financial statements have been prepared
in accordance with, and comply with, International Financial Reporting Standards
("IFRS"). The consolidated financial statements have been prepared under the
historical cost convention. The preparation of consolidated financial statements
in conformity with IFRS requires management to make prudent estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements preparation and the reported amounts of
revenues and expenses during the reporting period. Critical estimates are
disclosed in Note 3. Actual results could differ from the estimates.
Functional and presentation currency. The United States Dollar ("US dollar or
US$") is the presentation currency for the Group's operations as the majority of
the Company's operations is conducted in US dollars and 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 and presented in US dollars in accordance with IAS
21 (revised 2003), The Effects of Changes in Foreign Exchange Rates.
Translation to functional currency. Monetary balance sheet items denominated in
foreign currencies have been remeasured using the exchange rate at the
respective balance sheet date. Exchange gains and losses resulting from foreign
currency translation are included in the determination of profit or loss. The US
dollar to Russian Rouble exchange rates were 28.78 and 27.75 as of 31 December
2005 and 2004, respectively.
Translation to presentation currency. The results and financial position of each
group entity (functional currency of none of which is a currency of a
hyperinflationary economy) are translated into the presentation currency as
follows:
(i) Assets and liabilities for each balance sheet presented are
translated at the closing rate at the date of that balance sheet. 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 income statement are translated 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 equity are reclassified to profit or loss.
Group accounting. Subsidiaries, which are those entities in which the Group has
an interest of more than one half of the voting rights, or otherwise has power
to exercise control over the operations, are consolidated. Subsidiaries are
consolidated from the date on which control is transferred to the Group and are
no longer consolidated from the date that control ceases. The purchase method of
accounting is used to account for the acquisition of subsidiaries by the Group.
The cost of an acquisition is measured as the fair value of the consideration
provided or liabilities incurred or assumed at the date of exchange plus costs
directly attributable to the acquisition.
All intercompany transactions, balances and unrealised gains on transactions
between group companies are eliminated; unrealised losses are also eliminated
unless the transaction provides evidence of an impairment of the asset
transferred.
Minority interest at the balance sheet date represents the minority
shareholders' portion of the fair values of the identifiable assets, liabilities
and contingent liabilities of the subsidiary at the acquisition date, and the
minorities' portion of movements in equity since the date of the combination.
Minority interest is presented as a separate component of equity. Where the
losses applicable to the minority in a consolidated subsidiary exceed the
minority interest in the equity of the subsidiary, the excess and any further
losses applicable to the minority are charged against the majority interest
except to the extent that the minority has a binding obligation to, and is able
to, make good the losses. If the subsidiary subsequently reports profits, the
majority interest is allocated all such profits until the minority's share of
losses previously absorbed by the majority has been recovered.
Property, plant and equipment. Property, plant and equipment acquired as part
of a business combination is recorded at fair value at the acquisition date.
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 accordance with the successful efforts method. Under the successful efforts
method, costs of successful development and exploratory wells are capitalised.
Costs of unsuccessful exploratory wells are expensed upon determination that the
well does not justify commercial development. Other exploration costs are
expensed as incurred.
Depletion of capitalized costs of proved oil and gas properties is calculated
using the units-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 with Society of Petroleum Engineers definitions and were estimated by
DeGolyer and MacNaughton, the Group's independent reservoir engineers. 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
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
financial statements at each balance sheet date at their expected net present
values using discount rates which reflect the economic environment in which the
Group operates.
Changes in provisions resulting from the passage of time are reflected in the
statement of 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.
The provision for dismantlement liability is recorded on the balance sheet, 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. Each lease payment is allocated between the liability
and finance charges so as to achieve a constant rate on the finance balance
outstanding. The corresponding rental obligations, net of finance charges, are
included in other long-term payables. The interest element of the finance cost
is charged to the income statement over the lease period. The property, plant
and equipment acquired under finance leases are depreciated over the shorter of
the useful life of the asset or the lease term, with the comparison being made
based on the current annual extraction level.
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 (net of any incentives received from the lessor) are charged to
the income statement on a straight-line basis over the period of the lease.
Impairment of assets. Assets that are subject to depreciation 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
at the lowest levels for which there are separately identifiable cash flows
(cash-generating units).
Inventories. Inventories of extracted crude oil, materials and supplies and
construction equipment are valued at the lower of the weighted-average cost and
net realisable value. 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. 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
effective interest rate. The amount of the provision is recognised in the
statement of operations.
Cash and cash equivalents. Cash and cash equivalents include cash in hand and
deposits held at call with banks. Cash and cash equivalents are carried at
amortised cost using the effective interest method.
Value added tax. Value added taxes related to sales are payable to tax
authorities upon collection of receivables from customers. Input VAT is
reclaimable against sales VAT upon payment for purchases. The tax authorities
permit the settlement of VAT on a net basis. VAT related to sales and purchases
which have not been settled at the balance sheet date (VAT deferred) is
recognised in the balance sheet on a gross basis and disclosed separately as a
current asset and liability. Where provision has been made against debtors
deemed to be uncollectible, an impairment loss is recorded for the gross amount
of the debtor, including VAT. The related VAT deferred liability is maintained
until the debtor is written off for statutory accounting purposes.
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 yield 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 balance sheet date.
Loans receivable. The loans advanced by the Group to its shareholder are
classified as "loans and receivables" in accordance with IAS 39 and stated at
amortised cost using the effective interest method.
Deferred income taxes. Deferred income tax is calculated at rates enacted or
substantially enacted at the balance sheet date, using the balance sheet
liability method, for all temporary differences between the tax bases of assets
and liabilities and their carrying values for financial reporting purposes. The
principal temporary differences arise from depreciation on property, plant and
equipment, provisions, fair value adjustments to long-term items, and expenses
which are charged to the statement of operations before they become deductible
for tax purposes.
Deferred income tax assets attributable to deducible temporary differences,
unused tax losses and credits are recognised only to the extent that it is
probable that future taxable profit or taxable temporary differences will be
available against which they can be utilised.
Deferred income tax assets and liabilities are offset when the Group has a
legally enforceable right to set off current tax assets against current tax
liabilities, when deferred tax balances relate to the same regulatory body, and
when they relate to the same taxable entity.
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, have been
charged to statement of operations.
Pension costs. The Group makes required contributions to the Russian Federation
state pension scheme on behalf of its employees. Mandatory contributions to the
governmental pension scheme are expensed or capitalized to inventories on a
basis consistent with the associated salaries and wages.
Revenue recognition. Revenues are recognised when crude oil or refined products
are dispatched to customers and title has transferred. Revenues from non-cash
sales are recognised at the fair value of the goods or services received. Gross
revenues include export duties and excise taxes but exclude value added taxes.
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 one geographic segment,
which is the Russian Federation.
Reclassifications. Certain reclassifications have been made to 2004 amounts to
conform to 2005 presentation. Additionally, certain adjustments were made to
2004 amounts related to the finalization of the Group's purchase accounting for
2004 acquisitions. The table below discloses the adjusted amounts before and
after the reclassifications. Management believes that the current presentation
is preferable to that presented in prior years.
As originally Following
reported reclassification
At 31 December 2004
Inventories 2,247 2,773
Property, plant and equipment 100,622 102,754
Short-term borrowings and current portion of long-term borrowings 38,815 38,486
Accounts payable and accrued expenses 3,019 3,748
Deferred tax liability 17,751 18,390
Other long-term liabilities - 1,590
Translation difference 1,236 1,264
For the year ended 31 December 2004
Selling, general and administrative expenses 7,115 6,825
Cost of production 4,062 4,352
At 31 December 2004, inventories, property, plant and equipment, accounts
payable and accrued expenses, deferred tax liability, other long-term
liabilities and translation difference were increased by $0.526 million, $2.132
million, $0.400 million, $0.639 million, $1.590 million and $0.028 million,
respectively, to reflect the respective fair values after the Group completed
its purchase accounting for its acquisition of Petrosakh that occurred in
December 2004.
Also at 31 December 2004, management reclassified $0.329 million from short-term
borrowings and current portion of long-term debt to accounts payable and accrued
expenses to conform to current year's presentation of accrued interest and
certain other accruals.
For the year ended 31 December 2004, selling, general and administrative
expenses was decreased and cost of production was increased by $0.290 million,
primarily to record salaries of management personnel working at production
locations within cost of production.
New accounting developments. In December 2003, the International Accounting
Standards Board ("IASB") released 15 revised International Accounting Standards
and withdrew one IAS standard. The revised standards were all mandatory for
periods starting on or after 1 January 2005.
In 2004, the IASB published five new standards, two revisions and two amendments
to existing standards. In 2005, the IASB published one new standard and seven
amendments of existing standards. In addition, the International Financial
Reporting Interpretations Committee issued five new interpretations in 2004 and
two in 2005. Significant changes relevant to the Group as a result of the new
effective or early adopted IFRSs are:
IAS 1 (revised 2003), Presentation of Financial Statements ("IAS 1 (revised)").
IAS 1 (revised) requires the classification as current all financial liabilities
for which the Group does not have an unconditional right to defer their
settlement for at least twelve months after the balance sheet date.
Additionally, IAS 1 (revised) requires that minority interest be presented
within total equity and that profit or loss for the period is allocated between
"profit or loss attributable to minority interest" and "profit or loss
attributable to shareholders of the parent" on the face of the consolidated
statements of operations. The revised standard is applied retrospectively in
accordance with IAS 8.
IAS 8 (revised 2003), Accounting Policies, Changes in Accounting Estimates and
Errors. The Group now applies all voluntary changes in accounting policies
retrospectively. Comparatives are amended in accordance with the new policies.
All material errors are now corrected retrospectively in the first set of
financial statements after their discovery.
IAS 21 (revised 2003) The Effects of Changes in Foreign Exchange Rates ("IAS 21
(revised)"). IAS 21 (revised) clarifies the method of translation of foreign
currencies to the functional and presentation currency and clarifies that
goodwill and fair value adjustments to assets and liabilities resulting from
acquisitions are treated as part of the assets and liabilities of the acquired
entity and translated at the exchange rate on the balance sheet date. There was
no significant effect upon the Group's retrospective adoption of IAS 21
(revised) on 1 January 2005.
IAS 24 (revised 2003) Related Party Disclosures. The definition of related
parties was extended and additional disclosures required by the revised standard
were made in these financial statements. The revised standard is applied
retrospectively in accordance with IAS 8.
IAS 36 (revised 2004) Impairment of Assets ("IAS 36"). The Group now performs
impairment tests of goodwill, intangible asset not yet available for use and
intangible assets with indefinite useful life at least annually. The 'bottom-up
/top-down' approach to testing goodwill was replaced by a simpler method. As
applicable, the goodwill is, from the acquisition date, allocated to each of the
acquirer's cash-generating units ("CGU"), or groups of CGUs, that are expected
to benefit from the synergies of the business combination. Each unit or group
of units to which the goodwill is allocated represents the lowest level at which
the goodwill is monitored and is not larger than a segment. Reversals of
impairment losses of goodwill are now prohibited. The clarifications of certain
elements of value in use calculations in the revised IAS 36 did not have an
impact on these financial statements. Management now assesses reasonableness of
the assumptions on which the Group's current cash flow projections are based by
examining the causes of differences between past cash flow projections and
actual cash flows. The revised IAS 36 is applied in accordance with the
standard's transitional provisions to goodwill and intangible assets acquired in
business combinations for which the agreement date is on or after 31 March 2004
and to all other assets prospectively from 1 January 2005.
IAS 38 (revised 2004) Intangible Assets ("IAS 38"). The revised IAS 38 is
applied prospectively in accordance with its transitional provisions. The
amended accounting policies apply to intangible assets acquired in business
combinations for which the agreement date is on or after 31 March 2004 and to
all other intangible assets acquired on or after 1 January 2005. Intangible
assets now include assets that arise from contractual or other legal rights,
regardless of whether those rights are transferable or separable. The
probability of inflow of economic benefits recognition criterion is now deemed
to be always met for intangibles that are acquired separately or in a business
combination. The Group's policies were amended to introduce the concept of
indefinite life intangible assets which exist when, based on an analysis of all
of the relevant factors, management concludes that there is no foreseeable limit
to the period over which the asset is expected to generate net cash inflows.
Such intangibles are not amortised but tested for impairment at least annually.
The Group has reassessed the useful lives of its intangible assets in accordance
with the transitional provisions of IAS 38. No adjustment resulted from this
reassessment.
IFRS 2, Share-based Payment. IFRS 2 requires that the fair value of the
employee services received in exchange for the grant of the equity instruments
is recognised as an expense over the vesting period. For transactions with
parties other than employees, the Group accounts for the transaction based upon
the fair value of goods or services provided, unless the fair values are not
reliably estimable. The adoption of IFRS 2 on 1 January 2005 did not have a
material effect on the Group as the Group had no outstanding share-based awards
upon adoption.
IFRS 3, Business Combinations. IFRS 3 requires accounting for all business
combinations by applying the purchase method and separate recognition, at the
acquisition date, of the acquiree's contingent liabilities if their fair values
can be measured reliably. It also requires that the identifiable assets,
liabilities and contingent liabilities are measured at their fair values
irrespective of the extent of any minority interest. Any resulting goodwill is
tested for impairment annually, or when there are indications of impairment.
The excess of the Group's interest in the net fair value of an acquiree's
identifiable assets, liabilities and contingent liabilities over the cost
("negative goodwill") is recognized immediately in the consolidated statement of
operations. The Group applies transitional provisions of IFRS 3 and applies it
to all business combinations for which the agreement date is on or after 31
March 2004.
IFRS 5 (issued 2005) Non-current Assets Held for Sale and Discontinued
Operations ("IFRS 5"). The Group applies IFRS 5 prospectively in accordance
with its transitional provisions to non-current assets (or disposal groups) that
meet the criteria to be classified as 'held for sale' and operations that meet
the criteria to be classified as 'discontinued' after 1 January 2005. The
Group's accounting policies now describe assets 'held for sale' as those that
will be recovered principally through a sale transaction rather than through
continuing use. Subject to certain exceptions, assets or disposal groups that
are classified as 'held for sale' are measured at the lower of carrying amount
and fair value less costs to sell. Such assets cease to be depreciated and are
presented separately on the face of the balance sheet. There was no impact of
the adoption of IFRS 5.
IFRS 6, Exploration for and Evaluation of Mineral Resources ("IFRS 6"). IFRS 6
was early adopted by the Group, before its effective date. IFRS 6 allows an
entity to continue using the accounting policies for exploration and evaluation
assets applied immediately before adopting the IFRS, subject to certain
impairment test requirements. As permitted under IFRS 6, the Group capitalizes
exploration and evaluation costs until such time as the economic viability of
producing the underlying resources is determined.
IAS 21 (Amendment) - Net Investment in a Foreign Operation. The amendment to
IAS 21 was early adopted by the Group, before its effective date. It clarifies
treatment of foreign exchange differences on intercompany loans that form part
of a net investment in a foreign operation.
The adoption of all the other new or revised standards that are effective for
2005 did not have a material impact on the Group's financial position,
statements of income or of cash flows.
New or revised standards that are not yet effective. Certain new standards and
interpretations have been published that are mandatory for the Group's
accounting periods beginning on or after 1 January 2006 or later periods and
which the Group has not early adopted:
IFRIC 4, Determining whether an Arrangement contains a Lease (effective from 1
January 2006); IAS 39 (Amendment) - The Fair Value Option (effective from 1
January 2006); IAS 39 (Amendment) - Cash Flow Hedge Accounting of Forecast
Intragroup Transactions (effective from 1 January 2006); IAS 39 (Amendment) -
Financial Guarantee Contracts (effective from 1 January 2006); IFRS 7,
Financial Instruments: Disclosures and a Complementary Amendment to IAS 1
Presentation of Financial Statements - Capital Disclosures (effective from 1
January 2007); IAS 19 (Amendment) - Employee Benefits (effective from 1 January
2006); IFRS 1 (Amendment) - First-time Adoption of International Financial
Reporting Standards and IFRS 6 (Amendment) - Exploration for and Evaluation of
Mineral Resources (effective from 1 January 2006); IFRIC 5, Rights to Interests
arising from Decommissioning, Restoration and Environmental Rehabilitation Funds
(effective from 1 January 2006); IFRIC 6, Liabilities arising from
Participating in a Specific Market - Waste Electrical and Electronic Equipment
(effective for periods beginning on or after 1 December 2005); IFRIC 7,
Applying the Restatement Approach under IAS 29 (effective for periods beginning
on or after 1 March 2006); IFRIC 8, Scope of IFRS 2 (effective for periods
beginning on or after 1 May 2006) and IFRIC 9, Reassessment of Embedded
Derivatives (effective for periods beginning on or after 1 June 2006).
3 Critical Estimates in Applying Accounting Policies
These new standards and interpretations are not expected to significantly affect
the Group's financial statements when adopted on 1 January 2006 or later.
The Group makes estimates and assumptions that affect the reported amounts of
assets and liabilities. 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. Judgments that
have the most significant effect on the amounts recognised in the financial
statements and estimates that can cause a significant adjustment to the carrying
amount of assets and liabilities are outlined below.
Accounting for extractive industry activity. The Group follows the successful
efforts method of accounting for oil and gas properties. Under the successful
efforts method, property acquisitions, successful exploratory wells, all
development costs and support equipment and facilities are capitalised.
Unsuccessful exploratory wells are charged to expense at the time the wells are
determined to be non-productive. Production costs, overhead and all exploration
costs other than exploratory drilling are charged to expense as incurred.
Acquisition costs of unproved properties, exploration and evaluation costs are
evaluated periodically and any impairment assessed is charged to expense.
The Group calculates depreciation, depletion and amortisation of capitalised
costs of oil and gas properties using the unit-of-production method for each
field based upon proved developed reserves for exploration and development
costs, and total proved reserves for acquisitions of proved properties. For
this purpose, the oil and gas reserves of key fields have been determined based
on estimates of mineral reserves determined in accordance with internationally
recognised definitions and independently assessed by internationally recognised
petroleum engineers. The present value of the estimated costs of dismantling oil
and gas production facilities, including abandonment and site restoration costs
are recognised when the obligation is incurred and are included within the
carrying value of property, plant and equipment, and therefore subject to
amortisation thereon using the unit-of-production method. Changes in estimates
of reserves can result in significant changes in depletion expense.
Tax legislation. Russian tax, currency and customs legislation is subject to
varying interpretations as further discussed in Note 17.
Deferred income tax asset recognition. Deferred tax assets represent income
taxes recoverable through future deductions from taxable profits. Deferred
income tax assets are recorded on the Group's consolidated balance sheets to the
extent that realisation of the related tax benefits is probable. In determining
future taxable profits and the amount of tax benefits that are probable in the
future, management makes judgements and applies estimation based on recent
years' taxable profits and expectations of future taxable income.
Related party transactions. In the normal course of business, the Group enters
into transactions with its related parties. 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.
Assumptions to determine amount of provisions. In determining amounts of
provisions, management uses all information available to determine whether an
asset is recoverable or whether it is probable that an event will result in
outflows of resources from the Group. Significant judgment is used to estimate
the amounts of provisions, including such factors as the current overall
economic conditions, specific customer, counterparty or industry conditions and
the current overall legal and tax environment. Changes in any of these
conditions may result in adjustments to provisions recorded by the Group.
Useful lives of property, plant and equipment. Items of property, plant and
equipment are stated at cost less accumulated depreciation. The estimation of
the useful life of an item of property, plant and equipment is a matter of
management judgment 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.
Fair values of acquired assets and liabilities. Since its inception, the Group
has completed several significant acquisitions (Note 4). IFRS 3 requires that,
at the date of acquisition, all identifiable assets (including intangible
assets), liabilities and contingent liabilities of an acquired entity be
recorded at their respective fair values. The estimation of fair values
requires management judgment. For significant acquisitions, management engages
independent experts to advise as to the fair values of acquired assets and
liabilities. Changes in any of the estimates subsequent to the finalization of
acquisition accounting may result in losses in future periods.
Going concern. Management assumed that the Group will continue as a going
concern.
Fair values of financial instruments. Fair value is the amount at which a
financial instrument could be exchanged in a current transaction between willing
parties, other than in a forced sale or liquidation, and is best evidenced by an
active quoted market price. The estimated fair values of financial instruments
have been determined by the Group using available market information, where it
exists, and appropriate valuation methodologies where no market information is
available. However, judgement is necessarily required to interpret market data
to determine the estimated fair value.
Cash and cash equivalents are carried at amortised cost which approximates
current fair value.
At 31 December 2005 and 2004, the carrying amounts of trade and other
receivables, short-term borrowings, trade and other payables, taxes payable and
advances from customers approximated their fair values.
The fair values of the Group's long-term borrowings were estimated based upon
rates available to the Group on similar instruments of similar maturities. At
31 December 2005 and 2004, management believes that the fair values of its
borrowings approximate their respective carrying values.
4 Acquisitions
Acquisition of Dinyu. In November 2005, the Group acquired a 100.0 percent
stake in Dinyu from Lonsdacks Investments Limited for $61.5 million following
the approval from the Russian Federal Antimonopoly Service.
Subsequent to its purchase of Dinyu, on 21 December 2005 the Group purchased the
35 percent stake owned by third parties in the 65 percent-owned subsidiary of
Dinyu, OOO Michayuneft ("Michayuneft") for $0.2 million. Since the date of
acquisition, Dinyu contributed $0.466 million of net profit to the Group's
operating results.
Acquisition of Arcticneft. In July 2005, the Group acquired a 100.0 percent
equity interest in Arcticneft from OAO LUKoil for $23 million net of debt.
Arcticneft holds production licenses in the Nenetsky Autonomous Region of the
Russian Federation. Since the date of acquisition, Arcticneft contributed
$0.320 million of net loss to the Group's operating results.
Management's purchase accounting allocation resulted in an excess of $16.8
million of net identifiable assets and oil and gas properties and equipment over
the purchase price. Management believes that this amount is attributed to the
seller's undervaluing of Arcticneft and its desire to dispose of non-core
assets. The associated gain was recorded in the Group's consolidated statement
of operations for the year ended 31 December 2005.
Acquisition of Urals-Nord. In April 2005, the Company acquired the remaining
50.0 percent interest in OOO Urals Nord ("Urals Nord") for $14 million. On that
date $1.5 million was paid immediately in cash and $12.5 million was paid in
October 2005. The Group incurred $0.84 million of additional cost related to
seismic review of the license areas. Urals Nord holds 5 exploration licenses
for Beluginisky, Zapadno-Sorokinskiy, Fakelniy, Nadezhdinskiy and Alfinskiy
Prospects. Urals-Nord has been consolidated from the date of acquisition.
Management believes that the purchase price for Urals-Nord approximates the fair
value of unproved oil and gas properties acquired. Such unproved oil and gas
properties are included within property, plant and equipment in the consolidated
balance sheet. No goodwill was recognized in the acquisition. Since the date
of acquisition, Urals-Nord contributed $0.035 million of net loss to the Group's
operating results.
Fair values of acquired companies. The table below discloses the carrying
values and fair values of the assets and liabilities of the companies acquired
during 2005 immediately prior to and upon acquisition, respectively. The values
disclosed below comprise 100 percent of the assets and liabilities of the
acquirees. The IFRS carrying values before the acquisition reported below
relate to the IFRS carrying values in the separate accounts of the acquirees.
Such stakes were revalued to their fair values at the acquisition date for
purposes of these consolidated financial statements.
Urals-Nord Arcticneft, Dinyu,
including Michayuneft
IFRS Fair IFRS Fair IFRS Fair
carrying values at carrying values at carrying values at
amounts acquisition amounts acquisition amounts acquisition
before before before
acquisition acquisition acquisition
Cash and cash equivalents - - 2,045 2,045 122 122
Accounts receivable and - - 1,719 1,719 4,224 4,224
prepayments
Other current assets - - 8,350 12,583 1,243 1,243
Oil and gas properties and 840 19,261 34,073 74,040 15,460 86,466
equipment
Other non-current assets - - 188 188 857 857
Short-term borrowings and 840 840 13,036 13,036 8,653 8,563
current portion of long-term
borrowings
Other current liabilities - - 20,425 20,425 5,574 5,574
Deferred income tax - 4,421 5,934 16,503 - 17,041
liability, non-current
Other non-current liabilities - - 784 784 - -
Summary combined financial information. The following table sets forth summary
combined financial information for the year ended 31 December 2005 that is
presented to provide information to evaluate the financial effects of the
acquisitions of Arcticneft, Dinyu and Urals-Nord as if they had occurred on 1
January 2005.
Group Urals-Nord Arcticneft Dinyu Adjustments Summary
results and
eliminations combined
Total revenues 92,918 - 22,154 31,831 (27,507) 119,396
Profit (loss) for the period 7,055 (35) (1,082) 2,354 (669) 7,623
The summary combined financial information should not be construed to represent
consolidated financial information. Group results include the activities of the
acquired entities from the respective acquisition dates through 31 December
2005. Total revenues and profit (loss) for the period for Urals-Nord,
Arcticneft and Dinyu comprise the respective entities' results for the full
year, including the period prior to acquisition, without adjustments for
intercompany transactions or fair values. Adjustments and eliminations include
the following: (a) depreciation, depletion and amortization was adjusted to
reflect the higher carrying values of property, plant and equipment following
fair value adjustments; (b) intercompany eliminations were recorded; (c)
adjustments to eliminate results of the period included both in the Group
results and the respective entities' results for the full year; and (d)
corresponding adjustments for income taxes were recorded. However, no
adjustments were made to adjust interest expense for borrowings used to finance
these acquisitions.
Acquisition of Petrosakh. In December 2004, the Group acquired a 97.2 percent
equity interest in Petrosakh for $46.9 million. Petrosakh is an integrated oil
and gas exploration and production company located on Sakhalin Island in the
Russian Far East. Petrosakh operates the Okruzhnoye and Pogranichnoye onshore
oil fields licenses and has an exploration license for the off-shore part of the
Pogranichnoye field. No goodwill was recognized on the acquisition of
Petrosakh.
Acquisition of CNPSEI. In November 2004, the Group acquired a 100.0 percent
equity interest in CNPSEI for $6.8 million. CNPSEI is an oil and gas
exploration and production company located in the Komi region of northern
Russia. CNPSEI operates the Sosnovskoye and Yuzhnotebukskoye onshore oil field
licenses. No goodwill was recognized on the acquisition of CNPSEI.
Acquisition of Chepetskoye. In October 2004, the Group acquired a 100.0 percent
interest in Chepetskoye, from one if its principal shareholders for nominal
consideration. Chepetskoye is an oil and gas exploration and production company
located in the Udmurtia region of the Russian Federation. Chepetskoye operates
the Zapadno-Krasnogorsky onshore oil field licenses.
This acquisition was contemplated as part of the Urals Energy Shareholder
Agreement dated 28 July 2004, whereby shareholders would contribute cash or
assets for their equity interests in Urals Energy (Note 12). Chepetskoye was
recognised initially at its fair value of $5.9 million.
Fair values of acquired companies. The table below discloses the carrying
values and fair values of the assets and liabilities of the companies acquired
during 2004 immediately prior to and upon acquisition, respectively. The values
disclosed below comprise 100.0 percent of the assets and liabilities of the
acquirees. The IFRS carrying values before the acquisition reported below
relate to the IFRS carrying values in the separate accounts of the acquirees.
Such stakes were revalued to their fair values at the acquisition date for
purposes of these consolidated financial statements.
Petrosakh CNPSEI Chepetskoye
IFRS Fair IFRS Fair IFRS Fair
carrying values at carrying values at carrying values at
amounts acquisition amounts acquisition amounts acquisition
before before before
acquisition acquisition acquisition
Cash and cash equivalents 373 373 1 1 158 158
Other current assets 2,540 3,776 1,016 1,016 654 654
Properties, plant and equipment 16,517 13,220 1,520 1,520 401 401
(excluding oil and gas
properties)
Oil and gas properties 6,439 60,698 3,264 7,886 7,529 15,768
Other non-current assets 59 59 - - - -
Short-term borrowings and 10,478 10,478 - - 8,650 8,650
current portion of long-term
borrowings
Other current liabilities 2,327 2,266 2,101 2,101 266 266
Deferred income tax 2,559 14,915 270 1,417 31 2,008
liability, non-current
Other non-current liabilities 2,205 2,205 105 105 155 155
Had these acquisitions been completed on 1 January 2004, consolidated revenues
and net loss would have been $33.7 million and $3.0 million, respectively, for
the year ended 31 December 2004.
5 Accounts receivable and prepayments
31 December:
2005 2004
Accounts and notes receivable - trade ($0.586 million and $0.608 7,871 70
million provision for impairment at 31 December 2005 and 2004)
Prepaid taxes, other than value added tax 4,408 410
Advances to suppliers 3,871 453
Recoverable taxes including VAT 3,503 1,720
Receivables from related parties (Note 19) 2,725 723
Other 1,410 330
Total accounts receivable and prepayments 23,788 3,706
6 Inventories
31 December:
2005 2004
Crude oil 3,252 1,184
Petroleum products 1,590 592
Materials and supplies 7,799 997
Total inventories 12,641 2,773
7 Property, Plant and Equipment
Activity within property, plant and equipment for the two years ended 31
December 2005 is detailed below.
Oil and gas Refinery and Buildings Other Assets Assets under Total
properties related construction
equipment
Cost
Balance at 31 December 2003 - - - - - -
Translation difference 1,933 124 14 57 50 2,178
Business combinations 84,876 8,560 975 3,582 1,770 99,763
Additions - - - 133 1,217 1,350
Transfers 579 - - - (579) -
Balance at 31 December 2004 87,388 8,684 989 3,772 2,458 103,291
Translation difference (5,129) (315) (41) (154) (219) (5,858)
Business combinations 172,110 615 1,100 650 5,405 179,880
Additions 4,697 - - 209 16,452 21,358
Transfers 8,053 - - 964 (9,017) -
Changes in estimates of (765) - - - - (765)
dismantlement provision
Disposals (217) - - (310) (325) (852)
Balance at 31 December 2005 266,137 8,984 2,048 5,131 14,754 297,054
Oil and gas Refinery and Buildings Other Assets Assets under Total
properties related construction
equipment
Accumulated Depreciation
Balance at 31 December 2003 - - - - - -
Translation difference (14) - - (1) - (15)
Depreciation, depletion (505) - - (17) - (522)
and amortization
Balance at 31 December 2004 (519) - - (18) - (537)
Translation difference 128 8 4 10 - 150
Depreciation, depletion (8,044) (510) (226) (614) - (9,394)
and amortization
Disposals 118 - - 94 - 212
Balance at 31 December 2005 (8,317) (502) (222) (528) - (9,569)
Net Book Value
Balance at 31 December 2004 86,869 8,684 989 3,754 2,458 102,754
Balance at 31 December 2005 257,820 8,482 1,826 4,603 14,754 287,485
Included within oil and gas properties at 31 December 2005 and 2004 were
exploration and evaluation assets of $140.5 million and $37.5 million,
respectively, including property acquisition costs with net book values of
$134.0 million and $37.5 million, respectively, not subject to depletion.
Additionally, included within oil and gas properties at 31 December 2005 and
2004 were property acquisition costs with net book value of $41.6 million and
$12.8 million, respectively, that were being depleted over total proved
reserves.
The Group's oil fields are situated in the Russian Federation on land owned by
the Russian government. The Group holds licenses and associated mining plots and
pays production taxes to extract oil and gas from the fields. The licenses
expire between 2008 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, amounting to $0.020 million and $0.198
million at 31 December 2005 and 2004, 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.
At 31 December 2005 and 2004, property, plant and equipment with carrying net
book value of $90.2 million and $1.6 million, respectively, was pledged as
collateral for the Group's borrowings.
8 Accounts Payable and Accrued Expenses
31 December:
2005 2004
Trade payables 2,809 236
Interest payable 833 224
Wages and salaries 806 278
Advances from and payables to related parties (Note 19) 77 861
Payable under guarantee arrangements (Note 19) - 1,073
Other payable and accrued expenses 3,407 1,076
Total accounts payable and accrued expenses 7,932 3,748
Of interest payable, $0.117 million was payable to related parties at 31
December 2004.
9 Taxes
Income taxes for the periods ended 31 December 2005 and 2004 comprised the
following:
Year ended 31 December:
2005 2004
Current tax expense 890 103
Deferred tax charge (benefit) (3,155) (280)
Income tax charge (benefit) (2,265) (177)
Below is a reconciliation of profit (loss) before taxation to income tax charge
(benefit):
Year ended 31 December:
2005 2004
Profit (loss) before income tax 4,708 (3,835)
Theoretical tax charge (benefit) 1,130 (920)
at the statutory rate of 24 percent
Excess of net assets acquired over purchase price (4,030) -
Non-recurring mobilization costs 1,721 -
Losses utilized in the current year (1,340) -
Tax credits related to seismic surveys (1,047) -
Expenses at other tax rates 939 -
Other income not assessable for income tax purposes - (10)
Other expenses and losses not deductible for income tax purposes 334 748
Effect of tax penalties 28 5
Income tax charge (benefit) (2,265) (177)
The movement in deferred tax assets and liabilities during the year ended 31
December 2005 was as follows:
2005 Recognized in Charged (credited) Effect of 2004
equity for to the statement of acquisitions
translation operations
differences
Deferred tax liabilities
Property, plant and equipment 52,620 (1,066) (1,883) 36,167 19,402
Inventories 90 (3) (1,479) 1,445 127
Payables 291 - 223 68 -
Borrowings received - (3) (142) - 145
Other taxable temporary differences 113 (2) 115 - -
Deferred tax assets
Receivables (155) 6 5 - (166)
Dismantlement provision (190) 7 219 (188) (228)
Payables (360) 14 158 (190) (342)
Inventories (114) 4 87 - (205)
Other deductible temporary (555) 19 (93) (429) (52)
differences
Tax losses (640) 16 (365) - (291)
Net deferred tax liability 51,100 (1,008) (3,155) 36,873 18,390
The movement in deferred tax assets and liabilities during the year ended 31
December 2004 was as follows:
2004 Recognized in Charged (credited) Effect of 2003
equity for to the statement of acquisitions
translation operations
differences
Deferred tax liabilities
Property, plant and equipment 19,402 372 (40) 19,070 -
Inventories 127 2 - 125 -
Borrowings received 145 2 - 143 -
Deferred tax assets
Receivables (166) (55) 21 (132) -
Dismantlement provision (228) (5) - (223) -
Payables (342) (5) - (337) -
Inventories (205) (3) - (202) -
Other deductible temporary (52) (20) 19 (51) -
differences
Tax losses (291) (11) (280) - -
Net deferred tax liability 18,390 277 (280) 18,393 -
There is no concept of consolidated tax returns in the Russian Federation and,
consequently, tax losses and current tax assets of different subsidiaries cannot
be set off against tax liabilities and taxable profits of other subsidiaries.
Accordingly, taxes may accrue even where there is a net consolidated tax loss.
Similarly, deferred tax assets of one subsidiary cannot be offset against
deferred tax liabilities of another subsidiary. At 31 December 2005 and 2004,
deferred tax assets of $2.000 million and $1.754 million, respectively, have not
been recognized for deductible temporary differences for which it is not
probable that sufficient taxable profit will be available to allow the benefit
of that deferred tax asset to be utilised.
The Group has not recognised deferred tax liabilities for temporary differences
associated with investments in subsidiaries as the Group is able to control the
timing of the reversal of those temporary differences and does not intend to
reverse them in the foreseeable future. At 31 December 2005 and 2004, the
estimated unrecorded deferred tax liabilities for such differences were $1.395
million and $0.638 million, respectively.
Taxes payable at 31 December 2005 and 2004 were as follows:
31 December:
2005 2004
Income taxes payable 6,039 387
Unified production tax 2,257 654
Value added tax 1,311 577
Other taxes payable 1,880 299
11,487 1,917
Total taxes payable
10 Borrowings
All borrowings outstanding at 31 December 2005 were denominated in US Dollars.
Short-term borrowings. Short-term borrowings and current portion of long-term
borrowings were as follows at 31 December 2005 and 2004.
31 December:
2005 2004
Loan from Alfa Eco M - 10,993
Related party borrowings - 27,493
Current portion of long-term borrowings 34,117 -
Total short-term borrowings and 34,117 38,486
current portion of long-term borrowings
Loan from Alfa Eco M. Alfa Eco M is related to previous shareholders of
Petrosakh (Note 4). The loan was rouble denominated, bore interest at 9.5
percent per annum and was fully repaid in June 2005.
Related party borrowings. At 31 December 2005 and 2004, outstanding borrowings
from related parties totalled nil and $27.5 million, respectively. The
borrowings, which were fully repaid or converted to shares of the Group during
2005, were unsecured and from shareholders and companies controlled by
shareholders. All borrowings were denominated in US dollars except those from
Nafta (B) NV, which were denominated in Euros.
The table below outlines all activity on related party borrowings outstanding at
31 December 2004.
Name of party 31 December 31 December 2004 Date of
2005 repayment/
conversion
(2005)
Shareholders - settled against unpaid capital
Hillsilk Limited - 330 March
Shareholders - converted to shares
Radwood Business Inc. - 500 August
Polaris Business Limited - 300 August
Citara International Limited - 5,000 August
Fantin Finance Limited - 3,000 August
Shareholders - converted to shares
and settled against unpaid capital
Texas Oceanic Petroleum LLC - 1,500 August
Controlled by shareholders - settled against unpaid capital
UEN Trading Limited - 8,660 March
Controlled by shareholders - converted to shares
Nafta (B) NV - 6,822 June
Other - 1,381
Total related party borrowings - 27,493
Shareholders. During 2005, the $0.330 million loan due to Hillsilk Limited and
$1.0 million of the $1.5 million loan due to Texas Oceanic Petroleum LLC were
converted to equity as settlement of the shareholders' unpaid share capital
balances (Note 12) and the remaining $0.5 million were converted to additional
shares of the Group (Note 12).
In July 2005, the Group amended its loan agreements with Radwood Business Inc.,
Polaris Business Limited, Citara International Limited, Fantin Finance Limited
and Texas Oceanic Petroleum LLC (who collectively at 31 December 2004, provided
$9.3 million, Libor plus 2.0 percent unsecured notes to the Group), whereby the
loan interest was restated to 15.0 percent per annum, effective retroactively to
the origination of the loan. In August 2005, the balance of the loans,
including unpaid interest, were extinguished by issuing 3,879,844 shares at a
conversion rate of $2.65 per share, the estimated fair value of the Group's
shares at the time the conversion was agreed.
In accordance with IAS 39, Financial Instruments, Recognition and Measurement,
this modification and conversion comprise an extinguishment of debt.
Accordingly, the difference of $0.6 million between the carrying value of the
borrowings at the time of the extinguishment and the fair value of the
consideration provided by the Group were recognized as a loss on extinguishment
of debt in the consolidated statement of operations.
Controlled by shareholders. During 2005, the $8.660 million loan due to UEN
Trading Limited was converted to equity as settlement of a portion of UEN Cyprus
Limited's unpaid share capital balance (Note 12).
In June 2005, the Group settled its obligation to Nafta (B) NV by issuing shares
at $2.65 per share (Note 12).
Long-term borrowings. Long-term borrowings were as follows at 31 December 2005
and 2004.
31 December:
2005 2004
BNP Paribas Reserve Based Loan Facility 69,000 -
Bank Zenit 12,000 -
Other 122 -
Subtotal 81,122 -
Less: current portion of long-term borrowings (34,117) -
Total long-term borrowings 47,005 -
BNP Paribas Reserve Based Loan Facility. In November 2005, the Group closed a
five year, revolving Reserve Based Loan Facility with BNP Paribas, underwritten
to a maximum commitment of $100.0 million. In November 2005, the maximum amount
then available of $69.0 million was drawn. The facility is divided into a
senior conforming tranche of $59.0 million that bears interest at LIBOR plus 5.0
percent and a junior non-conforming tranche of $10.0 million priced at LIBOR
plus 6.25 percent. Both tranches are repayable in full in December 2010. The
loan was collateralized by liens on property, plant and equipment of
subsidiaries (Note 7). The Group is subject to certain financial and other
technical covenants under the BNP Paribas Reserve Based Loan Facility including
the maintenance of a minimum financial ratios. The Group is in compliance with
its covenants under the facility at 31 December 2005.
Bank Zenit. In March 2005, the Chepetskoye and CNPSEI entered into two loan
agreements with Bank Zenit totalling $12.0 million. The loan agreements bore
interest at 11.0 percent per annum and were scheduled to mature in March 2010.
The loans contained cross default provisions and were collateralized by liens on
property, plant and equipment of these subsidiaries (Note 7). This loan was
repaid in February 2006.
BNP Paribas Bank Credit Facility. In June 2005, the Petrosakh entered into a
$20.0 million, 18 month per-export credit facility with BNP Paribas Bank. This
variable interest debt facility bore interest at LIBOR plus 5.0 percent and was
originally repayable in December 2006. This facility was repaid in full in
November 2005.
RP Capital Group. In July 2005, the Group entered into a 10.0 percent
convertible preferred note agreement with RP Capital Group for up to $15.0
million. In the event of a qualifying initial public offering ("IPO") the notes
were convertible into ordinary shares at a 20 percent discount to the IPO price.
In July 2005 the Group issued $10.0 million of the convertible notes at par.
These notes were converted into 2,929,651 shares in August 2005. No gain or
loss was recognized on conversion.
Scheduled maturities of long-term borrowings outstanding were as follows:
Scheduled maturities
at 31 December:
Year ended 31 December: 2005 2004
One year 34,117 38,486
Two to five years 47,005 -
Thereafter - -
Total long-term borrowings 81,122 38,486
11 Dismantlement Provision
The dismantlement provision represents the net present value of the estimated
future obligation for dismantlement, abandonment and site restoration costs
which are expected to be incurred at the end of the production lives of the oil
and gas fields. The discount rate used to calculate the net present value of the
dismantling liability was 13.0 percent.
Year ended 31 December:
2005 2004
Opening dismantlement provision 950 -
Translation difference (21) 20
Acquisitions 785 920
Additions 20 -
Changes in estimates (1,145) -
Change due to passage of time 224 10
Closing dismantlement provision 813 950
As further discussed in Note 17, environmental regulations and their enforcement
are under development by governmental authorities. Consequently, the ultimate
dismantlement, abandonment and site restoration obligation may differ from the
estimated amounts and this difference could be significant.
12 Equity
At 31 December 2005, the Group's authorized ordinary shares were 100 million,
each having a par value of 0.0025 Cypriot pounds, of which 86.9 million were
issued and outstanding shares at 31 December 2005.
In January 2006, the Group's shareholders approved a resolution increasing the
authorized shares by 20 million to 120 million.
Share activity and other capital contributions for the two years ended 31
December 2005 are outlined below. All share amounts have been given retroactive
effect for the 400:1 share split executed in July 2005.
Number of Share Share Unpaid
shares capital premium capital
(thousands of
shares)
Balance at 31 December 2003 4,000 20 10 -
Share issuance 36,000 189 41,291 (11,324)
Contribution from shareholders - - 871 -
Balance at 31 December 2004 40,000 209 42,172 (11,324)
Partial conversion of - - - 1,000
Texas Oceanic Petroleum LLC loan
Conversion of UEN Trading Limited loan - - - 8,660
Conversion of Hillsilk Limited - - - 330
Conversion of other related party loans - - - 1,027
Issuance of shares to Nafta (B) NV 9,434 50 24,950 -
Conversion of shareholder loans 3,880 20 10,261 -
Conversion of RP Capital Group loan 2,930 16 9,984 -
Shares issued for cash 30,667 165 113,946 -
Unpaid capital received in cash - - - 307
Share-based payment - - 42 -
Balance at 31 December 2005 86,911 460 201,355 -
Urals Energy was created on 10 November 2003. Share capital at incorporation
comprised 10,000 authorized and issued ordinary shares with a nominal value of
one Cyprus Pound (CYP). In July 2004, the shareholders signed a Shareholder
Agreement (the "Agreement") whereby, the Group issued an additional 90,000
ordinary shares for total consideration of $41.5 million. The share issuance
was settled with in-kind contributions with a fair value of $17.5 million
(comprising a 100 percent interest in Chepetskoye valued at $5.9 million,
shareholder advances to group companies totalling $9.7 million and expenses
incurred on behalf of the Group totalling $1.9 million) and cash of $24.0
million. At 31 December 2004, $11.3 million of the cash contributions remained
unpaid.
In addition to contributions in accordance with the Shareholder's Agreement,
during 2004, the shareholders also contributed their equity interest in OOO
Urals Energy with a fair value of $0.9 million. This contribution was recorded
as additional paid-in capital.
Partial conversion of Texas Oceanic Petroleum LLC loan. In May 2005, $1.0
million of the $1.5 million loan due to Texas Oceanic Petroleum LLC was
converted to equity as settlement of Texas Oceanic Petroleum's unpaid share
capital (Note 10). The remaining balance was converted to shares of the Group.
Conversion of UEN Trading Limited loan. In March 2005, the $8.660 million loan
due to UEN Trading Limited was converted to equity as settlement of UEN Cyprus
Limited's unpaid share capital (Note 10).
Issuance of shares to Nafta (B) NV. In June 2005, the Group issued 9,434
ordinary shares to Nafta (B) NV, a company owned in majority by two of the
shareholders, for total consideration of $25.0 million. The share issuance was
settled with a cash contribution of $18.4 million and conversion of $6.6 million
in existing debt of Nafta B.
Conversion of shareholder loans. In August 2005, the Group extinguished its
loans from Radwood Business Inc., Polaris Business Limited, Citara International
Limited, Fantin Finance Limited and Texas Oceanic Petroleum LLC by issuing
3,879,844 shares at a conversion rate of $2.65 per share (Note 10).
Conversion of RP Capital Group loan. In August 2005, the Group extinguished
$10.0 million of debt outstanding to RP Capital Group by issuing 2,929,651
shares (Note 10).
Shares issued for cash. In August 2005, the Group completed an initial public
offering of its shares. As part of the offering, the Group issued 30,667,050
shares in exchange for $114.1 million, net of transaction costs.
Share-based payments. During 2005, the Group granted a share-based award to one
of its officers. Under the award, the officer shall have the option to purchase
a certain number of the Group's shares at a share price equal to $131 million
divided by the number of Group shares that are issued and outstanding at both 1
August 2006 and 1 August 2007. The option is in two parts comprised of the
number of shares that can be purchased for a payment of $125,000 on 1 August
2006 and of $125,000 on 1 August 2007, which are the respective vesting dates of
the two parts of the award. The officer is required to be continuously employed
by the Group through the vesting dates. Notification of intent to purchase must
be submitted within three days of the respective dates, and payment and delivery
of shares to the officer are to occur within 15 days of the respective dates.
During 2005, the Group estimated the total fair value of the award to be $0.067
million, of which $0.042 million was recognized during 2005 within selling,
general and administrative expenses, with respect to this award. The full
amount of the award is being recognized over its vesting period. The
Black-Scholes option valuation model, used for valuing this award, was developed
for use in estimating the fair value of traded options that have no vesting
restrictions and are fully transferable. In addition, this option valuation
model requires the input of highly subjective assumptions, including the
expected stock price volatility. As the Group's shares were not publicly traded
at the time of the grant of this award, management estimated the volatility
measure through consultation with independent experts. Changes in the
subjective input assumptions can materially affect the fair value estimate.
Based on the assumptions below, the weighted average fair value of this option
was estimated to be $0.067 million. Significant assumptions included in the
option valuation model are summarized as follows.
Share price $2.65
Dividend yield -
Expected volatility 25.00%
Risk-free interest rate 4.00%
Expected life 1-2 years
13 Revenues
Year ended 31 December:
2005 2004
Crude oil
Export sales 69,177 2,546
Domestic sales (Russian Federation) 13,433 3,774
Petroleum (refined) products - domestic sales 9,904 1,643
Other sales 404 221
Total gross revenues 92,918 8,184
14 Cost of Production
Year ended 31 December:
2005 2004
Depreciation and depletion 8,285 507
Unified production tax 16,829 1,394
Cost of purchased products 12,455 -
Wages and salaries (including payroll taxes of $1.457 million and 7,341 647
$0.230 million for the years ended 31 December 2005 and 2004, respectively)
Materials 2,276 189
Other 3,256 1,615
Total cost of production 50,442 4,352
15 Selling, General and Administrative Expenses
Year ended 31 December:
2005 2004
Wages and salaries 5,179 1,197
Audit and professional consultancy fees 2,542 2,767
Office rent and other expenses 1,522 759
Other taxes 1,338 312
Transport and storage services 998 102
Loading services 845 -
Loss on disposal of assets 254 14
Other expenses 1,290 1,674
Total selling, general and administrative expenses 13,968 6,825
16 Mobilization Costs
The Group's mineral licenses require that the Group perform certain exploration,
evaluation and development activities as a condition of maintaining and/or
renewing the licenses. During 2005, the Group entered into an agreement with
KCA Deutag to provide a specialized drilling rig for the purpose of obligatory
exploratory drilling on one of the Group's properties on Sakhalin Island. As
part of the agreement, the Group was required to transport the rig approximately
5,000 kilometres to reach Sakhalin Island. By disclosing the agreements to
secure and transport the rig, management was able to demonstrate to the
licensing authorities its commitment to fulfilling its obligations under the
license. However, due to delays in transportation and seasonal weather
concerns, the Group was forced to terminate its agreement and abort the
transport prior to the rig's arrival to Sakhalin Island, resulting in
mobilization costs of $7.2 million being expensed during 2005.
The Group was subsequently able to modify an existing rig to drill an
exploratory well on the property in order to maintain compliance with the
license terms.
17 Contingencies, Commitments and Operating Risks
Operating environment of the Group. Whilst there have been improvements in
economic trends in the country, the Russian Federation continues to display
certain characteristics of an emerging market. These characteristics include,
but are not limited to, the existence of a currency that is not freely
convertible in most countries outside of the Russian Federation, restrictive
currency controls, and relatively high inflation. The tax, currency and customs
legislation within the Russian Federation is subject to varying interpretations,
and changes, which can occur frequently.
The future economic direction of the Russian Federation is largely dependent
upon the effectiveness of economic, financial and monetary measures undertaken
by the Government, together with tax, legal, regulatory, and political
developments.
Sales and royalty commitments. In accordance with Petrosakh's license terms,
Petrosakh is required to sell 20.0 percent of its annual oil production in the
form of petroleum products to the Sakhalin Island region at market prices.
In accordance with the sale purchase agreement to acquire Petrosakh, the Group
agreed to pay a perpetual royalty to the previous shareholders of $0.25 per ton
of crude oil produced from the currently unproved off-shore licensed area.
Exploration licenses - investment commitments. The Company's application for an
extension of the Pogranichnoye License area offshore Sakhalin Island has been
successful. The Russian Federal Agency for Natural Resources granted the
license extension in January 2006. The license period was extended to 1 February
2011 and the terms of the amended license now require a total of five
exploration wells to be drilled during the period 2005-2010. The East Okruzhnoye
No. 1 well spudded in 2005 will qualify as the first of the five exploration
wells required by the amended license. Management currently estimate such
expenditure to approximate $19.0 million.
Urals Nord has five geological studies licenses which expire in January 2008.
According to the license agreement terms Urals Nord is required to drill
exploration wells and perform seismic works. Management currently estimate such
expenditure to approximate $36 million.
Other capital commitments. At 31 December 2005 and 2004 the Group had no other
significant contractual commitments for capital expenditures.
Taxation. Russian tax, currency 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 regional and federal authorities.
Recent events within the Russian Federation suggest that the tax authorities may
be taking a more assertive position in their interpretation of the legislation
and assessments, and it is possible that transactions and activities that have
not been challenged in the past may be challenged. As a result, significant
additional taxes, penalties and interest may be assessed. Fiscal periods remain
open to review by the authorities in respect of taxes for three calendar years
preceding the year of review. Under certain circumstances reviews may cover
longer periods.
As at 31 December 2005 and 2004 management believes that its interpretation of
the relevant legislation is appropriate and the Group's tax, currency and
customs positions will be sustained. Where management believes it is probable
that a position cannot be sustained, an appropriate amount has been accrued for
in these financial statements.
Insurance policies. At 31 December 2005, the Group held limited insurance
policies in relation to its assets, operations, or in respect of public
liability or other insurable risks. Since the absence of insurance alone does
not indicate an asset has been impaired or a liability incurred, no provision
has been made in these financial statements.
Restoration, rehabilitation and environmental costs. The Group companies have
operated in the upstream and refining oil industry in the Russian Federation for
many years and its activities have had an impact on the environment. The
enforcement of environmental regulations in the Russian Federation is evolving
and the enforcement posture of government authorities is continually being
reconsidered. The Group periodically evaluates its obligation related thereto.
The outcome of environmental liabilities under proposed or future legislation,
or as a result of stricter enforcement of existing legislation, cannot
reasonably be estimated at present, but could be material. Under the current
levels of enforcement of existing legislation, management believes there are no
significant liabilities in addition to amounts which are already accrued and
which would have a material adverse effect on the financial position of the
Group.
Legal proceedings. During the year, the Group was involved in a number of court
proceedings (both as a plaintiff and a defendant) arising in the ordinary course
of business. In the opinion of management, there are no current legal
proceedings or other claims outstanding, which could have a material effect on
the result of operations or financial position of the Group and which have not
been accrued or disclosed in these consolidated financial statements.
Oilfield licenses. The Group is subject to periodic reviews of its activities
by governmental authorities with respect to the requirements of its oil filed
licenses. Management of the Group correspond with governmental authorities to
agree on remedial actions, if necessary, to resolve any findings resulting from
these reviews. Failure to comply with the terms of a license could result in
fines, penalties or license limitations, suspension or revocations. The Group's
management believes any issues of non-compliance will be resolved through
negotiations or corrective actions without any materially adverse effect on the
financial position or the operating results of the Group.
18 Financial Risks
Foreign exchange risk. The Group has substantial amounts of foreign currency
denominated long-term borrowings and is thus exposed to foreign exchange risk.
Foreign currency denominated assets and liabilities give rise to foreign
exchange exposure. The Group does not have formal arrangements to mitigate
foreign exchange risks.
Interest rate risk. The Group's income and operating cash flows are
substantially independent of changes in market interest rates. The Group obtains
funds from, and deposits its cash surpluses with, banks at current market
interest rates, and does not utilize hedging instruments to manage its exposure
to changes in interest rates. The details of interest rates associated with the
Group's borrowings are discussed in Note 10. The carrying value of the Group's
receivables, payables and borrowings approximate their fair values (Note 3).
Credit risk. Financial assets, which potentially subject Group entities to
credit risk, consist principally of trade receivables. The Group has policies
in place to ensure that sales of products and services are made to customers
with an appropriate credit history. The carrying amount of accounts receivable,
net of provision for impairment of receivables, represents the maximum amount
exposed to credit risk. The Group has no other significant concentrations of
credit risk. Although collection of receivables could be influenced by economic
factors, management believes that there is no significant risk of loss to the
Group beyond the provision already recorded.
Cash is placed in financial institutions, which are considered at time of
deposit to have minimal risk of default.
Commodity and pricing risk. The Group's operations are significantly affected
by the prevailing price of crude oil both in the international oil market and in
the Russian Federation. Crude oil prices have historically been highly
volatile, dependent upon the balance between supply and demand and particularly
sensitive to OPEC production levels. Crude oil prices in the Russian Federation
are below international levels primarily due to constraints on the export of
crude oil. Also, domestic crude oil prices are contract specific as there is no
active market for domestic crude oil and marker prices are not available. There
is typically no straight correlation between domestic and international oil
prices. The Group's subsidiary - Petrosakh, operates on Sakhalin Island where
the surrounding ocean is not navigateable for several months of the year, this
further increases the exposure to commodity price risk.
19 Related-Party Transactions
For the purposes of these financial statements, parties are considered to be
related if one party has the ability to control the other party, is under common
control, or can exercise significant influence over the other party in making
financial or operational decisions as defined by IAS 24 Related Party
Disclosures. In considering each possible related party relationship, attention
is directed to the substance of the relationship, not merely the legal form.
Trading relationship with related parties. The Group has transactions in the
ordinary course of business with ZAO NC Urals, ZAO "Chepetskoye" NGDU (through
July 2004, when contributed by the Group shareholder to Urals Energy), Urals ARA
NV and Nafta (B) NV which all are controlled by major shareholders. These
transactions include sales and purchases of crude oil and petroleum products.
Such sales ended beginning September 2005. Below are the annual sales,
purchases and receivables balances for each year presented:
As of or for the year
ended 31 December:
2005 2004
Sales of crude oil on export markets 5,515 2,212
Associated volumes, tons 17,580 9,000
Sales of petroleum products on domestic markets - 212
Associated volumes, tons -
Purchases of crude oil - 1,178
Associated volumes, tons - 10,950
Commission revenue 24
Interest income - -
Interest expense 77 135
Management fees received - 208
Rental fees paid (included in selling, general and administrative expense) 306 264
Other expenses 790 232
Accounts and notes receivable 1,474 -
Loans receivable 1,251 723
Other payables and accrued expenses 74 61
Trade advances received 3 800
Lending relationships with related parties. See Note 10 for details of loans
from shareholders and from companies controlled by shareholders.
Guarantees issued to parties related to previous shareholders of subsidiaries.
In September 2004, CNPSEI issued a $1.5 million guarantee to secure borrowings
of OOO Neftegazrazvitiye, a former shareholder. The loan bore interest of 14.0
percent per annum. OOO Neftegazrazvitiye defaulted on its obligations and
therefore failed to repay the loan. CNPSEI, as the guarantor repaid a portion
of the loan during 2004 and the remainder during 2005. The Group's obligation
was recognised at its fair value in the purchase price adjustment in the
accompanying financial statements. Accordingly, there was no impact on the
Group's statement of operations for the years ended 31 December 2005 and 2004.
Compensation to senior management. The Group's senior management team comprises
10 people whose compensation totalled $4.174 million and $1.917 million for
the periods ended 31 December 2005 and 2004, respectively, including salary and
bonuses of $4.106 million and $1.917 million respectively, and stock
compensation of $0.042 million and nil, respectively, and no other compensation
was paid for both years.
20 Subsequent Events
Subordinated loan. In January 2006, the Group obtained a $12.0 million
subordinated loan from BNP Paribas. The subordinated loan bears interest at
LIBOR plus 5.0 percent and is repayable over five years in one payment on 10
November 2010. Attached to the subordinated loan were warrants to purchase up
to two million of the Group's common stock for #3.03. The warrants are
exercisable at any time and expire in November 2010. The Group used the
proceeds from the subordinated loan to repay its debt to bank Zenit of $12.0
million.
Share-based payments. In February 2006, the Group's Board of Directors approved
a Restricted Stock Plan (the "Plan") authorizing the Compensation Committee of
the Board of Directors to issue restricted stock of up to five percent of the
outstanding shares of the Group. Upon adoption, the Group issued 1,561,725
shares of restricted stock. The vesting schedule for the restricted stock
varies by individual award and, of the February 2006 grant, 1,040,445 shares,
260,625 shares and 260,625 shares vest on 1 January 2007, 2008 and 2009,
respectively.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR XDLLFQZBXBBK
Grafico Azioni Urals Energy (LSE:UEN)
Storico
Da Giu 2024 a Lug 2024
Grafico Azioni Urals Energy (LSE:UEN)
Storico
Da Lug 2023 a Lug 2024
