TIDMENEG
RNS Number : 9521I
Enegi Oil PLC
31 March 2015
The following replaces the Interim Results announcement released
at 07:00 under RNS number 9179I.
ENEGI OIL PLC
AIM ticker: 'ENEG'
OTC ticker: 'EOLPF'
31 March 2015
Enegi Oil Plc
("Enegi" or "the Company")
Interim Results for the six months ended 31 December 2014
Enegi, the independent Oil and Gas Company today announces its
interim results for the six months ended 31 December 2014.
Key points:
-- Strategy focused on utilising redeployable engineering
solutions that reduce Opex and Capex to build a portfolio of low
risk highly appraised marginal assets
-- Continuing focus on the development of portfolio through ABT Oil and Gas Ltd. ("ABTOG").
-- Building a consortium of "like-minded" major industry players
to take forward the Company's Marginal Field Initiative -
completion of ongoing discussions expected to lead to a dramatic
upturn in activity
-- New approach for development of western Newfoundland assets
based upon an incremental investment plan centered on an Early
Field Development ("EFD")
-- Increasing industry focus on cost reduction expected to drive
operators to consider alternative approaches to field development -
ABTOG's solutions and methods are appropriate for this
-- Further projects expected to be added to portfolio
-- Lower oil price environment increases the number and size of
projects that can be potentially developed using our low Opex /
Capex solutions
-- Lower oil price environment increases the attractiveness of
our solutions for projects, with returns significantly increasing
as oil price strengthens
-- Implementation of the business plan will require an injection
of new capital into the business - the value that it is able to
generate should significantly exceed the effect of any potential
shareholder dilution
Alan Minty CEO of Enegi commented:
"The significant opportunities afforded by marginal fields,
particularly in the current climate, remains the Company's focus.
Dialogue with the market and, in particular, asset owners
continually reinforces the need for delivery capability to be
demonstrable. Our offering requires expertise across a broad
spectrum of disciplines and, as such, we are looking to build a
consortium of established industry partners, with discussions well
advanced in a number of cases, to deliver this.
We consider that the completion of the appropriate agreements
will provide a very strong endorsement to our marginal field
initiative, complementing the substantial engineering work that has
already been undertaken, facilitating a firm upturn in activity and
the realisation of the vision in which all at the Company strongly
believe."
Enegi Oil Tel: + 44 161 817 7460
Alan Minty, CEO
Nick Elwes, Director of Communications
Cenkos Securities
Neil McDonald Tel: + 44 131 220 9771
Derrick Lee Tel: + 44 131 220 6939
www.enegioil.com
Facebook (Enegi Oil PLC)
Twitter (@enegioil)
Qualified Persons
The information in this release has been reviewed by Barath
Rajgopaul MSc (Mech. Eng.) C. Eng, a member of the Advisory Panel
of Enegi. Mr. Rajgopaul has over 30 years' experience in the
petroleum industry.
Chairman's Statement
The six month period under review has been extremely challenging
for the industry and is one that has seen wholesale changes being
carried out following the dramatic fall in the oil price from the
highs of June last year. This rapid decline in the oil price over
the last six months of last year has seen many investment and
development programs being put on hold or cancelled due to high
development costs and lower revenues as a result of falling oil
prices. In addition, operators are currently considering how to
manage some current existing projects that are running at a
loss.
While the industry is undoubtedly still coming to terms with a
lower oil price environment, we have continued to establish and
progress the foundations of our marginal field business. The
business provides a way of developing projects utilising
development solutions that have the ability to reduce Opex and
Capex - a strategy that could be seen to have considerable
prescience given the current oil price and focus on cost reduction
across the industry. This environment also provides significant
opportunities for us as oil and gas companies look for ways to
preserve their cash whilst still needing to move their projects
forward. Our business model of acquiring interests in projects,
taking them to field development plan and then developing them
using our solutions is a low risk, low cost and faster development
solution for operators - creating what we believe is a very
significant window of opportunity for us as lower oil prices
persist.
As we look to progress our strategy of building a portfolio of
assets that can be developed utilising these solutions, we remain
in discussions with a number of major industry players in order to
build a consortium of like-minded partners who will provide
services and expertise to ensure the delivery of our Marginal Field
Initiative. These are the foundations which we are looking to build
and which, upon completion we believe that these potential partners
will not only allow for a dramatic upturn in activity, but also
provide further considerable industry endorsement of the venture.
Whilst the time frame to setting up and completing this phase of
our initiative has been frustrating, it is essential to ensure that
we bring together the right team of partners and also ensure that
we continue to retain an appropriate level of upside for the
Company and our shareholders. Completing an inappropriate
transaction that stifles the venture is as bad, if not worse, than
not completing a transaction at all.
We believe that our lower cost solutions have a very significant
competitive advantage with our solutions being suitable for the
development of small fields between 16 mmbbls and 22 mmbbls even at
these oil prices, projects which traditional solutions are
currently unable to develop economically. With the cancellation of
projects on fields with as much as 30 mmbbls, which were marginally
economic with higher oil prices, an even more significant
opportunity is now available to us as these larger and often more
highly appraised fields are now no longer economic using
traditional solutions; increasing the number of fields available to
us as well as the potential size of each project.
Whilst lower oil prices have also undoubtedly impacted
financiers appetite for investing in oil and gas projects given the
potential returns from traditional solutions, we believe our
business model and flexible approach for financiers will still be
attractive in the current climate. In fact, the opportunities that
we are presenting which are economic and provide solid returns for
investors at the current prices, will provide very significantly
improved returns should the oil price recover even to $85 per
barrel. Ironically, what we have seen is that the lower oil price
has increased the attractiveness of our offering due to the
excellent economics of developing projects using our solutions
given the significant increases in potential returns that can be
gained when the oil price increases, something we are confident of
given the cyclical nature of the oil and gas industry. Given this
we remain confident that we will be able to add further projects to
our portfolio which we believe will be attractive to the industry
and investors alike.
During the period we also announced a new approach to developing
our assets in western Newfoundland based upon some of the lessons
we have learned in developing the Marginal Field Initiative. This
new approach will see us developing an incremental investment plan
centred on our assets in western Newfound that invites E&P
companies and oilfield service companies to share a portion of
phased development costs and risk in exchange for information,
license equity and guaranteed services. We are already in
discussions with a number of potential partners with a view to
commencing an EFD plan and will provide further updates as they are
agreed.
The Company continues to manage its cashflow carefully and a
number of actions have been implemented during the period, and
since its end, to reduce expenditures. Even allowing for these
measures the implementation of our business plan will require an
injection of new capital. The Board is also very mindful of the
wishes of its shareholders on seeking to avoid dilution at lower
prices and whilst new capital will be required the Board will, in
line with shareholders requests, endeavour to try and ensure that
this does not happen until further milestones have been met.
Allowing for this we have a very attractive and appropriate
business plan and believe that our marginal field initiative offers
us a very significant opportunity and that the value that any
additional capital that is raised should generate should
significantly exceed the effect of any potential shareholder
dilution. We have also been vigilant to ensure that as a company we
are not overburdened by excessive debt. This is a philosophy that
we will continue as in the current climate we are already seeing a
number of oil and gas companies struggling with their debt burdens
to the detriment of their shareholders.
Whilst the current challenges facing our industry, especially in
the UKCS, are substantial, through our strategy of focussing on
reducing Opex and Capex it is my belief that we have a highly
appropriate venture that has a very significant opportunity to grow
in the current climate. What we are undertaking has the potential
to be a truly global initiative and we would also not have
attracted the interest we have if others within the industry did
not feel the same. We are confident, allowing for some potential
hurdles that a lower oil price environment brings, that our
solutions, strategy and model are highly attractive to the industry
and provide an exciting future for the Company.
Alan Minty
Chairman
Operational Review
Marginal Field Initiative - ABT Oil and Gas Ltd.
The Marginal Field Initiative remains the Company's focus and it
is our belief that its success offers a huge opportunity for the
development and growth of the Company. This Initiative is embodied
by ABT Oil and Gas Ltd. ('ABTOG') which is a joint venture ('JV')
between the Company and Advanced Buoy Technology (ABTechnology) Ltd
("ABT").
The business model continues to be to acquire interests in and
build a portfolio of well appraised hydrocarbon discoveries that
are undervalued, generally due to their size and lack of proximity
to infrastructure, and through the application of our appropriate
re-deployable solutions which allow strong returns to be generated,
enable the discoveries to be developed. Our solutions offer a
reduction in Capex, allow for the application of operating
philosophies that significantly reduce Opex and are re-deployable
in a cost effective way so that the disparity between the
production life of the field and useful economic life of the
engineering solution can be managed such that smaller fields are
not disproportionately burdened with Capex. Highly appropriate
solutions given the current climate and focus on costs throughout
the industry.
Whilst we have continued to establish and progress the
foundations of the business; in order to provide additional
confirmation in our ability to deliver the business model it is
imperative that asset owners have the confidence that the solutions
can be delivered. To that extent, ABTOG is looking to build up a
consortium of like-minded major industry players who will provide
services and expertise to ensure the delivery of our Marginal Field
Initiative. These dialogues remain ongoing and the Company is
confident that upon completion these partners will provide
endorsement for the Marginal Field Initiative and have the
potential to significantly increase this venture's activity. The
Company expects that negotiations will be concluded within weeks
and will make an announcement accordingly.
On the Fyne Field, we have, during the period, undertaken work
which has considerably advanced the design and engineering of the
SIFT solution for greater capex reduction and the requirements for
'Normally Unattended' operations to reduce opex in light of the oil
price 'fall' providing deeper understanding of its potential
applications in the UKCS and beyond. As a result of such work and
most importantly, we are able to demonstrate that the solutions are
economic at current oil prices on projects that would normally be
relinquished. The solution proposed for Fyne has proven to provide
a robust economic case for the development of the field but in the
context of a wider regional development 'play' rather than as a
'stand-alone' project. This is the impact of the lower oil price;
marginal fields become larger so there is a change of focus to
opportunities that provide better returns for investment.
In conjunction with Antrim Ventures, ('AEV'), the Company was
offered a production licence on Block 21/28b in the UKCS 28th
Seaward Licensing Round. The offer of this licence allows for two
further discoveries to be incorporated into the Fyne Development
Plan and the Company will update on its implications in due
course.
On Block 22/12b, awarded to the Company in the 27(th) Seaward
Licensing Round, the work programme has been completed as agreed
under the farm-in agreement with Azinor. The programme has
confirmed that oil bearing sands at the Phoenix Discovery
("Phoenix") are contained within a simple and relatively low risk
four way dip closed structure and the advanced technical work has
successfully characterized and isolated these oil bearing sands
from their surroundings. Using the new information, the subsurface
model has been updated, revealing that the base case STOIIP for
Phoenix is likely to be in excess of 16MMBO. Again and as with
Fyne, the impact of the lower oil price has to be recognised; the
Company's view is that Phoenix remains a suitable candidate for
development, but as part of a wider marginal field initiative
'play'. The Company is in discussions with DECC with respect to the
most suitable manner in which to advance the licence.
ABTOG has also previously secured a further significant
opportunity by reaching agreement to farm into the Helvick and
Dunmore discoveries (the "Discoveries") in the North Celtic Sea
Basin, offshore Ireland with Providence Resources. In return for
the opportunity to acquire an aggregate 50% interest in the
Discoveries a phased, three stage work programme will be conducted.
The farm-in is subject to the approval of the Minister of State at
the Department of Communications, Energy and Natural Resources (the
"Minister") granting a Lease Undertaking in respect of each
Discovery, which the Company is currently awaiting.
Western Newfoundland
In Western Newfoundland Enegi has formulated the EFD plan which
is a logical response to lower oil prices and what appears to be a
change in investors' risk appetite regarding the uncertainty of
larger 'plays'. A key characteristic of this plan is the reduction
of risk by incremental project development. Furthermore, the plan
is based upon principles incorporated in the marginal field
initiative where existing prior information is assessed as to its
value now and to the investment necessary to advance a project to
another phase - a highly appropriate strategy for such a frontier
region such as western Newfoundland. This new approach will see us
developing an incremental investment plan centered on our assets in
western Newfound that invites E&P companies and oilfield
service companies to share a portion of phased development costs
and risk in exchange for information, license equity and guaranteed
services. The Company is already in discussions with a number of
potential partners with a view to commencing an EFD plan.
The Directors believe that the benefit for Enegi is significant.
By selling knowledge and equity in existing licences to other
parties on the basis that the Company is carried for prior and
future investment, what is actually being delivered is not only an
incremental and faster farm-in model, but also one that reduces the
risks to the farmee hugely. In this way, the Company expect both
service and existing E&P companies to subscribe to the EFD
plan.
Enegi's primary intent and key to the success of the region is
delineating and developing the discovered Garden Hill Field Trend
with this phased approach, which is expected to act as a catalyst
for increased oil and gas activity in Western Newfoundland, before
expanding operations to look at wider prospects.
During the period the Company also updated its subsurface
evaluation of its western Newfoundland assets. The west coast of
Newfoundland is on the margin of the Anticosti Basin and the
Company believes it to be one of the remaining frontier areas
containing significant hydrocarbon potential. Enegi has identified
a number of significant exploration plays, both conventional and
unconventional, alongside the discovered "Garden Hill Field Trend"
that extends on-to-off shore, using the results gathered from its
own investment and utilising data from previous operators.
Enegi has integrated and analysed subsurface data from across
the region, including seismic, well, and production data from PAP#1
ST#3 ("ST#3"). The most recent internal subsurface model revision
estimates that 406mmbbl may be contained within the mapped Garden
Hill Field Trend, of which approximately 85mmbbl could be
recoverable in the P50 case. The table below shows the STOIIP and
recoverable resources associated with the Garden Hill Field Trend
that is contained in the acreage currently held by Enegi.
PL2002-01(A) P90 P50 P10
-------------------------- ----- ----- -----
Total In-Place (MMBO) 21.6 45.8 97.0
Total Recoverable (MMBO) 4.2 9.6 22.0
-------------------------- ----- ----- -----
As well as defining the presence and extent of the Garden Hill
Field Trend, a number of similar prospects have been identified
along parallel and adjacent structural features - as experienced in
areas where the analogous play models exist (i.e. the Albion-Scipio
Field Trend). Such observations, once established, have the
potential to build significantly upon the upside around the Port au
Port ("PAP") region, and similarly along the west coast of
Newfoundland where this play concept is present. This further
endorses the rationale for the Company's EFD model and
strategy.
Operationally on PL2002-01(A), the Company has now reinstated
production activities at the Garden Hill site, which had been
suspended for a period due to unforeseen mechanical issues. Good
pressure recovery was observed over the period during which the
Well was shut in. The lack of observed pressure depletion continues
to reinforce the Company's confidence in the potential of the
Garden Hill Field with data indicating a minimum connected volume
in excess of 100 million barrels of oil. The Group also continues
to believe that the area covered by the lease renewal, as granted
in August 2012 reflects the view of the Department of Natural
Resources ('DNR') of the Provincial Government of Newfoundland and
Labrador, is inconsistent with the model that best reflects the
geology of the original lease. Consequently, the Group has issued
proceedings to understand the DNR's determination and challenge
that determination as appropriate. This process is currently still
ongoing.
On EL1070 the Group has continued to monitor the work programme
currently being undertaken by Shoal Point Energy ("SPE") which, it
is hoped, will result in an application for a Significant Discovery
Licence over EL1070. EL1070 was due to expire in January 2011, but
has remained in force due to the fact that SPE commenced the
drilling of the 3K-39 well prior to the expiry date. The 3K-39 well
requires hydraulic fracturing techniques to recognise and fully
assess the potential of its target and at this time the Province of
Newfoundland is conducting a review on these techniques.
Non-core Assets
In Ireland we have previously successfully completed our work
obligations under the Claire Basin Licencing Option and have
applied for an exploration licence, however the authorities have
chosen to conduct additional environmental studies before granting
an exploration licence.
In Jordan the Company continues to be involved in a project
aimed at developing the Dead Sea and Wadi Araba block with Korean
Global Energy Corp. The Company is currently waiting for the
licence for the block to be fully approved by the Council of
Ministers and ratified by Parliament.
Financials
The accounts for the period have been prepared in accordance
with the International Financial Reporting Standards as adopted by
the European Union using accounting policies that are consistent
with those stated in the 2014 Annual Report and Accounts.
The Company reports a loss of GBP1,083,000 for the period, a
decrease of GBP198,000 over the corresponding period in 2013. This
is primarily due to the Company reducing its overheads as it
resolves the financial and corporate structure required to
implement its strategy. Additionally, the result for the period
includes a charge of GBP140,000 with respect to the loan from Shard
Capital Management explained more fully below.
The Company received revenue of GBP27,000 during the period
(2013: nil). A series of mechanical delays and uncertainty over the
status of the now terminated farm-in agreement with Black Spruce
Exploration Corp. contributed significantly to activity during the
period. Data collected from the PAP#1-ST#3 well confirms the
Company's view that the asset remains valuable.
Group net assets as at 31st December 2014 were GBP1,385,000
(2013: GBP4,173,000) the reduction in which is largely explained by
the losses that the Company has realised over the following
periods.
Extension of Loan Agreement
At 31 December 2014 the Group had cash balances of GBP17,000,
compared to GBP299,000 at 31 December 2013. In December 2014, the
Company agreed to extend the loan with Shard Capital Management for
a further six months for an additional cost of GBP120,000. The new
terms included the Company taking out an additional loan amount of
GBP200,000 for an additional cost of GBP20,000. The aggregate total
of GBP1,540,000 is repayable to Shard Capital Management within six
months of the period end. The loan is repayable in cash or shares
in the Company at the discretion of the Company.
As part of the terms of the loan extension Enegi entered into a
warrant agreement with Shard Capital Management to subscribe for up
to 10 million Ordinary Shares, such warrants to be exercisable at a
price of 2.3 pence per share, being a 31 per cent premium to the
Company's market closing price on 22 December 2014 and to be
exercisable at any time prior to the expiry of 24 months following
the date of the loan extension.
Future funding and capital requirements
The Directors believe that the Company has developed a very
attractive business model in choosing to participate in the
development of the Marginal Field Initiative. Upon conclusion of
the necessary foundations, its global potential will see an upturn
in activity and the Company will seek to utilise the offering to
increase its project portfolio. Implementation of the business plan
will require an injection of new capital into the business but the
value that it is able to generate should significantly exceed the
effect of any potential shareholder dilution.
CONSOLIDATED INCOME STATEMENT
Unaudited Unaudited Audited
6 months 6 months 12 months
ended 31 ended 31 ended 30
December December June
2014 2013 2014
GBP'000 GBP'000 GBP'000
------------------------------------ ---------- ---------- -----------
Revenue 27 - 45
Cost of sales - - -
------------------------------------ ---------- ---------- -----------
Gross Profit 27 - 45
------------------------------------ ---------- ---------- -----------
Administrative expenses (1,110) (1,281) (4,603)
------------------------------------ ---------- ---------- -----------
Loss from operations (1,083) (1,281) (4,558)
------------------------------------ ---------- ---------- -----------
Finance costs - - (301)
Loss before tax (1,083) (1,281) (4,859)
------------------------------------ ---------- ---------- -----------
Taxation - - -
------------------------------------ ---------- ---------- -----------
Loss for the year (1,083) (1,281) (4,859)
------------------------------------ ---------- ---------- -----------
Loss per share (expressed in pence
per share)
Basic (0.6p) (0.8p) (2.9p)
Diluted (0.6p) (0.8p) (2.9p)
------------------------------------ ---------- ---------- -----------
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
Unaudited Unaudited Audited
As at 31 As at 31 As at
December December 30 June
2014 2013 2014
GBP'000 GBP'000 GBP'000
------------------------------------- ---------- ---------- ---------
Non-current assets
Tangible fixed assets 4,830 6,007 4,828
Intangible assets 1,157 725 1,155
Other long term assets 543 558 538
------------------------------------- ---------- ---------- ---------
6,530 7,290 6,521
------------------------------------- ---------- ---------- ---------
Current assets
Trade and other receivables 619 398 680
Cash and cash equivalents 17 299 232
636 697 912
------------------------------------- ---------- ---------- ---------
Total assets 7,166 7,987 7,433
Current liabilities
Trade and other payables (3,737) (2,826) (3,220)
Due to related parties (1,594) (523) (1,329)
------------------------------------- ---------- ---------- ---------
(5,331) (3,349) (4,549)
------------------------------------- ---------- ---------- ---------
Non-current liabilities
Provisions (450) (465) (448)
------------------------------------- ---------- ---------- ---------
Total liabilities (5,781) (3,814) (4,997)
------------------------------------- ---------- ---------- ---------
Net assets 1,385 4,173 2,436
Shareholders' equity
Ordinary share capital 1,857 1,569 1,857
Share premium account 26,137 24,459 26,137
Reverse acquisition reserve 9,364 9,364 9,364
Other reserves (2,487) (2,496) (2,487)
Warrant reserve 355 355 355
Accumulated losses (33,841) (29,078) (32,790)
------------------------------------- ---------- ---------- ---------
Total equity attributable to owners
of the parent 1,385 4,173 2,436
------------------------------------- ---------- ---------- ---------
CONSOLIDATED STATEMENT OF CASH FLOW
Unaudited Unaudited Audited
6 months 6 months 12 months
ended ended ended
31 December 31 December 30 June
2014 2013 2014
GBP'000 GBP'000 GBP'000
------------------------------------------------ -------- ------------- ------------- -----------
Cash flows from operating activities
Cash used in operations (203) (1,453) (2,512)
Net cash used in operating activities (203) (1,453) (2,512)
------------------------------------------------ -------- ------------- ------------- -----------
Cash flows from investing activities
Expenditure on tangible assets (-) (273) (899)
Net cash used in investing activities (-) (273) (899)
------------------------------------------------ -------- ------------- ------------- -----------
Cash flows from financing activities
Proceeds from Loan - 1,000 1,000
Fees paid to secure Loan - (40) (40)
Funds placed in an Equity Swap - - (500)
Share capital issued for cash - 825 2,730
Net cash flows from financing
activities - 1,785 3,190
------------------------------------------------ -------- ------------- ------------- -----------
Net (decrease) / increase in
cash and cash equivalents (203) 59 (221)
Cash and cash equivalents at
the start of the year 232 71 71
Exchange (losses) / gains (12) 169 382
Cash and cash equivalents at
the end of the year 17 299 232
------------------------------------------------ -------- ------------- ------------- -----------
NOTE: These statements have been prepared under International
Financial Reporting Standards as adopted by the European Union
using accounting policies consistent with those in the last Annual
Report.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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