RNS Number:7228V
Urals Energy Public Company Limited
30 April 2007
Urals Energy Public Company Limited
Results for the year ended 31 December 2006
Urals Energy ("Urals Energy", the "Company" or the "Group") (LSE: UEN) a leading
independent exploration and production company with operations in Russia today
announces its results for the year ended 31st December 2006 and the latest
estimates published by DeGolyer and MacNaughton for its total proven, probable
and possible petroleum reserves and value of these reserves as at 31 December
2006.
Reserves Upgrade
* 2P reserves increase of over 400% to 577 mmboe (2005 116 mmbbls);
incorporating acquisition of Dulisma and its oil (96 mmboe), condensate (46
mmboe) and gas (322 mmboe) reserves all now fully booked as proved and
probable
* 152% year on year increase in the PV10 of the Group's 2P reserves to
$1,804 million (2005 $717 million)
Financial Highlights
* 83 % increase in total revenues to $169.6 million (2005 $92.9 million)
* Operating profit of $34.1 million (2005 $11.3 million)
* Five fold increase in post tax profit to $34.4 million (2005 $6.9 million)
* 36% increase in EBITDA to $22.9 million (2005 $16.9 million)
* Strengthened financial position following $209 million equity capital
raising and $144 million Dulisma project loan and other financing
Operational Highlights:
* 82% year on year increase in average production to 9,569 bopd (2005:
5,263 bopd)
* Production forecasted at 15,000 bopd by 4Q07 and 19,000 bopd by 2Q08
* Dulisma funding in place and development operations commenced with link-up
to Transneft's ESPO expected in 2008-09. Dulisma production forecasted
to peak at 30,000 bopd and 71,000 mcf sales gas per day in 2013;
o Approvals in place to link pipeline to ESPO
o Dulisma 2007 development programme underway and all equipment in
place including 160 ton mobile drilling rig, gas-electric
generator and field camp to spud first development well in July
2007
o Announcement of Dulisma gas strategy to exploit 1.9 tcf 2P reserve
base
o Commercial agreement to be signed to sell future gas production
from Dulisma
* Commencement of Mineral Extraction Tax holiday at Dulisma through 2016,
saving an estimated $308 million over a 10 year period
* Announcement of spudding of Nadezhdinsky No. 1 exploration well in northern
Timan Pechora to test 60 million barrel target
* 5 year extension of Pogranichnoye offshore exploration licence, Sakhalin
Island
* Fracture stimulation programme commenced and underway at Petrosakh,
Sakhalin Island
* Extension of development licence for deeper Permian horizon at
Peschanoozersky Field, Arcticneft
Corporate
* Appointment of Leonid Y. Dyachenko as CEO, reflecting Urals Energy's
increasing position and profile in Russia
* William R. Thomas remains on the Board as a Non-Executive Director
* J. Robert Maguire, most recently the head of the Global Energy Group at
Morgan Stanley, to be appointed Non Executive Director
* Alexei V. Ogarev, current Urals Energy VP Government Relations and former
Deputy Head of Russian Presidential Administration, to be appointed
Executive Director
* Key Management team strengthened following appointments of
o William S. Hayes, Senior Vice President and General Counsel
o Maxim V. Bezriadin, Vice President and Business Unit Manager, East
Siberia
o Stephen D. Kirton, Vice President, Technical Services
Acquisitions
* Further 2 acquisitions in 2006
o $148 million acquisition of OOO Dulisma and OOO LTK
o $1.5 million acquisition of OOO Nizhny Omrynskoye Neft
Current Operations and Outlook
* Average production for 1Q07 lower than anticipated at 8,900 bopd
* Several technical factors impacting production addressed and current
production capability of c.10,700 bopd
* Ongoing fraccing program, new wells and return to production at Dulisma
should allow production targets of 15,000 bopd in Q407 and 19,000 in Q208 to
be achieved
* Revised Company production target of 50,000 bopd by 2013 per new D&M
report.
* $93.4 million capex programme in 2007
* Continual appraisal of potential acquisition opportunities
Leonid Y. Dyachenko, newly appointed Chief Executive, commented:
"Urals Energy made substantial progress last year laying the foundations to
become a significant producer in Russia over the next five years. With an
intense development programme underway and a continued focus on acquisitions I
believe we have all the fundamentals in place to achieve strong future growth
and become a major Russian independent operator. The Board would like to thank
Bill Thomas for his significant contributions to the Company's success. As CEO,
he has led Urals Energy since our formation in 2003 and was instrumental in
positioning the Company for the next stage of growth and value creation. I am
delighted that Bill will remain with Urals Energy as a Non-Executive Director
going forward."
30 April 2007
Pelham PR
James Henderson 020 7743 6673
Gavin Davis 020 7743 6677
CEO'S STATEMENT
2006 was an important year of growth for Urals Energy as we completed our
largest and most important acquisition, OOO Dulisma, and continued to
consolidate and invest in our seven other operating subsidiaries in Russia. The
Company grew significantly in all respects: reserves, production, cash flow and
profits. As a result, we are well positioned to continue our strategy of growth
by both developing our existing assets and making further significant, accretive
acquisitions.
Operationally, we invested over $60 million in our properties, almost half in
development drilling. This was important in increasing production to an average
of 9,569 BOPD versus 5,263 BOPD in 2005 -- an increase of 82%. Importantly, we
have also purchased and transported to the field site at Dulisminskoye all
necessary equipment to begin drilling operations, including our 160 ton mobile
drilling rig. This provides us the capability to begin development operations
and prepare the field for full-scale production operations as the East Siberian
Pacific Ocean ("ESPO") pipeline nears completion of its first phase of
construction.
Since the acquisition of Dulisma in June 2007, we have worked to finalize a new
field development plan for the Dulisminskoye field. With our new drilling rig
in place, we expect to spud our first development well in July and drill and
complete a total of three development wells by the 2nd quarter of 2008.
Successful completion of these wells is necessary to achieve our production rate
targets. Production timing is contingent on the pace of development drilling,
and the completion of the East Siberia Pacific Ocean pipeline (ESPO) and our
link-up with this important new export pipeline. Based on the latest
information regarding the progress of the ESPO's development, our stated goal of
a 2007 year-end production rate of 19,000 BOPD will now shift to the 2nd quarter
of 2008.
We are announcing today an important increase in our proved and probable
reserves as evaluated by DeGolyer & MacNaughton, our independent reserve
engineers. Based on our work to monetize the large gas and condensate reserves
at Dulisminskoye, we are now upgrading the gas and condensate at Dulisminskoye
to proved and probable from possible. This is a result of our active
negotiations to finalize a long-term gas sales agreement, which we expect to
complete in the next few months. Year on year and on a barrel of oil equivalent
basis, 2P reserves have increased from 116 million barrels to 577 million
barrels. Please note that the D&M estimates for both oil and gas at
Dulisminskoye, and indeed for all of our properties, are less than the Russian
state reserves reported by the Ministry of Natural Resources.
Most importantly, the present value of our reserves has also increased
significantly. As a result of the now confirmed production tax holiday at
Dulisma and the incremental value attributable to the development of our gas and
condensate reserves, the Company's 2P reserves now carry a total present value
discounted at 10% equal to $1.8 billion. We believe this is strong indication
of the underlying asset value of our oil and gas reserves.
Financial Results
The Group benefited during the year from its increasing production profile
generating an 83% increase in total revenues to $169.6 million (2005: $92.9
million). This contributed to a three-fold increase in operating profits of
$34.1 million (2005: $11.3 million) and a five fold rise in post-tax profits of
$34.4 million (2005: $6.9 million). EBITDA increased by 36% to $22.9 million.
The Group realised a weighted average dollar price of $48.39 per barrel of oil
sold in 2006 compared with $44.35 per barrel in 2005. The average net revenues
per barrel for the Group increased slightly for the year at $34.40 compared to
$31.57 in 2005.
During the course of the year the Group raised a net total of $195 million in
new equity through Morgan Stanley. These funds enabled us to complete the
acquisition of Dulisma and commence the development work. In January of this
year we raised a further $130 million through Goldman Sachs under a new debt
finance facility. This financing will give us the required funding to develop
Dulisminskoye's oil reserves, thereby increasing production from that field to
its projected peak level of 30,000 bopd by 2011. We also raised an additional
$14 million in other debt from BNP Paribas.
The Group's cash position at the year end was $33 million. Following the Dulisma
project financing in January, the Group's current cash balance stands at
approximately $80 million.
During 2007 our capital expenditure programme is expected to be approximately
$93 million. Approximately $42 million will be dedicated to the Dulisma
development programme (funded through the Goldman Sachs debt finance facility
referred to above) and $51 million will be invested in increasing production in
our other producing fields.
Corporate
We have today announced the appointment of Leonid Y. Dyachenko as Chief
Executive. Mr Dyachenko has been a director of Urals Energy since the Company
was founded and for the last two years has managed the Group's day-to-day
activities within Russia based in our Moscow office. Over the next few years
Urals Energy will become an important independent oil and gas producer within
Russia, producing an estimated 50,000 bopd and over 71,000 mcf sales gas per day
by 2013. Leonid Dyachenko's appointment reflects Urals Energy's development into
a prominent Russian oil and gas business.
I will continue my involvement with Urals Energy as a non-executive member of
the board of directors. My resignation is effective immediately but I have
agreed to assist in the transition of management responsibilities through 30
June 2007.
The Group is also announcing today the appointment of two additional directors:
J. Robert Maguire and Alexei V. Ogarev. Bob Maguire is one of the most
experienced international oil and gas investment banking advisers within the
industry, with over 30 years experience, most recently as head of the Global
Energy Group at Morgan Stanley. His expertise will prove invaluable to the
Company through its next stage development.
Alex Ogarev is Urals Energy's VP of Government Relations and has an important
record of Russian government service including Deputy Head of the Presidential
Administration, and General Director of Rosvooruzhenie, the Russian arms export
agency. He plays an important role in managing our government relations and will
provide the board a valuable insight to the Russian government and political
environment.
We also recently strengthened the management team with the appointments of
William S. Hayes as Senior Vice President and General Counsel and Maxim V.
Bezriadin as Vice President and Business Unit Manager, East Siberia, together
with Stephen D. Kirton as Vice President, Technical Services. Following these
appointments we are confident we have the right level of management support in
place for the future.
Operations
Production Update
We ended the year at a producing rate of approximately 11,600 bopd. Since then
we have seen a temporary production decline due to several factors, including
shutting-in wells for the Petrosakh frac program, shut-in production at Dulisma
due to pipeline repairs by the pipeline owner, and a decline in reservoir
pressure at Dinyu and Petrosakh. As a result, actual production for the first
quarter averaged approximately 8,900 BOPD. However, we have taken steps to
restore production and, including the temporarily shut-in production at Dulisma,
we now have the capability to produce approximately 10,700 BOPD.
During the year, we acquired and refurbished a fleet of fracture stimulation
equipment, including three pumping units. Operations commenced at Petrosakh in
January 2007 and we are confident of significantly increasing production through
fracture stimulation at Petrosakh and other selected producing subsidiaries.
As we bring new wells online and the fraccing program continues, we expect our
production level to increase to approximately 15,000 BOPD in the fourth quarter
of 2007.
Dulisma
Following completion of the Dulisma acquisition in June 2006, the Group has been
actively executing its development programme targeting peak production of 30,000
bopd by 2011. Progress is being made on all fronts, with all Government
approvals for the field development program received. The Group has also
received approval from Transneft to accept oil produced at Dulisma for its ESPO
pipeline, thus providing the Dulisma field future permanent export pipeline
access for its crude oil production. The re-routing of the ESPO to within 75 km
of the Dulisma field, reduced initial cost estimates for construction of the
pipeline from the field to the ESPO tie-in by approximately $70 million, and
brings forward our production profile.
In January this year we announced that the Irkutsk Tax Inspectorate had
confirmed the 10 year tax holiday for the Dulisminskoye field for the period
between 1 January 2007 and 31 December 2016. This tax holiday is estimated to
produce savings of approximately $308 million over the 10 year period and
further exemplifies the importance of this asset to Urals Energy.
Development activity at Dulisminskoye is moving forward in accordance with our
plans announced last year. The new 160 tonne mobile drilling rig and all
associated equipment are at the field site and rigging-up operations are
underway. The first development well will be spudded in July, with a two further
development wells scheduled for the fourth quarter of 2007 and first quarter of
2008.
Road and pad construction is continuing in the field and we are working to
commission two gas-turbine generators to provide power for drilling and
production operations. A new 100-man field camp will be installed during the
winter of 2007. Construction of a central processing facility (CPF) and the
connecting pipeline to Kirensk will begin later this year in time for the
delivery of pipeline quality oil when the ESPO is commissioned in 2008-9.
Our 2007 CAPEX budget for Dulisma will be approximately $42 million of which $16
million is for development drilling and $26 million for pipelines,
infrastructure and facilities.
We are preparing a gas monetization plan that includes burning associated gas to
generate in-field electricity, stripping liquids to create a separate sales
stream of condensate and natural gas liquids, reinjecting certain gas volumes to
maintain reservoir pressure and entering into a long term gas sales agreement
with a large gas end-user. We expect to announce the terms of this agreement
over the next few months and provide further details about the gas monetization
plan.
Sakhalin Island
Production during the year averaged 3,159 bopd compared with 2,524 bopd in 2005.
During the year we drilled two development wells and three re-entry wells. Our
first offshore exploration well; the Pogranichny No. 1 well, was drilled at the
beginning of 2006 to a depth of approximately 2,100 meters but failed to
encounter commercial volumes of oil or gas. This well has been followed up with
an intense 3D seismic reprocessing and reinterpretation programme. Offshore
drilling is expected to resume in the summer of 2008.
In January 2006 we agreed a five year extension to our offshore exploration
licence in Sakhalin Island with the Ministry of Natural Resources. This will
allow us to fully exploit the licence area which has a potential of over 850
million barrels in place. In March, we received approval to lift Petrosakh
crude oil using foreign-flagged vessels through 2009. We believe this is a first
for any oil-exporting company on Sakhalin Island and will enable us to more
efficiently schedule tankers to lift our export cargoes.
Fraccing operations commenced at Petrosakh in January 2007 and the first four
wells have been completed. A total of eight wells are planned to be fracture
stimulated. Based on the preliminary results of the first four wells, we have
increased individual well rates by 3-4 times the production rate prior to
fraccing. There is no assurance this level of increase will be achieved in every
well, but we are confident of significantly increasing production through
fracture stimulation at Petrosakh and certain of our other producing
subsidiaries.
During 2007 six development wells are planned. The results of our most recent
well, PS47, indicate a possible new pool discovery that may open up several
drilling locations. We are also now commissioning three new oil products storage
tanks and constructing two new 10,000 ton crude oil storage tanks for oil
exports.
Komi Republic
During the year production at Komi averaged 3,937 bopd compared with 3,349 bopd
2005. In 2006 the Group drilled 8 development and 2 exploration wells in Dinyu.
In particular the DN-48 exploration well drilled in third quarter of 2006, to
test an extension of the Dinyu field to the Southeast, encountered a previously
unidentified reef structure with over 60 meters of permeable limestone
reservoir. After extensive testing, the well produced only small quantities of
live oil, but has consequently opened up a new potential play within the Dinyu
license area. We are working to identify additional prospects to prove this
hypothesis.
In the first quarter of 2006 we completed the acquisition of approximately 300
kilometres of new 2D seismic over the Dinyu field and continue to identify new
drilling locations with this new data. The potential includes the new reef trend
we encountered while drilling DN-48, and a newly identified eastern lobe that
has excellent potential.
In October 2006 we also acquired Nizhny Omrinskoye Neft for $1.5 million in cash
from Lukoil. This principal licence is a mature producing field that is
estimated to have 25 million barrels of C1-C2 reserves. We have reactivated 3
wells on this field and have commissioned DeGolyer and MacNaughton to
re-evaluate reserves on this licence area.
Three to five development wells will be drilled in 2007 at Dinyu with a
possibility of an additional exploration well subject to seismic data review. In
the second half of 2007, we expect to initiate a Komi-wide fraccing programme,
as well as continue to workover wells at Nizhny Omrinskoye.
Timan Pechora
The average production on the Timan Pechora licence areas during 2006 was 1,001
bopd compared to 1,078 bopd 2005. In 2006 the Group re-completed five wells and
drilled two development wells at Arcticneft. By mid-year, we expect to initiate
drilling of an important sidetrack to test the deep Permian horizon for which a
license extension was granted by the Ministry of Natural Resources in 2006.
At Urals Nord, our first exploration well on the Nadezhdinsky prospect was
spudded in on 18 April 2007 and is expected to reach a target depth of 3,700
meters in June of 2007. The prospect is an Upper Devonian reef that may contain
upwards of 60 million barrels of recoverable reserves. The well is located
approximately 60 kilometers southwest of the port of Varendey on the northern
coastline of Russia.
Udmurtia
Average production at Chepetskoye NGDU in 2006 was 940 bopd compared to 914 bopd
in 2005. As part of our 2006 programme we drilled six development wells on the
Potapovskoye field and have received pilot production project approval. In
addition, ZT118 well on Zotovskoye was recompleted and we began a pilot water
injection scheme. In 2007 we plan to drill five development wells at the
Potapovskoye field.
Outlook
The Company is well positioned to continue its growth as a leading Russian
independent E&P company. I am personally very proud of having played a key role
in the development of Urals Energy - which is in many ways a success because of
its partnership of Russian and western shareholders. With Alex Dyachenko
assuming the role of Chief Executive, the Company will be led by a capable
Russian manager, executing a focused Russian strategy. I look forward to
continuing our partnership as a member of the board of directors.
William R. Thomas
Chief Executive Officer
30 April 2007
Financial Results
Operating Environment
2006 was characterized by fluctuating world oil prices and the Company's focus
on investment in development drilling. Brent oil prices began the year at
$61.67 per barrel, reached a peak of $78.69 in August a low of $55.96 in October
and ended the year at $56.63 per barrel. The Russian oil industry broadly
tracked these movements. Industry average domestic oil prices began 2006 at
$59.53 per barrel and averaged approximately $57.72 per barrel for the year.
Profit margins were strong in the first half of the year, when the industry
realized the best domestic netbacks ever. However, in the fourth quarter, due to
rapidly falling export prices combined with the 60-day lag in the reduction of
export duties, the entire Russian oil industry suffered from a profitability
squeeze.
The Rouble continued to appreciate against the Dollar, rising 4% in the year,
which combined with continued increases in costs for critical items such as
steel and labor, translated in higher operating costs.
Production and Revenues
Crude oil production during the year increased by 13% from 3.0 million barrels
in 2005 to 3.4 million barrels in 2006, with average daily production increasing
from 5,320 barrels per day in 2005 to 9,200 in 2006. The majority of this
increase was due to organic development, with only 566 bopd coming from new
properties acquired during the year.
During the period the Company's gross revenues totalled $169.6 million versus
$92.9 million in 2005. The Group realized a weighted average gross price of
$48.39 per barrel of oil sold in 2006 versus $44.35 in 2005. Export sales
prices for the Group averaged $61.20 per barrel, and domestic sales prices
averaged $27.75 per barrel. Domestic refined product prices averaged $50.52 per
barrel.
Net revenues increased to $119.2 million from $66.1 million in the prior year.
While the weighted average gross price realized per barrel was $3.52 higher then
in 2005, the percentage per barrel paid to the government in the form of
production taxes and export duties in 2006 was 50.18% versus 46.94% in 2005. As
a result, the average net revenues per barrel were only modestly higher, $32.81
for 2006 versus $30.22 for 2005. 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 2006
was $29.26 versus $29.01 per barrel in 2005. In 2006, netbacks for export sales
were $29.63 per barrel and $28.71 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 $47.64 per barrel.
Net revenues minus the cost of production was $25.8 million as compared to $14.1
million in 2005, resulting in an operating profit of $34.1 million versus $11.3
million in the prior year. Production costs totalled $92.1 million of which
$19.8 million represents non-cash items, principally DD&A. Also imbedded in
these costs are $9.3 million of crude purchased from our neighbouring operator
on Kolguyev Island, GUP AMNGR. Urals Energy purchased this oil from AMNGR and
resold it together with its own produced oil for a modest profit margin, but a
lesser profit margin then it would have had Urals Energy produced the oil
itself.
SG&A costs were $28.9 million. The largest component in SG&A was wages and
salaries which increased year-on-year due to additional personnel from
acquisitions and increased operations. SG&A also includes a number of non-cash
expense items, primarily related to the Company's stock incentive plan,
totalling $5.1 million.
Interest expense for the period was $9.8 million as compared to $6.9 million in
2005, as the Company's average debt outstanding for the period was greater than
in 2005.
Net profit for the year attributable to shareholders was $34.3 million as
compared to $7.1 million in 2005. The largest non-cash item affecting this
result is an extraordinary gain through a negative goodwill charge of $35.9
million related to our acquisition of Dulisma. This reflects the excess in fair
market value of the assets purchased above the price paid. The method for
calculating the fair market value is a conservative discounted cash flow
valuation based on factors known at the time (not including currently known
value attributes such as the unified production tax holiday and the commercial
sales value of the natural gas).
Adjusting for non-recurring costs and other standard non-cash items, the
Company's management-adjusted EBITDA for the period was $22.9 million, or 19% of
net revenues.
During Q406 the financial performance of the Group was affected by a squeeze
between lower prices and high export duties at Petrosakh and Arcticneft. Russian
export duties are regressive and are set according to a fixed formula and
increase as export prices increase, however this adjustment is subject to a
60-day time lag. The sharp spike in prices in July and August followed by a
steep decline in September and October resulted in high export duties versus low
export prices at the critical time when, in early December, the Company had to
make its last shipments to clear inventory before the winter sea ice-in at
Petrosakh and Arcticneft prevents navigation. The Company estimates that as a
result of this significant price change and the export tax lag, the negative
impact on EBITDA was approximately $7.3 million. Wide short-term fluctuations
such as those seen in 2006 represent a risk for the Company, as a large portion
of its operating profits are derived from two critical time windows, early
December and late June, when the seas are navigable due to the ice-melt, it must
make large shipments from these operations regardless of the market conditions
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 total gross revenues
during 2006 were export duties (28%) and the unified production tax (21%). The
Company paid a total of $103.3 million in cash taxes for the year. Unified
production taxes are calculated based on production revenues and in 2006 the
Group paid $33.9 million. Looking forward, the proportion of mineral extraction
taxes paid overall by the Company will decline dramatically as production from
Dulisma increases, where a holiday for this tax has been granted through 2016.
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 2006 resulted in an average export duty for the
Company of 41% of gross export revenues, and $48.2 million of cash paid. As
mentioned above, this tax can be particularly punitive in rapidly declining
crude price scenarios, as happened in the fall of 2006. VAT payments totalled
$3.6 million.
At 31 December 2006, the Group's deferred tax liability was $111.8 million. This
is a non-cash liability derived under IFRS methodology by accruing the
difference of the fair market value of the Company's producing reserves versus
the amount actually paid to acquire them. The Company expects this deferred tax
liability to be reflected on its balance sheet indefinitely, and to grow further
in the event that Urals Energy continues to make acquisitions at low entry
prices.
Cash Flow
For the period, operating cash flow before working capital changes was $22.9
million. Net cash generated from operating activities improved considerably over
the year, $35.3 million for 2006 versus a loss of $32.2 in 2005. Capital
expenditures for development in 2006 were $59.5 million of which approximately
58% was direct drilling expense. The bulk of the remaining capital expenditures
was for advanced infrastructure investment at Dulisma, where a total of $16.4
million was spent. The cost of acquisitions (net cash on hand) during 2006 was
$137.3 million, resulting in a total use of cash for investments and
acquisitions of $198.6 million.
During the course of the year, a net total of $195.1 million in new funds from
the sale of equity was raised. At 31 December 2005, the Group's short- and
long-term debt was $81.1 million. During 2006, a total of $14.0 million in new
debt was borrowed and $29.9 million in debt principle repaid. As a result, as of
31 December 2006, total outstanding debt was $63.8 million.
Cash Position
The deficit of $163.3 million resulting from the difference of cash generated
through operations and cash expenditures for investments in assets and
acquisitions was funded by the addition of $164.0 million in cash from net
borrowings, the sale of equity and exchange rate changes. This resulted in a
change to the cash position of $0.7 million by year end.
Hedging
The Company does not hedge any of its crude oil or product sales, costs or
currency conversions.
Financing
In May of 2006 the Company raised net proceeds of $195.1 million through the
sale of $209.0 million worth of equity. The equity was sold to the public at a
price of #3.60 per common share.
In January of 2006 the Company refinanced the $12 million loan outstanding to
Bank Zenith with a subordinated 5-year loan from BNP Paribas in the same amount.
The loan is non-amortizing, priced at LIBOR plus 5.00% and had warrants attached
to it, giving the bank the right to purchase up to 2 million shares of common
stock at #3.03 per share. In November, the Company also secured a revolving $2
million working capital debt facility from ZAO BNP Paribas.
In January of 2007 the Company borrowed $130 million from Goldman Sachs and
Standard Bank. The loan is secured against Dulisma as project financing for its
development, and has limited, subordinated recourse to Urals Energy Public
Company Limited. It is a four year, non-amortizing loan, priced at LIBOR plus
3.25% with an additional 4.00% PIK. It is callable after two years, and the
Company has purchased interest rate swaps for the cash interest over this
period.
31 December
Note 2006 2005
Assets
Current assets
Cash and cash equivalents 33,082 32,334
Accounts receivable and prepayments 5 24,717 21,465
Current income tax prepayments 4,401 1,174
Inventories 6 26,679 12,641
Total current assets 88,879 67,614
Non-current assets
Property, plant and equipment 7 595,800 287,485
Other non-current assets 8 16,073 3,247
Total non-current assets 611,873 290,732
Total assets 700,752 358,346
Liabilities and equity
Current liabilities
Accounts payable and accrued expenses 9 10,033 7,932
Income tax payable 3,281 6,039
Other taxes payable 10 7,253 3,461
Other taxes provision 2,367 1,987
Short-term borrowings and current 11 22,965 34,117
portion of long-term borrowings
Advances from customers 9 30,913 523
Current liabilities before warrants classified as liabilities 76,812 54,059
Warrants classified as liabilities 11 3,516 -
Total current liabilities 80,328 54,059
Long-term liabilities
Long-term borrowings 11 40,844 47,005
Long term finance lease obligations 1,192 1,357
Dismantlement provision 12 3,327 813
Deferred tax liability 10 111,787 51,100
Other long term liabilities 298 580
Total long-term liabilities 157,448 100,855
Total liabilities 237,776 154,914
Equity
Share capital 13 633 460
Share premium 13 401,448 201,355
Translation difference 22,445 (2,296)
Retained earnings 37,022 2,714
Equity attributable to shareholders 461,548 202,233
of Urals Energy Public Company Limited
Minority interest 1,428 1,199
Total equity 462,976 203,432
Total liabilities and equity 700,752 358,346
MEMORANDUM NOTE:
Total equity 462,976 203,432
Warrants classified as liabilities 11 3,516 -
466,492 203,432
Approved on behalf of the Board of Directors on 27 April 2007
____________________________ ___________________________
W.R. Thomas S. M. Buscher
Chief Executive Officer Chief Financial Officer
Year ended 31 December
Note 2006 2005
Revenues
Gross revenues 14 169,590 92,918
Less: excise taxes (2,176) (530)
Less: export duties (48,217) (26,253)
Net revenues 119,197 66,135
Operating costs
Cost of production 15 (92,071) (52,034)
Selling, general and administrative expenses 16 (28,955) (12,376)
Non-recurring mobilization costs 17 - (7,170)
Excess of net assets acquired over purchase price 4 35,895 16,793
Total operating costs (85,131) (54,787)
Operating profit 34,066 11,348
Interest income 11 1,359 913
Interest expense 11 (9,810) (6,911)
Foreign currency gains (losses) 7,491 (185)
Other non-operating (losses) (202) (669)
Change in fair value of warrants classified as liabilities 11 (1,766) -
31,138 4,496
Profit before income tax
Income tax benefit 10 3,284 2,477
Profit for the year 34,422 6,973
Profit for the year attributable to:
- Minority interest 114 (82)
- Shareholders of Urals Energy Public Company Limited 34,308 7,055
Earnings per share of profit attributable to
shareholders of Urals Energy Public Company Limited:
- Basic earnings per share (in US dollar per share) 0.3264 0.1178
- Diluted earnings per share (in US dollar per share) 0.3175 0.1177
Weighted average shares outstanding
- Basic earnings per share 105,099,777 59,915,473
- Diluted earnings per share 108,051,649 59,939,038
Year ended 31 December
2006 2005
Cash flows from operating activities
Profit before income tax 31,138 4,496
Adjustments for:
Depreciation and depletion 19,335 8,285
Change in fair value of warrants classified as liabilities 1,766 -
Share-based payments 5,089 42
Interest income (1,359) (913)
Interest expense 9,810 6,911
Loss on disposal of assets 439 254
Excess of net assets acquired over purchase price (35,895) (16,793)
Foreign currency (gains) losses (7,491) 185
Other non-cash transactions 56 (1)
Operating cash flows before changes in working capital 22,888 2,466
(Increase) decrease in inventories (10,622) 4,343
(Increase) in accounts receivables and prepayments (1,257) (11,810)
(Decrease) in accounts payable and accrued expenses (116) (22,349)
Increase in advances from customers 9 30,390 523
Increase (decrease) in other taxes payable 5,622 (785)
Cash generated from (used in) operations 46,905 (27,612)
Interest received 1,190 913
Interest paid (8,900) (2,685)
Income tax paid (3,890) (2,862)
35,305 (32,246)
Net cash generated from (used in) operating activities
Cash flows from investing activities
Acquisitions of subsidiaries, net of cash acquired 4 (137,299) (106,500)
Purchase of property, plant and equipment (59,538) (18,087)
Purchase of intangible assets (1,772) -
Net cash used in investing activities (198,609) (124,587)
Cash flows from financing activities
Proceeds from borrowings 14,000 101,412
Repayment of borrowings (29,946) (56,313)
Finance lease principle payments (419) (404)
Repayment of promissory notes 4 (15,088) -
Cash proceeds from exercise of options 13 125 -
Cash proceeds from issuance of ordinary shares 13 195,052 143,100
Net cash generated from financing activities 163,724 187,795
Effect of exchange rate changes
on cash and cash equivalents 328 (49)
Net increase in cash and cash equivalents 748 30,913
Cash and cash equivalents
at the beginning of the year 32,334 1,421
Cash and cash equivalents
at the end of the year 33,082 32,334
Notes Share Share Unpaid Retained Equity Minority Total
capital premium capital earnings attributable to interest equity
(accumulated Shareholders of
deficit) Urals Energy
Cumulative Public Company
Translation Limited
Adjustment
Balance at 1 January 209 42,172 (11,324) 1,264 (4,341) 27,980 1,327 29,307
2005
Effect of currency (3,560) - (3,560) (46) (3,606)
translation
Profit for the year - 7,055 7,055 (82) 6,973
Total recognized (3,560) 7,055 3,495 (128) 3,367
income (loss)
Issuance of shares 13 251 159,141 11,324 - - 170,716 - 170,716
Share-based payment 13 - 42 - - - 42 - 42
Balance at 31 December 460 201,355 - (2,296) 2,714 202,233 1,199 203,432
2005
Effect of currency 24,741 - 24,741 115 24,856
translation
Profit for the year - 34,308 34,308 114 34,422
Total recognized 24,741 34,308 59,049 229 59,278
income (loss)
Issuance of shares 13 173 194,879 - - - 195,052 - 195,052
Exercise of options 13 - 125 - - - 125 - 125
Share-based payment 13 - 5,089 - - - 5,089 - 5,089
Balance at 31 December 633 401,448 - 22,445 37,022 461,548 1,428 462,976
2006
1 Activities
Urals Energy Public Company Limited ("Urals Energy" or the "Company" or "UEPCL")
was incorporated as a limited liability company in Cyprus on 10 November 2003.
Urals Energy and its subsidiaries (the "Group") are primarily engaged in oil and
gas exploration and production in the Russian Federation and processing of crude
oil for distribution on both the Russian and international markets.
The registered office of Urals Energy is at 31 Evagorou Avenue, Suite 34,
CY-1066, Nicosia, Cyprus. The Group's primary office is located at 11 Osennaya
Ul. Moscow, 121609, Russian Federation.
The Group comprises the following subsidiaries:
Entity Jurisdiction Effective ownership interest
at 31 December
2006 2005
Exploration and production
ZAO Petrosakh ("Petrosakh") Sakhalin 97.2% 97.2%
ZAO Arcticneft ("Arcticneft") Nenetsky 100.0% 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% 100.0%
OOO Michayuneft ("Michayuneft") Komi 100.0% 100.0%
OOO Oil Company Dulisma ("Dulisma") Irkutsk 100.0% -
OOO Lenskaya Transportnaya Kompaniya ("LTK") Irkutsk 100.0% -
OOO Nizhneomrinskaya Neft Komi 100.0% -
Management company
OOO Urals Energy Moscow 100.0% 100.0%
Urals Energy (UK) Limited United Kingdom 100.0% 100.0%
Exploration
OOO Urals-Nord ("Urals-Nord") Nenetsky 100.0% 100.0%
Trading
UENEXCO Limited ("UENEXCO") Cyprus 100.0% 100.0%
UENEXCO Limited only operated during the first quarter of 2006 after which all
trading operations were transferred to UEPCL.
2 Summary of 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 as modified by change in fair value of warrants
classified as liabilities. 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. These policies have been
consistently applied to all the periods presented, unless otherwise stated.
Critical accounting estimates and judgments are disclosed in Note 3. Actual
results could differ from the estimates.
These consolidated financial statements also include all disclosures necessary
for compliance with the relevant sections of the Cyprus Companies Law Cap 133.
Functional and presentation currency. The United States Dollar ("US dollar or
US$ or $") 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 26.33 and 28.78 as of 31 December
2006 and 2005, respectively.
Translation to presentation currency. The results and financial position of each
group entity (the 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 a manner similar to the successful efforts method. Costs of successful
development and exploratory wells are capitalised.
The Group accounts for exploration and evaluation activities in accordance with
IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing
exploration and evaluation costs until such time as the economic viability of
producing the underlying resources is determined. Exploration and evaluation
costs related to resources determined to be not economically viable are expensed
through cost of production in the consolidated income statement. Other
exploration costs are expensed as incurred.
Depletion of capitalized costs of proved oil and gas properties is calculated
using the unit-of-production method for each field based upon proved reserves
for property acquisitions and proved developed reserves for exploration and
development costs. Oil and gas reserves for this purpose are determined in
accordance 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
Intangible assets. All of the Group's other intangible assets have definite
useful lives and primarily include capitalised computer software and licences.
Acquired computer software licenses and patents are capitalised on the basis of
the costs incurred to acquire and bring them to use.
Development costs that are directly associated with identifiable and unique
software controlled by the Group are recorded as intangible assets if inflow of
incremental economic benefits exceeding costs is probable. Capitalised costs
include staff costs of the software development team and an appropriate portion
of relevant overheads. All other costs associated with computer software, eg its
maintenance, are expensed when incurred.
Intangible assets are amortised using the straight-line method over their useful
lives:
Estimated useful life
Software licences 3
Capitalised internal software development costs 3
Other licences 5 to 7
Provisions. Provisions are recognised when the Group has a present legal or
constructive obligation as a result of past events and when it is probable that
an outflow of resources embodying economic benefits will be required to settle
the obligation, and a reliable estimate of the amount of the obligation can be
made.
Provisions, including those related to dismantlement, abandonment and site
restoration, are evaluated and re-estimated annually, and are included in the
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
income statement.
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.
Interest costs on borrowings to finance the construction of property, plant
and equipment are capitalised, during the period of time that is required to
complete and prepare the asset for its intended use. Borrowing costs are
recognised as an expense on a time proportion basis using the effective interest
method.
Loans receivable. The loans advanced by the Group are classified as "loans and
receivables" in accordance with IAS 39 and stated at amortised cost using the
effective interest method.
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 income statement 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 income statement.
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.
Warrants. Warrants issued that allow the holder to purchase shares of the
Group's stock are recorded at fair value at issuance and recorded as liabilities
unless the number of equity instruments to be issued to settle the warrants and
the exercise price are fixed in the issuing entities' functional currency at the
time of grant, in which case they are recorded within shareholders' equity.
Changes in the fair value of warrants recorded as liabilities are recorded in
the income statement.
Share capital. Ordinary shares are classified as equity. Incremental costs
directly attributable to the issue of new shares are shown in equity as a
deduction, net of tax, from the proceeds. Any excess of the fair value of
consideration received over the par value of shares issued is presented in the
notes as a share premium.
Share-based payments. The fair value of equity instruments granted is evaluated
at the measurement date, based on market prices if available, taking into
account the terms and conditions upon which those equity instruments were
granted. If market prices are not available, the fair value of the equity
instruments granted is estimated using a valuation technique to estimate what
the price of those equity instruments would have been on the measurement date in
an arm's length transaction between knowledgeable, willing parties.
Earnings per share. Earnings per share is determined by dividing the profit or
loss attributable to equity holders of the Group by the weighted average number
of participating shares outstanding during the reporting year.
Adoption of new or revised standards and interpretations. New or amended
standards and interpretations adopted by the Group from 1 January 2006 are
discussed below.
None of the adoptions had a material impact on the Group's financial position or
results of operations.
IAS 39 (Amendment), The Fair Value Option; IAS 39 (Amendment), Cash Flow Hedge
Accounting of Forecast Intragroup Transactions; IAS 39 (Amendment), Financial
Guarantee Contracts. The amendments to IAS 39 clarified the use of the fair
value through profit or loss category of financial instruments and clarified the
accounting for financial guarantees as either insurance contracts or financial
instruments.
IAS 21 (Amendment), Net Investment in a Foreign Operation. This amendment
requires foreign exchange gains and losses on monetary items that form part of
net investment in a foreign operation to be reported in consolidated equity even
if the loans are not in the functional currency of either the lender or the
borrower. Previously, such exchange differences were required to be recognised
in consolidated profit or loss.
IAS 19 (Amendment), Employee Benefits. The amendment to IAS 19 introduces an
additional recognition option for actuarial gains and losses in post-employment
defined benefit plans.
IFRS 1 (Amendment), First-time Adoption of International Financial Reporting
Standards and IFRS 6 (Amendment), Exploration for and Evaluation of Mineral
Resources. The amendments to IFRS 1 and IFRS 6 provided limited relief to
first-time adopters of IFRS with respect to the provisions of IFRS 6.
IFRIC 4, Determining whether an Arrangement contains a Lease ("IFRIC 4"). IFRIC
4 provides guidance on how to determine whether an arrangement contains a lease
as defined in IAS 17, Leases, on when the assessment or reassessment of an
arrangement should be made and on how lease payments should be separated from
any other elements in the arrangement.
IFRIC 5, Rights to Interests arising from Decommissioning, Restoration and
Environmental Rehabilitation Funds ("IFRIC 5"). IFRIC 5 provides guidance on the
accounting for interests in decommissioning funds.
IFRIC 6, Liabilities arising from Participating in a Specific Market - Waste
Electrical and Electronic Equipment ("IFRIC 6"). IFRIC 6 addresses the
accounting for liabilities under an EU Directive on waste management for sales
of household equipment.
New accounting pronouncements. Certain new standards and interpretations have
been published that are mandatory for the Group's accounting periods beginning
on or after 1 January 2007 or later periods and which the entity has not early
adopted:
IFRS 7, Financial Instruments: Disclosures and a complementary Amendment to IAS
1 Presentation of Financial Statements - Capital Disclosures (effective from 1
January 2007). The IFRS introduces new disclosures to improve the information
about financial instruments. The volume of disclosures will increase
significantly with an emphasis on quantitative aspects of risk exposures and the
methods of risk management. The quantitative disclosures will provide
information about the extent to which the entity is exposed to risk, based on
information provided internally to the entity's key management personnel.
Qualitative and quantitative disclosures will cover exposure to credit risk,
liquidity risk and market risk including sensitivity analysis to market risk.
IFRS 7 replaces IAS 30, Disclosures in the Financial Statements of Banks and
Similar Financial Institutions, and some of the requirements in IAS 32,
Financial Instruments: Disclosure and Presentation. The Amendment to IAS 1
introduces disclosures about level of an entity's capital and how it manages
capital. The Group is currently assessing what impact the new IFRS and the
amendment to IAS 1 will have on disclosures in its financial statements.
IFRS 8, Operating Segments (effective for annual periods beginning on or after 1
January 2009). The Standard applies to entities whose debt or equity instruments
are traded in a public market or that file, or are in the process of filing,
their financial statements with a regulatory organisation for the purpose of
issuing any class of instruments in a public market. IFRS 8 requires an entity
to report financial and descriptive information about its operating segments and
specifies how an entity should report such information. Management does not
expect IFRS 8 to affect the Group's financial statements.
Other new standards or interpretations. The Group has not early adopted the
following other new standards or interpretations: IFRIC 7, Applying the
Restatement Approach under IAS 29 (effective for periods beginning on or after 1
March 2006, that is from 1 January 2007); IFRIC 8, Scope of IFRS 2 (effective
for periods beginning on or after 1 May 2006, that is from 1 January 2007);
IFRIC 9, Reassessment of Embedded Derivatives (effective for annual periods
beginning on or after 1 June 2006); IFRIC 10, Interim Financial Reporting and
Impairment (effective for annual periods beginning on or after 1 November 2006);
IFRIC 11, IFRS 2-Group and Treasury Share Transactions (effective for annual
periods beginning on or after 1 March 2007); IFRIC 12, Service Concession
Arrangements (effective for annual periods beginning on or after 1 January
2008). Unless otherwise described above, these new standards and
interpretations are not expected to significantly affect the Group's financial
statements.
Reclassifications. Certain reclassifications have been made to 2005 amounts to
conform to 2006 presentation. 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 2005
Other non-current assets 2,098 3,247
Accounts receivable and prepayments 23,788 21,465
Current income tax prepayments - 1,174
Other taxes payable 5,448 3,461
Other taxes provision - 1,987
For the year ended 31 December 2005
Selling, general and administrative expenses (13,968) (12,376)
Cost of production (50,442) (52,034)
Other non-operating losses (457) (669)
Income tax benefit 2,265 2,477
At 31 December 2005, management reclassified $1.149 million from accounts
receivable and prepayments to other non-current assets, primarily to record
advances to contractors and suppliers for capital construction projects. Current
income tax prepayments as of $1.174 million were separated from accounts
receivable and prepayments.
At 31 December 2005, other taxes provision as of $1.987 was separated from other
taxes payable.
For the year ended 31 December 2005, selling, general and administrative
expenses was decreased and cost of production was increased by $1.592 million,
primarily to record property tax and other taxes of $1.338 and loss on disposal
of assets of $0.254 million within cost of production.
For the year ended 31 December 2005, reversal of income tax provision as of
$0.212 million was reclassified from other non-operating losses to income tax
benefit.
3 Critical Accounting Estimates and Judgments in Applying Accounting
Policies
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.
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 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.
Tax legislation. Russian tax, currency and customs legislation is subject to
varying interpretation. Refer to Note 18.
4 Acquisitions
Acquisition of OOO Oil Company Dulisma and OOO Lenskaya Transportnaya
Kompaniya. In April 2006, the Group acquired 100 % stakes in OOO Oil Company
Dulisma ("Dulisma") and OOO Lenskaya Transportnaya Kompaniya ("LTK") for $136
million, net of assumed debt of $15.1 million. Dulisma holds exploration and
production licenses in Irkutsk expiring in 2019. A net loss of $2.4 million
associated with Dulisma and LTK were included in the Group's results for the
year ended 31 December 2006.
The table below presents the fair values of 100 % of Dulisma's and LTK's assets
and liabilities as of the date of acquisition. No information on the IFRS
carrying values before the acquisition is available as Dulisma and LTK did not
prepare IFRS financial statements prior to acquisition.
Fair values at
acquisition
Cash and cash equivalents 61
Accounts receivable and prepayments 2,842
Other current assets 1,378
Oil and gas properties and equipment 241,711
Short-term borrowings and current portion of long-term borrowings (399)
Other current liabilities (18,523)
Deferred income tax liability, non-current (55,738)
Net assets 171,332
Excess of the Group's share in (35,448)
net assets over purchase consideration
Purchase consideration share in net assets acquired 135,884
Less: cash and cash equivalents of subsidiaries acquired (61)
Outflow of cash and cash equivalents on acquisition 135,823
Included within oil and gas properties and equipment acquired with Dulisma and
LTK are property acquisition costs with a fair value of $153.1 million that are
not subject to depletion pending the results of management's assessment of the
economic viability of the properties. Additionally, included within oil and gas
properties and equipment acquired with Dulisma and LTK are property acquisition
costs with a fair value of $35.4 million that are being depleted over total
proved reserves.
Management attributes the excess of the Group's share in net assets acquired
over purchase consideration to the foreign seller's interest in exiting the
Russian market and its lack of interest in investing the required resources to
develop the license as well as uncertainties over the timing and conditions for
using the planned pipeline connecting Dulisma's operations to commercial
markets.
The remaining amount of $0.447 million of excess of net assets acquired over
purchase price relates to the acquisition of OOO Nizhneomrinskaya Neft, an
entity extracting crude oil, for a total consideration of $3.532 million. The
cash and cash equivalents of subsidiary acquired is $2.056 million as of the
date of acquisition.
Summary combined financial information. The following table sets forth summary
combined financial information for the year ended 31 December 2006 that is
presented to provide information to evaluate the financial effects of the
acquisitions of Dulisma and LTK as if they had occurred on 1 January 2006.
Group Dulisma Adjustments Summary
results And LTK and elimination combined
Total revenues 169,590 4,390 (2,968) 171,012
Profit (loss) for the year 34,422 (2,904) 2,449 33,967
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
2006. Total revenues and profit (loss) for the period for Dulisma and LTK
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)
intercompany eliminations were recorded; (b) adjustments to eliminate results of
the period included both in the Group results and the respective entities'
results for the full year; and (c) 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 Dinyu. In November 2005, the Group acquired a 100.0 % stake in
Dinyu from Lonsdacks Investments Limited for $61.5 million, net of debt assumed
of $8.5 million, following the approval from the Russian Federal Antimonopoly
Service.
Subsequent to its purchase of Dinyu, in December 2005, the Group purchased the
35 % stake owned by third parties in Dinyu's 65 % owned subsidiary, OOO
Michayuneft ("Michayuneft") for $0.2 million.
Acquisition of Arcticneft. In July 2005, the Group acquired a 100.0 % equity
interest in Arcticneft from OAO LUKoil for $23 million, net of debt assumed of
$13 million. Arcticneft holds production licenses in the Nenetsky Autonomous
Region of the Russian Federation.
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 income
statement for the year ended 31 December 2005.
Acquisition of Urals-Nord. In April 2005, the Company acquired the remaining
50.0 % interest in OOO Urals-Nord ("Urals-Nord") for $14 million. 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.
5 Accounts Receivable and Prepayments
31 December
2006 2005
Trade accounts and notes receivable (net of allowances of $0.640 million 1,755 7,871
and $0.586 million at 31 December 2006 and 2005, respectively)
Prepaid taxes 759 3,234
Advances to suppliers 4,857 2,723
Recoverable taxes including VAT 12,236 3,503
Receivables from related parties (Note 20) 2,897 2,805
Other 2,213 1,329
Total accounts receivable and prepayments 24,717 21,465
Total accounts receivable and prepayments at amount of $3.91 million and $10.947
million at 31 December 2006 and 2005, respectively, are denominated in US
dollars.
6 Inventories
31 December
2006 2005
Crude oil 6,910 3,252
Petroleum products 1,700 1,590
Materials and supplies (net of allowances of $1.217 million and $0.854 18,069 7,799
million at 31 December 2006 and 2005, respectively)
Total inventories 26,679 12,641
7 Property, Plant and Equipment
Oil and gas Refinery and Buildings Other Assets under Total
properties related Assets construction
equipment
Cost at
1 January 2005 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 15,812 20,718
Capitalised borrowing - - - - 640 640
costs (Note 11)
Transfers 8,053 - - 964 (9,017) -
Changes in estimates of (765) - - - - (765)
dismantlement
provision (Note 12)
Disposals (217) - - (310) (325) (852)
31 December 2005 266,137 8,984 2,048 5,131 14,754 297,054
Translation difference 35,034 838 330 341 4,837 41,380
Business combinations 209,473 - 2,629 1,216 31,437 244,755
Additions 5,060 - - - 39,546 44,606
Capitalised borrowing - - - - 861 861
costs (Note 11)
Transfers 28,322 57 59 4,729 (33,167) -
Changes in estimates of 146 - - - - 146
dismantlement
provision (Note 12)
Disposals (2,112) - - (1,055) (1,176) (4,343)
31 December 2006 542,060 9,879 5,066 10,362 57,092 624,459
Oil and gas Refinery and Buildings Other Assets Assets under Total
properties related equipment construction
Accumulated Depreciation at
1 January 2005 (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
(8,317) (502) (222) (528) - (9,569)
31 December 2005
Translation difference (1,312) (64) (33) (71) - (1,480)
Depreciation, depletion (16,950) (518) (380) (1,034) - (18,882)
and amortization
Disposals 883 - - 389 - 1,272
31 December 2006 (25,696) (1,084) (635) (1,244) - (28,659)
Net Book Value at
31 December 2005 257,820 8,482 1,826 4,603 14,754 287,485
31 December 2006 516,364 8,795 4,431 9,118 57,092 595,800
Included within oil and gas properties at 31 December 2006 and 2005 were
exploration and evaluation assets of $322.9 million and $140.5 million,
respectively. Additions to exploration and evaluation assets in 2006 and 2005
totalled $159.1 million and $135.9 million, respectively, including $153.1
million and $129.4 million as a result of business combinations. Transfers from
exploration and evaluation assets to producing properties totalled $4 million
and nil in 2006 and 2005, respectively. The remaining movements in exploration
and evaluation assets relate to currency differences. During the years ended 31
December 2006 and 2005, no exploration and evaluation costs were recognized in
the Group's consolidated income statement and investing cash flows, other than
business combinations, related to exploration and evaluation assets totalled $6
million and $6.5 million respectively.
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 $2.3 million and $0.020
million at 31 December 2006 and 2005, 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 2006 and 2005, property, plant and equipment with carrying net
book value of $134.4 million and $90.2 million, respectively, was pledged as
collateral for the Group's borrowings.
8 Other Non-Current Assets
31 December
2006 2005
Advances to contractors and suppliers 12,474 1,177
Intangible assets 1,141 -
Other deferred costs 2,458 2,070
Total other non-current assets 16,073 3,247
9 Accounts Payable and Accrued Expenses
31 December
2006 2005
Trade payables 5,991 2,809
Interest payable 15 833
Wages and salaries 1,167 806
Advances from and payables to related parties (Note 20) - 74
Other payable and accrued expenses 2,860 3,410
Total accounts payable and accrued expenses 10,033 7,932
Total accounts payable and accrued expenses at amount of $3.314 million and
$3.582 million at 31 December 2006 and 2005, respectively, are denominated in US
dollars.
Advances from customers. In December 2006, the Group received an advance of
$30.2 million denominated in US dollars from Petraco Oil Company Limited for
crude oil sales volumes from Petrosakh and Arcticneft in June-August 2007. This
advance was received to finance the development program in Dulisma during the
winter period. The advance bears interest at LIBOR plus 4% until the date of
bill of lading and LIBOR plus 1% for 30 days from the bill of lading date.
10 Taxes
Income taxes for the years ended 31 December 2006 and 2005 comprised the
following:
Year ended 31 December
2006 2005
Current tax (benefit) expense (1,296) 678
Deferred tax (benefit) (1,988) (3,155)
Income tax (benefit) (3,284) (2,477)
Below is a reconciliation of profit before taxation to income tax charge
(benefit):
Year ended 31 December
2006 2005
Profit before income tax 31,138 4,496
Theoretical tax charge
at the statutory rate of 24 % 7,473 1,079
Excess of net assets acquired over purchase price (8,615) (4,030)
Non-recurring mobilization costs - 1,721
Tax credits related to seismic surveys (280) (1,047)
Losses utilized in the current year - (1,340)
Utilisation of previously unrecognised tax loss carry forward (781)
Unrecognised tax loss carry forward for the year 396 939
Reversal of unused income tax provision (2,835) (161)
Effect of tax penalties 164 28
Other non-deductible expenses 1,194 334
Income tax (benefit) (3,284) (2,477)
The movement in deferred tax assets and liabilities during the year ended 31
December 2006 was as follows:
2006 Recognized in Charged Effect of 2005
equity for (credited) to acquisitions
translation the income
differences statement
Deferred tax liabilities
Property, plant and equipment 114,388 7,747 (1,792) 55,813 52,620
Inventories 124 9 25 - 90
Payables 75 19 (238) 3 291
Other taxable 39 8 (82) - 113
temporary differences
Deferred tax assets
Receivables (255) (19) 29 (110) (155)
Dismantlement provision (799) (31) (184) (394) (190)
Payables (459) (36) (63) - (360)
Inventories (130) (12) 87 (91) (114)
Other deductible (61) (110) 653 (49) (555)
temporary differences
Tax losses (1,135) (72) (423) - (640)
Net deferred tax liability 111,787 7,503 (1,988) 55,172 51,100
The movement in deferred tax assets and liabilities during the year ended 31
December 2005 was as follows:
2005 Recognized in Charged Effect of 2004
equity for (credited) to acquisitions
translation the income
differences statement
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 113 (2) 115 - -
temporary differences
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 (555) 19 (93) (429) (52)
temporary differences
Tax losses (640) 16 (365) - (291)
Net deferred tax liability 51,100 (1,008) (3,155) 36,873 18,390
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 2006 and 2005,
deferred tax assets of $4.9 million and $2.0 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 2006 and 2005, the
estimated unrecorded deferred tax liabilities for such differences were $4.4
million and $1.4 million, respectively.
Other taxes payable at 31 December 2006 and 2005 were as follows:
31 December
2006 2005
Unified production tax 5,583 2,259
Value added tax 374 367
Other taxes payable 1,296 835
Total other taxes payable 7,253 3,461
11 Borrowings
Long-term borrowings. Long-term borrowings were as follows at 31 December 2006
and 2005:
31 December
2006 2005
BNP Paribas Reserve Based Loan Facility 51,054 69,000
BNP Paribas Subordinated Loan 10,570 -
Bank Zenit - 12,000
Other 185 122
Subtotal 61,809 81,122
Less: current portion of long-term borrowings (20,965) (34,117)
Total long-term borrowings 40,844 47,005
BNP Paribas Reserve Based Loan Facility. In November 2005, the Group received a
five year, revolving Reserve Based Loan Facility with BNP Paribas, underwritten
to a maximum commitment of $100.0 million. At 31 December 2005, the maximum
amount then available of $69.0 million was drawn. The facility is divided into
a senior tranche of $59.0 million that bears interest at LIBOR plus 5.0 % and a
junior tranche of $10.0 million priced at LIBOR plus 6.25 %. Both tranches are
repaid on quarterly basis and matured 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 covenants under the
facility, including the maintenance of a minimum current ratio and a maximum
ration of total borrowings to EBITDA. Additionally, under the facility, the
Group is required to maintain a designated cash balance equal to the next
quarter's payment of principal and interest ($7.473 million and $1.083 million
at 31 December 2006 and 2005, respectively). At 31 December 2006, the Group was
in compliance with all its covenants under the facility.
Subordinated Loan. In January 2006, the Group obtained a $12.0 million
subordinated loan from BNP Paribas (the "Subordinated Loan"). The Subordinated
Loan bears interest at LIBOR plus 5.0 % and is repayable 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 the Bank Zenit loan of $12.0 million.
Management estimated the value of the warrants to be $1.75 million at issuance.
As the exercise price of the warrants is denominated in a currency other than
the Group's functional currency, the warrants are classified as a liability and
adjusted to fair value at each reporting date, with the change in fair value
recorded within the income statement. In 2006 the change in fair value of
warrants resulted in an expense of $1.77 million. As the warrants are
exercisable at any time, this amount was originally recorded as current
liabilities in the Group's consolidated balance sheet, with a corresponding
reduction in the carrying value of the Subordinated Loan. The difference
between the carrying value and the face value of the Subordinated Loan is
accreted over the term to maturity as interest expense at the effective interest
rate of the debt.
Bank Zenit. In March 2005, Chepetskoye and CNPSEI entered into two loan
agreements with Bank Zenit totalling $12.0 million. The loans bear interest at
11.0 % per annum and scheduled for repayment in March 2010. The loans were
repaid in full in February 2006.
BNP Paribas Bank Credit Facility. In June 2005, the Petrosakh entered into a
$20.0 million, 18 month pre-export credit facility with BNP Paribas Bank. This
variable interest debt facility bore interest at LIBOR plus 5.0% 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 % 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 % 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
2006 2005
One year 20,965 34,117
Two to five years 40,844 47,005
Thereafter - -
Total long-term borrowings 61,809 81,122
Short-term borrowings. Short-term borrowings were as follows at 31 December
2006 and 2005:
31 December
2006 2005
BNP Paribas Revolver 2,000 -
Total short-term borrowings 2,000 -
BNP Paribas $2 million revolving facility. In November 2006, the Group entered
into a revolving loan agreement with BNP Paribas for a maximum of $2 million
with a maximum maturity of 3 months and bearing interest of LIBOR plus 4.0%.
The effective interest rate. The effective interest rates were 10.47 % and 9.71
% as at 31 December 2006 and 2005, respectively.
Interest expense and income. Interest expense and income for the years ended 31
December 2006 and 2005 comprised the following:
Year ended 31 December
2006 2005
Short-term borrowings
Alfa Eco M - 913
Related party borrowings (Note 20) - 726
Related party borrowings converted into equity (Note 20) - 655
Nimir - 478
BNP Paribas Pre-export Loan - 961
Bank Zenit 129 1,031
Other short-term borrowings 44 35
Total interest expense associated with short-term borrowings 173 4,799
Long-term borrowings
BNP Paribas Subordinated Loan
- interest at coupon rate 1,125 -
- accretion of issuance costs and discount associated with warrants 381 -
BNP Paribas Reserve Based Loan Facility
- interest at coupon rate 6,521 835
- commitments 263 777
- accretion of issuance costs 529 88
Total interest expense associated with long-term borrowings 8,819 1,700
Finance leases 162 276
Less capitalised borrowing costs (861) (640)
Change in dismantlement provision due to passage of time (Note 12) 166 224
Interest on advance from Petraco Oil Company Limited 1,181 315
Other interest 170 237
Total interest expense 9,810 6,911
Interest income
JP Morgan Liquidity Fund (635) (666)
Related party loans issued (Note 20) (130) (84)
Bank deposit (571) (163)
Other (23) -
Total interest income (1,359) (913)
Total finance costs 8,451 5,998
12 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 %.
Year ended 31 December
2006 2005
Opening dismantlement provision 813 950
Translation difference 126 (21)
Acquisitions 1,643 785
Additions 433 20
Changes in estimates 146 (1,145)
Change due to passage of time 166 224
Closing dismantlement provision 3,327 813
As further discussed in Note 18, 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.
13 Equity
At 31 December 2006, authorized ordinary shares were 250 million, each having a
par value of 0.0025 Cypriot pounds, of which 118.1 million and 86.9 million were
issued and outstanding at 31 December 2006 and 2005, respectively.
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 shares Share Share premium Unpaid capital
(thousands of
shares) capital
Balance at 1 January 2005 40,000 209 42,172 (11,324)
Conversion of loans as settlement of - - - 11,017
unpaid capital
Conversion of loans into shares 16,244 86 45,195 -
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 -
Shares issued for cash 31,089 173 194,879 -
Exercise of options 113 - 125 -
Share-based payment - - 5,089 -
Balance at 31 December 2006 118,113 633 401,448 -
Shares issued for cash. In May 2006, the Group completed a private placement
for 31,088,976 of its shares. Proceeds from the issuance totalled $195.1
million, net of transaction costs of $14.0 million.
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 of $17.0 million.
Conversion of loans as settlement of unpaid capital. During 2005, the Group
settled $11.0 million of loans payable by offsetting the loan amounts against
unpaid capital due the Group from the lenders.
Conversion of loans into shares. During 2005, the Group settled $45.3 million
of loans payable by issuing shares to the lenders.
Share-based payments. In February 2006, the 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 5 % 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.
The Group estimated the total fair value of the share-based payments to be
$6.582 million, of which $5.028 million was recognized in 2006.
In September 2005, the Group granted options to purchase 20,000 shares at an
exercise price of 240 pence per share to one of its directors. These options
were granted for zero consideration. All of these options remain unexercised.
In these consolidated financial statements the fair value of this option was
evaluated at $.007 million. The options vest on 30 September 2006, 2007 and
2008 in equal parts and expire on 30 September 2009.
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.
The Group estimated the total fair value of the award to be $0.120 million, of
which $0.057 and $0.042 million were recognized within selling, general and
administrative expenses in 2006 and 2005, respectively, 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 these awards, 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 $0.120 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
14 Revenues
Year ended 31 December
2006 2005
Crude oil
Export sales 117,940 69,177
Domestic sales (Russian Federation) 35,666 13,433
Petroleum (refined) products - domestic sales 14,798 9,904
Other sales 1,186 404
Total gross revenues 169,590 92,918
Substantially all of the Group's export sales are made to third party traders
with title passing at the Russian border. Accordingly, management does not
monitor the ultimate consumers and geographic markets of its export sales.
15 Cost of Production
Year ended 31 December
2006 2005
Depreciation and depletion 19,335 8,285
Unified production tax 36,067 16,829
Cost of purchased products 9,266 12,455
Wages and salaries (including payroll taxes of $2.6 million and 15,190 7,341
$1.5 million for the years ended 31 December 2006 and 2005, respectively)
Materials 4,862 2,276
Other taxes 256 1,338
Loss on disposal of assets 439 254
Other 6,656 3,256
Total cost of production 92,071 52,034
16 Selling, General and Administrative Expenses
Year ended 31 December
2006 2005
Wages and salaries 9,616 5,162
Professional consultancy fees 2,169 1,986
Audit fees 843 556
Office rent and other expenses 1,556 1,522
Transport and storage services 4,537 998
Loading services 1,381 845
Share based payments 5,089 42
Directors' fees 60 17
Other expenses 3,704 1,248
Total selling, general and administrative expenses 28,955 12,376
Directors' fees for the years ended 31 December 2006 and 2005 do not include
$0.185 million and nil related to share-based payments provided to one of the
Group's directors (Note 13).
17 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 kilometers 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.
18 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 economy. 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 in 2005 was required to sell 20.0 % of its annual oil production in
the form of petroleum products to the Sakhalin Island region at market prices,
no such commitments exist in 2006.
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 2006 and 2005 the Group had no other
significant contractual commitments for capital expenditures.
Taxation. Russian tax and customs legislation is subject to varying
interpretations, and changes, which can occur frequently. Management's
interpretation of such legislation as applied to the transactions and activity
of the Group may be challenged by the relevant authorities.
The Russian 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. The Supreme Arbitration Court issued guidance to lower courts on
reviewing tax cases providing a systemic roadmap for anti-avoidance claims, and
it is possible that this will significantly increase the level and frequency of
tax authorities' scrutiny.
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 proceeding the year of review. Under certain
circumstances reviews may cover longer periods.
As at 31 December 2006 and 2005, 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. In August the company insured all of its major assets,
including oil in stock, for a total value of $90 million. Also, a liability
insurance policy was put in place, including environmental liability, with a
total limit of $7.8 million.
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.
Management currently does not believe that any of its significant exploration or
production licenses are at risk of being withdrawn by the licensing authorities.
Additionally, management currently plans to complete all the required
exploration or development work, as appropriate, within the timetables
established in the licenses.
19 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 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 11.
Fair values. The carrying value of the Group's receivables, payables and
borrowings approximate their fair values.
Cash and cash equivalents are carried at amortised cost which approximates
current fair value. Cash and cash equivalents include $31.5 million and $27.9
million as at 31 December 2006 and 2005, respectively, denominated in US
dollars.
At 31 December 2006 and 2005, 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 2006 and 2005, management believes that the fair values of its
borrowings approximate their respective carrying values.
Warrants classified as liabilities are carried at fair value.
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.
20 Balances and transactions with Related Party.
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 had transactions in the
ordinary course of business with Urals ARA NV and Nafta (B) NV which all are
controlled by major shareholders. These transactions included 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
2006 2005
Sales of crude oil on export markets - 5,515
Associated volumes, tons - 17,580
Interest expense - 1,381
Interest income 130 82
Professional consultancy fees (included in selling, general and administrative 424 289
expense)
Rental fees paid (included in selling, general and administrative expense) 450 306
Other expenses 41 790
Accounts and notes receivable 708 1,477
Loans receivable 1,983 1,251
Interest receivable 206 77
Accounts payable to contractors (included in other non-current assets) 863 -
Other payables and accrued expenses - 74
Compensation to senior management. The Group's senior management team comprises
10 people whose compensation totalled $12.895 million and $4.174 million for the
periods ended 31 December 2006 and 2005, respectively, including salary and
bonuses of $7.806 million and $4.132 million respectively, and stock
compensation of $5.089 million and $0.042 million, respectively, and no other
compensation was paid for both years. Additionally, included in loans
receivable at 31 December 2006 and 2005 were loans receivable of $0.955 and nil,
from the Group's senior management team.
21 Subsequent Events
Goldman Sachs. In January 2007, the Group entered into a new loan agreement to
fund the development of the Dulisminskoye field in Irkutsk Region, Eastern
Siberia. Goldman Sachs, as Arranger, and Standard Bank plc, as the funding bank,
are providing a total of US$130 million of debt. The debt facility is secured by
OOO "Oil Company Dulisma" as a project-style loan that is non-recourse, except
in certain limited circumstances, to Urals Energy. This debt financing is
expected to fund Urals Energy's commitment to develop the oil reserves at its
Dulisminskoye field.
The terms of the loan arranged by Goldman Sachs include an interest rate of 725
basis points over LIBOR of which 300 basis points are payable quarterly, with
the remainder accruing until the loan matures in four years or 2011 when all
principal and accrued interest is due in a single payment. The loan may be
prepaid at any time but during the first two years certain penalties for early
prepayment apply.
The credit risk of the debt facility will be sold to Goldman Sachs and Standard
Bank will act as the funding bank of record and also facility agent. The deal is
structured to fund in two tranches, $45 million and $85 million. The second
tranche is subject only to the approval of Urals Energy's senior bank syndicate
in accordance with the terms of a pre-negotiated inter-creditor agreement. Both
tranches were received during first quarter 2007.
Unified production tax holiday. In November 2006 the Russian Government
announced changes to the "Subsoil law", which provides a production tax holiday
for the unified production tax for the oil fields located in East Siberia in
Sakha-Ykutia, Irkutsk and Krasnoyarsk regions. In January 2007 OOO Oil Company
Dulisma received a written confirmation from Irkutsk Oblast Tax Inspectorate
verifying a ten year production tax holiday for the Dulisminskoye field starting
form 1 January 2007 and ending on 31 December 2016.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR BKLLLDZBZBBQ
Urals Energy (LSE:UEN)
Graphique Historique de l'Action
De Juin 2024 à Juil 2024
Urals Energy (LSE:UEN)
Graphique Historique de l'Action
De Juil 2023 à Juil 2024
