TIDMOPHR
RNS Number : 9321Y
Ophir Energy Plc
09 March 2017
9 March 2017
Ophir Energy plc
Full Year Results for the year ended 31 December 2016
Commenting on the results, Nick Cooper, Chief Executive Officer,
Ophir Energy said:
"2016 saw Ophir adopt the simple maxim "find low, monetise
smartly". Our decision to re-orient the Group's activities around
net asset value per share has changed our corporate mindset. All
activities are now focused on finding or developing hydrocarbons at
the lowest cost and monetising promptly and swiftly; thereby
maximising the margin realised for shareholders. In 2016, Ophir
delivered the start-up of the Kerendan gas field, we advanced the
Fortuna FLNG project towards FID and significantly reduced our
G&A cost (for a third year running).
"We are looking for 2017 to deliver material milestones. A green
light for Fortuna, expected in mid-2017, will unlock 345 MMboe for
monetisation. Subject to the volume of gas we choose to term up,
this could treble our Group 2P reserves in the process. Plans to
sweat our Asian assets have the potential to monetise up to a
further 80 MMboe over the next three years.
"At the same time, Ophir will be resuming operated exploration
and the Ayame-IX well in Côte d'Ivoire is expected to spud in May
2017. With production, development and exploration programmes
gathering pace, Ophir is moving towards our ambition of being a
sustainable explorer."
Financial Sustainability
-- Revenue of $107 million (2015: $178 million) with a further
$15 million (2015: $17 million) for Sinphuhorm accounted for using
the equity method
-- Cash generated from operations of $62 million(1) (2015: $113 million)
-- Cash on the balance sheet of $360 million (2015: $615
million, including short-term cash deposits)
-- Net cash on balance sheet of $160 million (2015: $355 million)
-- Achieved a further 35% reduction in net G&A costs
(1) See Financial Review Sources and uses of funds summary table
Monetisation of Resource
-- Reached agreement with OneLNG to form a Joint Venture that
will facilitate the development of the Fortuna gas field,
Equatorial Guinea, with FID expected during mid-2017, monetising
345 MMboe
-- Worked over 1.8 million man hours incident free
-- Achieved 99.6% production uptime, leading to average daily
production of 10,800 boepd (including Sinphuhorm), in line with
expectations
-- Completed a produced water debottlenecking project on the Bualuang field, Thailand
-- Expansion of Kerendan asset approved by Indonesian authorities
Finding Low
-- Ayame-1X exploration well in Cote d'Ivoire matured to
drill-ready and will spud in 2Q 2017, targeting 234 MMbo of gross
mean prospective resource
-- Added 158 MMboe of risked, drill-ready, prospective resource to the prospect inventory
-- Completed the Trepang 3D seismic survey in West Papua IV/Aru
licences in Indonesia and matured a number of prospects to
drill-ready
-- Commenced an onshore 3D seismic programme in Greater Kerendan
area with a view to expanding this asset
-- Entered Mexico with a successful bid for Block 5 in the Mexico deepwater licensing round
A presentation for analysts will be held at 10.30am this
morning. This will be webcast live through the link on the Company
website: www.ophir-energy.com/investors.
Ends
For further enquiries please contact:
Ophir Energy plc +44 (0)20 7811 2400
Nick Cooper, CEO
Tony Rouse, CFO
Geoff Callow, Head of Investor Relations and
Corporate Communications
Brunswick Group +44 (0)20 7404 5959
Patrick Handley
Wendel Verbeek
Chief Executive Officer's review
Last year in this report we described how the upstream E&P
sector had, in our view mistakenly, prioritised growth over returns
through the last up-cycle. As we promised in early 2016, Ophir has
reformed its business model. We have also adjusted our investment
strategy and compensation structure to focus resolutely on Net
Asset Value (NAV) per share. These reforms have been positively
received by investors. As an organisation, we are determined that a
more benign oil price environment will not distract us from what we
consider to be the best approach to sustainable, through-cycle,
growth in shareholder value.
Ophir's role in the value chain is to find molecules at the
lowest possible cost and monetise them at the highest possible
price, as promptly as is feasible. Upstream, like any other
business, is about margins achieved, rather than daily spot prices.
Focusing on assets with low breakeven prices, and then delivering
healthy product margins through smart monetisation will sustainably
create value through the cycle.
The monetisation model
The steps we took to put this 'find low, monetise smartly' model
into practice were threefold:
Firstly, in order to improve our ability to 'find low', we
needed both to significantly reduce our running costs and realign
our exploration portfolio to search for barrels that break even at
low prices. We delivered a material reduction in our G&A cost,
improving efficiencies across the business. We also exited five
exploration blocks that failed to meet our stricter investment
criteria and entered three new blocks that did.
Secondly, we sharpened our monetisation focus, both through
lowering opex on producing assets, and more rapid conversion of our
substantial 2C resources into producing 2P reserves or, better
still, cash. This focus saw us progress the Kerendan gas field to
first gas, prepare the Bualuang oil field for the next phase of
development and drive the Fortuna FLNG project closer to Final
Investment Decision (FID). In total, these steps offer the
potential to convert approximately 140 MMboe of 2C resources to 2P
in 2017, more than trebling our current 2P reserves.
Thirdly, we transformed corporate behaviour by introducing our
new NAV per share remuneration scheme for all employees. This
compensation approach is, we believe, far better aligned to
shareholders interests than a relative TSR metric in a cyclical
industry. We have been tremendously encouraged by how the new
approach has clarified investment decision-making and sharpened our
allocation of people and capital. I would like to thank our
shareholders for supporting this radical new scheme at our 2016
AGM.
Milestones in 2016
Ophir's progress in 2016 across these three areas has been rapid
and substantial. We are convinced that the changes that Ophir made
in early 2016 now position the Company to thrive in this new
upstream environment and deliver sustainable, superior total
shareholder return through the coming cycles.
In terms of finding at lowest cost, our model is to drive NAV
growth through sustainable, prudent exploration that is consistent
through the cycle. We believe that we can drill around two to three
material, frontier exploration wells per annum, whilst maintaining
sufficient technical rigour. We estimate that this drilling rate
would represent 10-25% of total global, frontier drilling by the
independent sector through the cycle.
I am pleased to say that we are now returning to operated
exploration drilling. Preparations for the Ayame-1X well in Côte
d'Ivoire started in 2016 to be ready for an expected spud in May
2017. This would represent Ophir's first deepwater operated well in
almost three years. As with our upstream peers, the fact that our
drilling targets are now competing for scarcer, but discretionary,
risk capital allows more high grading and should deliver better
risked outcomes from the portfolio.
In terms of monetising smartly, Ophir's exploration has, thus
far, resulted in the discovery, and part-monetisation, of two,
world-class assets in Tanzania and Equatorial Guinea.
In Tanzania, we have to date monetised the majority of our
interests and have delivered a material return on our historic
investment. In 2016, we saw a renewed push from the Tanzanian
Government to deliver the LNG project and the introduction of a new
operator in Shell. Both factors should accelerate the project
towards an FID later this decade. In 2017, our focus in Tanzania
remains to maximise shareholder returns from our remaining 20%
stake.
In Equatorial Guinea, we have made material progress toward
completing and financing an LNG value chain in the context of a
challenging market. After frustrations in the first half of 2016,
an innovative approach to value chain partnering and risk sharing
unlocked the problem. A constructive dialogue with our midstream
partner Golar LNG enabled us to find a solution that satisfies the
trends emerging in LNG pricing, contracting, financing and risk-
sharing. In November 2016 we signed a Shareholders' Agreement with
OneLNG - a joint venture between Golar LNG and Schlumberger - to
form a new Joint Venture (JV) that will finance and develop the
Fortuna project.
The establishment of the JV means we can now move the Fortuna
FLNG Project towards FID in mid-2017. At FID, the project NPV will
be a healthy multiple of the $120 million of capital we are
committing before first gas. Furthermore, the JV has been
structured so that Ophir Energy plc will not take any additional
balance sheet exposure or liabilities.
Ophir now has line of sight on its biggest potential
monetisation step since the Tanzania partial divestment in 2014. It
has been a long, difficult road but we are firmly on track for a
mid-2017 FID, which will monetise approximately 345 MMboe of 2C
resource. This will be one of a handful of global FIDs of a
green-field LNG project in 2017.
Monetising resource in this challenging environment demonstrates
Ophir's commercial acumen; a valuable complement to our skilled
team of geo-scientists and their ability to efficiently find
hydrocarbons.
At Ophir, we also recognise that capital return to shareholders
needs to start as early as possible. Once we reach our goal of
generating sufficient cash flow to be a sustainable explorer, we
will be in a better position to consider making returns to our
shareholders. The annuity-type cash flows that we will receive from
the Fortuna FLNG asset mean that Ophir's sustainability, and
therefore the predictability of capital returns, should become
increasingly visible towards the end of the decade.
As I look ahead to trends for 2017, breaking down barriers
between industry and value-chain players is a pre-requisite. The
exploration director of a major oil and gas company recently put
this best when they told us "now is a time for the industry to
collaborate, as we are all in this together; we can compete again
if necessary in the next decade". More exploration companies are
recognising the benefits from working together, sharing data and
knowledge to try to focus capital towards the best
opportunities.
A second area that is rightly attracting increasing attention is
the role of upstream players in the climate change challenge. At
Ophir, we recognise that we cannot put our head in the sand. We are
not about to transform to a renewable energy company, but we do see
a need for modified thinking and we have spent time in 2016
developing a position on this. This will evolve, but the topic is
now on the Board's agenda.
Ophir is now better-placed than we have been for several years.
I firmly believe, with the changes we have made to our business
model, our culture and our approach to resource allocation that we
can begin to deliver material returns for our shareholders.
I would like to thank Ophir's investors for their support and
patience, and Ophir's team for their energy, loyalty and bright
ideas despite the tough times.
As described in the Chairman's section, Nic Smith stood down as
Chairman in 2016 to be replaced by Bill Schrader. I thank Nic for
all his guidance and support to Ophir since its inception.
Regardless of what may, or may not, happen to commodity prices
in 2017, the changes that Ophir made in 2016 mean that we can look
forward with confidence and optimism.
Review of operations
As the organisation becomes increasingly focused on creating
growth in NAV per share, we are applying greater discipline when
allocating capital to our operating activities. Our first priority
is in safely maximising the value of the cash returns from our
production base. We can then think about where else in the
portfolio to deploy that capital in the pursuit of further value
creation.
During 2016 we have invested in additional facilities at the
Bualuang field to improve the production capacity of the
infrastructure; brought the Kerendan gas field onstream,
diversifying our production base; progressed the Fortuna FLNG
project towards FID; and continued to build the prospect inventory
to provide drilling options for 2017/2018.
As we look ahead through 2017, we will continue to invest in
both Bualuang and Kerendan to increase the cash generation of the
asset base. This is expected to lead to cash flow materially higher
than in 2016. The Fortuna FLNG project should move through FID in
mid-2017, providing a clear timeline to first production and cash
flow.
We will recommence exploration drilling in 2Q 2017 with a well
on the Ayame-1X prospect in Côte d'Ivoire.
Taken as a whole, we are confident that we will unlock further
value in our production base during 2017 and hope that we can also
create value through opening up a new play in Côte d'Ivoire.
Health, Safety, Security and Environment
Ophir is committed to protecting the health, safety and security
of our workforce and environments in which we work.
We do this through the deployment of HSSE risk management
systems that include the use of leading indicators to test the
robustness of our controls. Over 1.83 million hours were worked
during 2016 with no recordable injuries or illnesses and no loss of
containment events. These were excellent achievements.
Resource and reserves monetisation
Let us look at the application of our strategy at an operational
level. Reliable, diversified cash flow from our production base is
an important part of our strategy to become a sustainable explorer.
We have invested, and will continue to invest, in our production
base where there is an opportunity to enhance operating cash flow
per boe at attractive returns.
Ophir will only proceed with development projects that offer
demonstrable value creation for equity holders without undermining
the Group's funding position or its exploration-led strategy. As
such, we may look to partially or wholly monetise on discovery or
prior to significant investment to deliver the highest
risk-weighted returns to shareholders.
Bualuang, Thailand (20.9 MMbo 2P, 17.8 MMbo net 2C)
Our strategy for managing the Bualuang field is to maximise
cashflow through safe, reliable and cost-efficient production
operations, combined with the appropriate capital deployment to
further develop contingent resources. Bualuang is currently the
most cash-generative asset in the Ophir production portfolio. In
2016, it generated $58 million of cash from average daily
production of 8,700 bopd.
Our main focus at Bualuang during the year was to complete a
water debottlenecking project that increased water handling
capability by 50% to enable an increase in production and,
consequently, cash generation.
The water debottlenecking project cost a total of $21 million
and is expected to increase the NPV10 of the field by $83 million
with investment payback approximately 12-18 months after
completion.
As we look forward, the key challenge at Bualuang is how we
create further value and increase the cash generation of the field.
The ocean bottom node 3D seismic data, acquired in 2015 to image
under the platform, was processed and interpreted in 2016 and is
key to determining how we unlock additional value from the
field.
In 2017, we will complete a small infill drilling programme
consisting of two development wells. This will see old well stock
recycled to target new locations with the goal to grow production
by around 1,400 bopd. The investment in this programme will be c.
$12 million and is expected to add $23 million to the NPV of the
project and payback within 12 months.
We will also drill a further well targeting prospective resource
in the Bualuang field.
We are also in the final technical and commercial analysis stage
of the opportunity to expand the production capacity at Bualuang by
the installation of a simple, low-cost platform. Additional well
slots will enable the targeting of locations to convert prospective
and contingent resources to reserves. We expect to be in a position
to make an FID on the next phase of development in 2Q 2017.
Kerendan, Indonesia (15.9 MMboe 2P, 60.3 MMboe net 2C)
The primary challenge at Kerendan now that the field is
producing, is to seek innovative ways to monetise the 457 Bcf of
gross 2C contingent resource not covered by the initial gas sales
agreement (GSA).
The field produced at an average of 768 boepd over the period in
2016 that it was producing, but is expected to ramp up to full
contract volume of closer to 20 MMscfd in 2017, providing
additional cash flows. The offtaker contracted to take 16 MMscfd
from 11 January 2016 and, under the take or pay provision in the
GSA, a receivable of $17 million has been accrued. This was settled
in full in February 2017.
A significant step forward in monetising the additional 2C
resource in the Kerendan area occurred in late 2016 with SKKMigas
approving the West Kerendan-1 expansion plan.
This will allow an additional 40 Bcf to be monetised that will
grow production by 7 MMscfd from 2019. Making further progress on
the monetisation of the 457 Bcf of gross contingent resource, not
covered by the first GSA, is an area of focus for 2017. Safe
completion of the onshore 3D seismic acquisition programme,
forecast to complete in Q4 2017, is a key step on this pathway.
These data will allow for better definition of the Kerendan field
to give greater certainty around resource volumes, which should
ultimately lead to SKKMigas approving the sale of additional gas
volumes.
Sinphuhorm (7 MMboe 2P, 21.3 MMboe net 2C)
Gas production from Sinphuhorm was 10% ahead of budget at 1,900
boepd. This was principally as a result of the poor performance
from the competing hydropower sector.
Fortuna, Equatorial Guinea (400.7 MMboe net 2C)
The Fortuna project was the asset most in the spotlight during
2016 as we sought to find a way to monetise the 400 MMboe of net 2C
resource we have discovered in the play to date. Our focus has
always been on monetising this asset in a manner that maximises
value creation for our shareholders.
We have continued to move this project forward for one simple
reason - the point forward returns are excellent, as it is a
low-cost project with a world-class reservoir. Admittedly, we have
had our setbacks on this project, no more so than in the early part
of 2016 when Schlumberger withdrew from a planned upstream farm-in.
Having worked closely with our then midstream partner, Golar LNG,
to find a funding solution for the midstream part of the project,
we were delighted to sign a Shareholders' Agreement with OneLNG in
November 2016 for the formation of a Joint Venture that will
develop and finance the Fortuna FLNG project.
OneLNG is a joint venture owned by Golar LNG and Schlumberger to
help monetise stranded gas assets. We now have an integrated
project with Ophir and OneLNG aligned across the value chain. Ophir
will not invest more than $120 million of the $2 billion of capital
expenditure required to get to first gas and we expect to generate
a return of over 5x on this investment.
Since announcing the JV in November 2016 we have made good
progress against the remaining milestones. The Umbrella agreement
between the Fortuna JV and the Government of Equatorial Guinea is
expected to be signed during 1Q 2017. This defines the legal and
fiscal framework for the project.
A term sheet has been signed for the provision of the debt
facility with a consortium of Chinese banks. We have now moved to
the documentation phase and expect to close the facility during 2Q
2017.
The discussions with offtakers remain on-going and are expected
to be closed out imminently.
We expect to issue a shareholder Circular during 2Q 2017 with
FID remaining on schedule for mid-2017.
Blocks 1 and 4, Tanzania (500.2 MMboe net 2C)
In Tanzania, Shell took over the operatorship from BG Group in
March 2016 and has since undertaken a review of the project plan,
the development scope and the cost stack of the project.
Separately, since the elections in Tanzania in late 2015, the
new Government has taken a more pro-active, hands-on approach to
delivering the project. An integrated negotiating team, with
representatives from all the key ministries, has been established,
with the remit to deliver the required project agreement for the
onshore LNG plant. Once this is agreed, there will be a clear legal
framework under which the development can be moved forward.
After completing the final exploration commitment wells on
Blocks 1 and 4 in late 2016, the Minister of Energy awarded an
extension of Block 1 for a further three and a half years to
provide sufficient time to complete pre-FEED and FEED ahead of
investment approval. An extension for Block 4 is expected later in
2017. Ophir will continue to determine the optimum way to monetise
the asset to deliver value for shareholders.
Exploration
Ophir's strategy is to create value for shareholders through
finding resources at low cost and monetising them smartly in the
way that maximises the value created.
We have been actively maturing the best prospects on the plays
we have high-graded, adding new plays to compete for capital with
the existing opportunities. We have looked at numerous data rooms
in the past three years to rank the best opportunities. As a
result, Ophir has positions in a number of high graded plays, all
of which have prospects that have cleared commercial and technical
thresholds and have increased the Group's risked prospective
resources by 158 MMboe.
During 2016 we entered three new licences. The first of these
was a new country entry in Côte d'Ivoire when we signed a PSC for
Block CI-513.
The Ayame-1X prospect will spud in 2Q 2017 and we are currently
carrying mean prospective recoverable resource of 234 MMbo with a
23% geological chance of success. The well will be drilled by the
Seadrill West Saturn rig and the gross cost is expected to be $30
million. It is a stratigraphic prospect testing an extension of a
proven petroleum system in the adjacent block and the main risk is
trap effectiveness.
We also entered the DW-2A licence in Malaysia and will take a
drill or drop decision in 1H 2017.
Our third new licence entry was in Mexico, which followed work
by our Global New Ventures team screening opportunities outside our
Asian and African heartland. Our interest in Mexico was a result of
the liberalisation of the energy sector, which meant that for the
first time in nearly 80 years international companies would be able
to bid for acreage in Mexican waters of the Gulf of Mexico. Fewer
than 45 deepwater exploration wells have been drilled in Mexico
compared with over 1,200 on the US side, creating a rare
opportunity to access an under-explored, but proven world-class
basin. The basin also screened well from a commercial basis and
there is a clear path to monetisation.
Ophir is part of a Murphy-operated consortium, also containing
PC Carigali (part of Petronas) and Sierra Oil & Gas, that won
the rights to Block 5 in the first deepwater licence round in
December 2016. Drilling is not expected to take place until 2019
and the net cost to Ophir of the first phase work programme is
limited.
In Myanmar, we have matured the prospect inventory to
drill-ready status. The play looks to be comprised of sands in low
relief channel systems leading us to believe that Myanmar will
likely be developed by the aggregation of gas fields. We are
currently seeking to farm-down to a strategic partner and we view
this as a pre-requisite to drilling.
In Equatorial Guinea, the southwest portion of Block R contains
a potential extension of an oil play in the neighbouring block
which is operated by an IOC. The operator of the adjoining block
completed a 3D seismic survey in 2016 that was extended into Block
R. These data have been processed and our geoscientists, along with
those of the operator, are reviewing the prospectivity ahead of a
decision on whether to drill a well.
In Indonesia, we safely completed the offshore Trepang 3D
seismic survey on the West Papua IV and Aru licences in 4Q
2016.
We also completed the reprocessing of existing seismic data over
the West Papua IV and Aru licences which has enabled us to mature a
number of leads to prospects.
In Gabon, we have extended the Nkouere and Nkawa licences and
are using the Olumi Rouge 3D seismic data to mature a new outboard
play. We believe this play has multi-billion barrel potential and
we are currently seeking to farm-down to a partner prior to
entering into the second phase of the exploration licence.
Financial review
Sources and uses of funds summary
Net sources of funds: Units FY 2016 FY 2015 FY 2014
---------------------------------- ------------ -------- -------- --------
Revenue (including hedges) $'millions 107.2 178.2 -
---------------------------------- ------------ -------- -------- --------
Kerendan take-or-pay $'millions 16.5 - -
---------------------------------- ------------ -------- -------- --------
Cost of production (operating
expenses, royalty, inventories) $'millions (42.7) (47.9) -
---------------------------------- ------------ -------- -------- --------
Investment income $'millions 4.4 7.2 -
---------------------------------- ------------ -------- -------- --------
Income tax charge $'millions (23.7) (24.6) (210.4)
---------------------------------- ------------ -------- -------- --------
Total net sources of funds
from production $'millions 61.7 112.9 (210.4)
---------------------------------- ------------ -------- -------- --------
Net uses of funds:
---------------------------------- ------------ -------- -------- --------
Capex (less disposals)(1) $'millions 155.6 205.6 (685.3)
---------------------------------- ------------ -------- -------- --------
Net administration cost $'millions 13.4 31.3 20.7
---------------------------------- ------------ -------- -------- --------
Net finance costs $'millions 14.3 15.7 (7.0)
---------------------------------- ------------ -------- -------- --------
Total net uses of funds $'millions 183.3 252.6 (671.6)
---------------------------------- ------------ -------- -------- --------
Financing cash flow and debt:
---------------------------------- ------------ -------- -------- --------
Closing gross cash $'millions 360.4 614.6 1,172.8
---------------------------------- ------------ -------- -------- --------
Closing borrowings $'millions 200.3 259.6 -
---------------------------------- ------------ -------- -------- --------
Closing net cash $'millions 160.1 355.0 1,172.8
---------------------------------- ------------ -------- -------- --------
(1) Capex is adjusted to eliminate non-cash amounts for
decommissioning for 2016 of $19.2 million (2015: $1.5 million) and
capitalised interest for 2016 of $8.7 million (2015: $1.5
million).
Summary
As detailed in the Chief Executive Officer's review, our
strategy is to be a sustainable explorer, focused on delivering NAV
per share growth, by finding resources at low cost and then
monetising them smartly in the way that maximises the value
created. This requires us to generate sufficient cash flow over
time, through a combination of maximising cash flow from our
production assets and the monetisation of our exploration success,
to fund a sustainable exploration programme.
Our first step to build this cash flow, was the acquisition of
Salamander Energy in early-2015. This transaction provided Ophir
with two producing assets in Thailand, Bualuang and Sinphuhorm, and
a development asset in Indonesia, Kerendan, which came onstream in
August 2016.
During 2016, we took a further step towards achieving our
objective of becoming a sustainable explorer. Through our agreement
with OneLNG, we will form a Joint Venture (JV) to facilitate the
financing, construction and development of the integrated Fortuna
project in Equatorial Guinea. This provides a framework whereby we
can now move forward to commercialise the asset with a 33.8% equity
interest in the JV. Through these arrangements, we have limited our
capital and balance sheet exposures to a maximum of $120 million.
We expect to take FID on the project by mid-2017 and the asset is
expected to be on-stream mid-2020 delivering net cash flow to us of
approximately $140 million per year (at an indicative FOB gas price
of $6.00 MMbtu). The cash flow generated from Fortuna, along with
the cash flow from our Asian production base, will see us broadly
achieve our strategic objective of becoming a sustainable
explorer.
Our principal financial goals are therefore to ensure that we
preserve our balance sheet strength and maintain sufficient
liquidity between now and Fortuna coming on-stream. In the
meantime, funds will be invested as a priority to the further
monetisation of our existing asset base with our exploration
efforts being scaled according to the availability of residual
capital.
Additionally, during 2016 we took further steps to preserve our
liquidity by lowering our capital and operating cost base. We also
reduced our gross administration cost base with a further reduction
year on year (excluding one-off restructuring costs) of 31%.
Commodity prices strengthened during the second half of the year
with the OPEC agreement in November further underpinning positive
sentiment around oil prices. Brent recovered from a low of $27 per
barrel in January to a high of $57 per barrel in December, and
averaged $45 per barrel for the year. Brent pricing has been more
stable in early 2017 than for some time, but the outlook remains
cautious, and we will therefore continue to scale our future
programmes according to our capital constraints until we have
secured a sustainable cash flow.
Net sources of funds
2016 working interest production was in line with guidance at
10,800 boepd. This comprised 8,700 bopd from Bualuang and our first
contribution from Kerendan which averaged 200 boepd for the year.
In addition, 1,900 boepd was produced from Sinphuhorm (which is
accounted for using the equity method).
Revenue (including realisation of hedges) from Bualuang totalled
$107 million or $38 per barrel (2015: $178 million or $47 per
barrel). With a breakeven for 2016 of $15 per barrel, Bualuang
delivered positive post-tax funds flow of $58 million or $18 per
barrel (2015: $106 million or $34 per barrel). The Kerendan field
came onstream in August, with pre-production operating costs being
charged to the income statement in 2016, Kerendan utilised net
funds of $8 million. However, this amount was more than offset by
recognising $17 million of deferred income to the balance sheet for
the PLN take-or-pay obligation for volumes not drawn-down since the
commencement of the GSA on 11 January 2016. The take-or-pay amount
was settled in full by PLN in February 2017.
Full-year 2016 net sources of funds from production totalled $62
million (2015: $113 million), a 45% reduction year-on-year
predominantly due to lower commodity prices.
With an improved commodity price outlook in 2017 and the
Kerendan asset on-stream for the full year, post-tax funds flow
from production is forecast to increase to $80-120 million or
$18-27 per barrel.
Uses of funds
The Group's primary investments during 2016 were:
-- Exploration of $76 million (2015: $140 million)
including:
- Acquisition of Côte d'Ivoire Block CI-513 ($20 million)
- Myanmar AD-03 - well planning and Environmental Impact Assessment ($9 million)
- Acquisition of Malaysia Block 2A ($8 million)
- Indonesia - seismic data acquisition on the West Papua IV and Aru blocks ($8 million)
-- Monetisation of resource of $80 million (2015: $68 million)
comprising predominantly:
- Tanzania, Blocks 1 and 4 - drilling and pre-development spend ($22 million)
- Equatorial Guinea, Fortuna - Front End Engineering Design ($42 million)
- Thailand, Bualuang - water debottlenecking project ($12 million)
Of the 2016 exploration expenditures, we charged and wrote-off
$6 million (2015: $24 million) to the income statement. In
addition, we wrote-off prior year expenditures of $94 million
(2015: $125 million) following our decision to relinquish the G4/50
licence in Thailand and assessing the portfolio in Indonesia.
Our cost reduction programme saw gross administration cost
reduce by a further 31% in 2016. This is reflected in our net
administration expense reducing to $13 million (2015: $31 million),
a reduction of 35% after eliminating one-off restructuring costs of
$2 million in 2016 (2015: $14 million).
We incurred interest charges during 2016 of $14 million (2015:
$16 million) against average gross debt of $230 million, giving
rise to an average cost of debt of 7%. We took steps in 2016 to
lower our borrowings thus reducing the negative interest carrying
cost.
Overall, uses of funds for 2016 totalled $183 million (2015:
$199 million).
Looking ahead to 2017, our capital expenditure is forecast at
$125-175 million with plans including:
- Thailand, Bualuang - infill drilling programme ($24 million)
- Côte d'Ivoire - drilling of the Ayame-1X exploration well ($16 million)
- Equatorial Guinea - initial funding for the Fortuna JV ($25 million)
Longer term, the Group's future financial commitments beyond
2017 are limited to $33 million (2016: $48 million) against agreed
exploration work programmes.
Debt and net debt
During 2016 we reduced our total debt outstanding by repaying
$59 million of our reserve based lending facility. This gave rise
to outstanding debt at year-end 2016 of $200 million. This
comprised of our reserves based lending facility of $93 million
(2015: $210 million) and our high yield Nordic bond of $107 million
(2015: $107 million).
In late 2016, we commenced the process of refinancing our debt
facilities. This process is expected to complete in 2Q 2017 with an
increase to our borrowing capacity.
Our balance sheet therefore remains robust with closing gross
cash of $360 million (2015: $615 million, including short-term cash
deposits) and net cash at year-end 2016 of $160 million (2015: $355
million). We expect to remain approximately gross cash neutral in
2017 with our capital expenditure programmes covered by a
combination of funds generated from our production assets and
additional cash made available through the refinancing of the debt
facilities. We currently forecast that gross cash will be $375-425
million and that net cash will be $100-125 million at year-end
2017.
The Directors have also considered the longer-term viability of
the Company to end-2020. Based on their assessment, the Directors
have a reasonable expectation that the Company will be able to
continue in operation and meet its liabilities as they fall
due.
Consolidated income statement and statement of other
comprehensive income
For the year ended 31 December 2016
2016 2015
Consolidated income statement $'000 $'000
========================================= ==== ========= ===========
Continuing operations
Revenue 107,178 161,090
Cost of sales (95,443) (128,816)
=============================================== ========= ===========
Gross profit 11,735 32,274
Gain on farm-out - 245
Share of profit of investments accounted
for using the equity method 4,417 7,219
Impairment reversal/(expense) of
oil and gas properties 84,100 (126,732)
Impairment of investments accounted
for using the equity method - (42,117)
Exploration expenses (135,252) (183,137)
Other operating income/(expenses) 19,945 (25,258)
General and administration expenses (13,428) (31,252)
=============================================== ========= ===========
Operating loss (28,483) (368,758)
Net finance expense (21,595) (10,662)
Other financial gains - 3,372
=============================================== ========= ===========
Loss from continuing operations
before taxation (50,078) (376,048)
Taxation (expense)/benefit (27,368) 53,596
=============================================== ========= ===========
Loss from continuing operations
for the year (77,446) (322,452)
Attributable to:
Equity holders of the Company (77,446) (322,452)
=============================================== ========= ===========
(77,446) (322,452)
============================================== ========= ===========
Earnings per ordinary share
Basic - (Loss)/profit for the period
attributable to equity holders of (11.0)
the Company cents (47.1)cents
========================================= ==== ========= ===========
Diluted - (Loss)/profit for the
period attributable to equity holders (11.0)
of the Company cents (47.1)cents
========================================= ==== ========= ===========
Consolidated statement of other
comprehensive income
========================================= ==== ========= ===========
Loss from continuing operations
for the year (77,446) (322,452)
Other comprehensive income/(loss)
Other comprehensive income/(loss)
to be classified to profit or loss
in subsequent
periods: Exchange differences on
retranslation of foreign operations
net of tax 31 (702)
Other comprehensive income/(loss)
for the year, net of tax 31 (702)
=============================================== ========= ===========
Total comprehensive loss for the
year, net of tax: (77,415) (323,154)
=============================================== ========= ===========
Attributable to:
Equity holders of the Company (77,415) (323,154)
=============================================== ========= ===========
(77,415) (323,154)
============================================== ========= ===========
Consolidated statement of financial position
As at 31 December 2016
2016 2015
Notes $'000 $'000
============================================= ====== ====================== ==========
Non-current assets
Exploration and evaluation assets 4 310,229 879,914
Oil and gas properties 5 699,000 662,177
Other property, plant and equipment 3,706 5,140
Investments accounted for using the equity
method 130,736 130,200
Financial assets 21,103 27,253
1,164,774 1,704,684
============================================= ====== ====================== ==========
Current assets
Assets classified as held for sale 588,770 -
Inventory 46,738 50,216
Taxation receivable 15,178 22,322
Trade and other receivables 32,319 32,071
Cash and cash equivalents 360,424 614,569
1,043,429 719,178
============================================= ====== ====================== ==========
Total assets 2,208,203 2,423,862
============================================= ====== ====================== ==========
Current liabilities
Trade and other payables (93,398) (115,971)
Interest-bearing bank borrowings due within
one year (9,741) (37,059)
Taxation payable (13,226) (38,056)
Provisions (15,833) (47,737)
============================================= ====== ====================== ==========
(132,198) (238,823)
============================================= ====== ====================== ==========
Non-current liabilities
Other Payables (10,285) -
Interest-bearing bank borrowings (83,915) (115,949)
Bonds payable (106,651) (106,651)
Provisions (50,550) (67,190)
Deferred tax liability (249,527) (245,745)
(500,928) (535,535)
============================================= ====== ====================== ==========
Total liabilities (633,126) (774,358)
============================================= ====== ====================== ==========
Net assets 1,575,077 1,649,504
============================================= ====== ====================== ==========
Capital and reserves
Called up share capital 3,061 3,061
Reserves 1,572,296 1,646,723
============================================= ====== ====================== ==========
Equity attributable to equity shareholders
of the Company 1,575,357 1,649,784
============================================= ====== ====================== ==========
Non-controlling interest (280) (280)
============================================= ====== ====================== ==========
Total equity 1,575,077 1,649,504
============================================= ====== ====================== ==========
The consolidated financial statements of Ophir Energy plc
(registered number 05047425) were approved by the Board of
Directors on 8 March 2017.
On behalf of the Board:
Nick Cooper
Chief Executive Officer
Tony Rouse
Chief Financial Officer
Consolidated statement of changes in equity
For the year ended 31 December 2016
Called up Treasury Other Non- controlling Total equity
share capital shares reserves interest $'000
$'000 $'000 $'000 $'000
============================ ============================ ========================== ========== ========================== ============
As at 1 January 2015 2,474 (59) 1,695,904 (280) 1,698,039
Loss for the period, net
of tax - - (322,452) - (322,452)
Other comprehensive loss,
net of tax - - (702) - (702)
============================ ============================ ========================== ========== ========================== ============
Total comprehensive loss,
net of tax - - (323,154) (323,154)
New ordinary shares issued
to third parties 587 - 325,545 - 326,132
Purchase of own shares - (99) (56,011) - (56,110)
Exercise of options - 3 - - 3
Share-based payment - - 4,594 - 4,594
============================ ============================ ========================== ========== ========================== ============
As at 31 December 2015 3,061 (155) 1,646,878 (280) 1,649,504
Loss for the period, net
of tax - - (77,446) - (77,446)
Other comprehensive income,
net of tax - - 31 - 31
============================ ============================ ========================== ========== ========================== ============
Total comprehensive loss,
net of tax - - (77,415) - (77,415)
Exercise of options - 2 - - 2
Share-based payment - - 2,986 - 2,986
============================ ============================ ========================== ========== ========================== ============
As at 31 December 2016 3,061 (153) 1,572,449 (280) 1,575,077
============================ ============================ ========================== ========== ========================== ============
Consolidated statement of cash flows
For the year ended 31 December 2016
2016 2015
$'000 $'000
======================================================= === ============== =========
Operating activities
Loss before taxation (50,078) (376,048)
Adjustments to reconcile loss before taxation to
net cash provided by operating activities
Exploration expenses 135,252 183,137
Depreciation and amortisation 55,238 85,127
Impairment (reversal)/charge on oil and gas properties (84,100) 169,307
Share of profits from joint ventures (4,417) (7,219)
Net finance expenses and other financial gains 8,172 30,394
Net foreign currency loss/(gain) 13,424 (6,014)
Share based payment expense 2,986 4,594
(Decrease)/increase in provisions (19,322) 20,687
------------------------------------------------------------ -------------- ---------
Cash flow from operations before working capital
adjustments 57,155 103,965
------------------------------------------------------------ -------------- ---------
Increase in inventories (9,584) (7,172)
Decrease in other current and non-current payables (2,212) (52)
Decrease in other current and non-current assets 5,502 25,343
============================================================ ============== =========
Cash generated from operations 50,861 122,084
============================================================ ============== =========
Interest received 1,959 2,051
Income taxes paid (41,360) (83,042)
============================================================ ============== =========
Net cash flows generated from operating activities 11,460 41,093
============================================================ ============== =========
Investing activities
Proceeds from farm-out - 2,100
Purchase of exploration licences, net of cash acquired - (18,965)
Additions to Exploration and Evaluation assets (175,453) (311,120)
Additions to property, plant and equipment (18,585) (44,788)
Dividends received from joint ventures 5,164 5,843
Funding provided to joint ventures (1,283) (3,941)
Decrease in other financial assets - 331,484
Net cash flows used in investing activities (190,157) (39,387)
============================================================ ============== =========
Financing activities
Financing activities
Interest paid (16,275) (22,521)
Repayment of debt (59,352) (240,521)
Net issue/(repurchase) of shares 2 (56,106)
Cash acquired on acquisition of subsidiary - 48,827
============================================================ ============== =========
Net cash outflows from financing activities (75,625) (270,321)
============================================================ ============== =========
Effect of exchange rates on cash and cash equivalents 177 5,312
============================================================ ============== =========
Decrease in cash and cash equivalents (254,145) (263,303)
============================================================ ============== =========
Cash and cash equivalents at the beginning of the
year 614,569 877,872
============================================================ ============== =========
Cash and cash equivalents at the end of the year 360,424 614,569
============================================================ ============== =========
Notes to the financial statements
1. Corporate information
Ophir Energy plc (the 'Company' and ultimate parent of the
Group) is a public limited company domiciled and incorporated in
England and Wales with company number 05047425. The Company's
registered offices are located at 123 Victoria Street, London SW1E
6DE.
The principal activity of the Group is the development of
offshore and deepwater oil and gas exploration assets. The Company
has an extensive and diverse portfolio of exploration interests
across Africa and Southeast Asia.
The Group's consolidated financial statements for the year ended
31 December 2016 were authorised for issue by the Board of
Directors on 8 March 2017 and the consolidated statement of
financial position was signed on the Board's behalf by Nick Cooper
and Tony Rouse.
2. Basis of preparation
The consolidated financial statements of the Group have been
prepared in accordance with IFRS as issued by the International
Accounting Standards Board and adopted by the European Union (EU),
IFRIC Interpretations and the Companies Act 2006 applicable to
companies reporting under IFRS.
The consolidated financial statements are prepared on a going
concern basis.
The consolidated financial statements have been prepared under
the historical cost convention, modified by the revaluation of
certain derivative instruments measured at fair value. The
consolidated financial statements are presented in US Dollars
rounded to the nearest thousand dollars ($'000) except as otherwise
indicated.
Comparative figures for the period to 31 December 2015 are for
the year ended on that date.
The abbreviated financial statements do not include all the
information and disclosures required in the annual financial
statements, and should be read in conjunction with the consolidated
financial statements in the Ophir Energy plc Annual Report and
Accounts for the year ended 31 December 2016.
3. Segmental analysis
The Group's reportable and geographical segments are Africa,
Asia and Other. The other segment includes the corporate centres in
the UK, Australia and Singapore.
Segment revenues and results
The following is an analysis of the Group's revenue and assets
by reportable segment:
Year ended 31 December 2016
=============================== -------------------------------------------------------------------------------------
Africa Asia Other Total
$'000 $'000 $'000 $'000
=============================== ======================= ================== =================== ===================
Revenue sales of crude oil and
gas - 107,178 - 107,178
Depreciation and amortisation (12) (53,197) (2,093) (55,302)
Impairment of exploration
costs (3,749) (96,391) - (100,140)
Reversal of Impairment of oil
and
gas properties - 84,100 - 84,100
Impairment of investments - - - -
accounted
for using the equity method
Share of profit of
equity-accounted
joint venture - 4,417 - 4,417
=============================== ======================= ================== =================== ===================
Operating profit/(loss) 12,404 (5,864) (35,023) (28,483)
Finance income - 97 1,862 1,959
Finance expense (462) (22,057) (1,035) (23,554)
Other financial gains - - - -
=============================== ======================= ================== =================== ===================
Profit/(loss) before tax 11,942 (27,824) (34,196) (50,078)
Taxation (9,944) (17,384) (40) (27,368)
=============================== ======================= ================== =================== ===================
Profit/(loss) after tax 1,998 (45,208) (34,236) (77,446)
As at 31 December 2016
=============================== =====================================================================================
Total assets and total
liabilities
Total assets 778,065 1,148,674 281,464 2,208,203
(633,126)
Total liabilities (111,207) (517,504) (4,415) cm,358)
Investments accounted for
using the
equity method - 130,736 - 130,736
------------------------------- ----------------------- ------------------ ------------------- -------------------
Year ended 31 December 2016
------------------------------- -------------------------------------------------------------------------------------
Additions to non-current
assets 100,654 24,342 819 125,815
=============================== ======================= ================== =================== ===================
Year ended 31 December 2015
=============================== -------------------------------------------------------------------------------------
Africa Asia Other Total
$'000 $'000 $'000 $'000
=============================== ======================= ================== =================== ===================
Revenue sales of crude oil - 161,090 - 161,090
Depreciation and amortisation - (80,943) - (80,943)
Impairment of exploration
costs (134,640) (14,340) - (148,980)
Impairment of oil and gas
properties - (126,732) - (126,732)
Impairment of investments
accounted
for using the equity method - (42,117) - (42,117)
Share of profit of
equity-accounted
joint venture - 7,219 - 7,219
=============================== ======================= ================== =================== ===================
Operating (loss)/profit (154,270) (169,029) (45,459) (368,758)
Finance income 405 9,170 964 10,539
Finance expense (383) (18,641) (2,177) (21,201)
Other financial gains - 3,372 - 3,372
=============================== ======================= ================== =================== ===================
Loss before tax (154,248) (175,128) (46,672) (376,048)
Taxation 53,596
=============================== ======================= ================== =================== ===================
Loss after tax (322,452)
=============================== ======================= ================== =================== ===================
As at 31 December 2015
=============================== =====================================================================================
Total assets and total
liabilities
Total assets 705,430 1,164,134 554,298 2,423,862
(774,358)
Total liabilities (138,529) (628,340) (7,489) cm,358)
Investments accounted for
using the
equity method - 130,200 - 130,200
------------------------------- ----------------------- ------------------ ------------------- -------------------
Year ended 31 December 2015
------------------------------- -------------------------------------------------------------------------------------
Additions to non-current
assets 37,016 137,666 - 174,682
=============================== ======================= ================== =================== ===================
Non-current operating assets
The non-current operating assets for the UK are $2.7m. (2015:
$4.0 million). The non-UK, non-current operating assets are
$1,010.2 million (2015: $1,507.6 million). Included in the non-UK,
non-current operating assets is Thailand which makes up $421.3
million (2015: $455.7 million).
4. Exploration and evaluation assets
Year ended
Year ended
31 Dec
31 Dec 2016 2015
$'000 $'000
====================================== ============================================================ ===========
Cost
Balance at the beginning of the year 879,914 764,933
Additions1 119,225 131,961
Acquisition of subsidiary - 132,000
Reclassified as assets held for sale (588,770) -
Expenditure written off2 (100,140) (148,980)
Balance at the end of the year 310,229 879,914
====================================== ============================================================ ===========
1 Additions for the year ended 31 December 2016 include
exploration activities in: Equatorial Guinea - Block R ($41.5
million), Côte d'Ivoire - 513 ($19.6 million), Tanzania - Blocks 1
& 4 ($22.7 million), Myanmar - Block AD03 ($8.7 million) and
Malaysia -Block 2A ($7.7 million). Additions for the year ended
2015 included exploration activities in: Myanmar - Block AD03
($28.3 million), Thailand - G4/50 ($19.7 million) and Equatorial
Guinea - Block R ($18.3 million) and five Indonesian PSC licences
from Niko Resources Limited ($25.3million). The licences acquired
from Niko Resources were accounted for as an asset purchase as they
did not meet the definition of a business combination in accordance
with IFRS 3.
2 Expenditure written off in the year was ($100 million). The
most significant write off was in respect of Thailand - G4/50: loss
of $57.6m and Indonesia: loss of $37m. The CGU applied for the
purpose of the impairment assessment is the Blocks. The recoverable
amount of each Block was nil. This was based on management's
estimate of value in use. The trigger for expenditure write off was
management's assessment that no further expenditure on exploration
and evaluation of hydrocarbons in the Block was budgeted or planned
within the current licence terms.
Expenditure written off for the year ended 31 December 2015 was
$149.0 million. The significant write offs included within the
$149.0 million are listed below:
Expenditure write off in respect of Kenya: loss of $62.6 million
- Block L9, in respect of Gabon: loss of $12.5 million - Ntsina
Block, loss of $17.8 million - Mbeli Block and in respect of three
Blocks in the Seychelles a loss of $24.4 million. The CGU applied
for the purpose of the impairment assessment is the Blocks. The
recoverable amount for each Block was nil. This was based on
management's estimate of value in use. The trigger for expenditure
write off was management's assessment that no further expenditure
on exploration and evaluation of hydrocarbons in the Blocks was
budgeted or planned within the current licences terms.
The Group generally estimates value in use using a discounted
cash flow model. Future cash flows are discounted to their present
values using a pre-tax discount rate of 15% (2015: 15%).
Adjustments to cash flows are made to reflect the risks specific to
the CGU.
5. Oil and gas properties
Year ended
Year ended
31 Dec
31 Dec 2016 2015
$'000 $'000
==================== ======================================================================================== ===========
Cost
Balance at the 869,852 -
beginning of the
year
Acquisition of
subsidiary - 827,131
Additions1 5,426 42,721
==================== ======================================================================================== ===========
Balance at the end
of the year 875,278 869,852
==================== ======================================================================================== ===========
Depreciation and
amortisation
Balance at the (207,675) -
beginning of the
year
Charge for the year (52,703) (80,943)
Impairment
reversal/(charge)2 84,100 (126,732)
==================== ======================================================================================== ===========
Balance at the end
of the year (176,278) (207,675)
==================== ======================================================================================== ===========
Net book value
Balance at the 662,177 -
beginning of the
year
==================== ======================================================================================== ===========
Balance at the end
of the year 699,000 662,177
==================== ======================================================================================== ===========
1 Additions in 2016 are stated net of a $19.2 million decommissioning remeasurement.
2 The 2016 Impairment reversal was due to increased reserves
related to the Bualuang oil field in Thailand which has a
recoverable amount of $410.7m based on management's estimate of
value in use. The discount rate used was 15% (pre-tax).
The 2015 impairment charge of $126.7 million related to the
Bualuang oil field in Thailand which had a recoverable amount of
$387.2 million based on management's estimate of value in use. The
discount rate used was 15% (pre-tax).
6. Net debt
As at As at
31 Dec
31 Dec 2016 2015
$'000 $'000
================================ ======================================================== ==========
Amounts due on maturity:
Interest bearing bank loans 93,656 153,008
Bonds payable 106,651 106,651
================================ ======================================================== ==========
Total gross debt 200,307 259,659
Less cash and cash equivalents (360,424) (614,569)
================================ ======================================================== ==========
Total net cash (160,117) (354,910)
================================ ======================================================== ==========
At the balance sheet date, the bank borrowings are calculated to
be repayable as follows:
As at As at
31 Dec
31 Dec 2016 2015
$'000 $'000
On demand or due within one year 9,741 37,059
In the second year 43,831 43,701
In the third to fifth year inclusive 146,735 178,899
After five years - -
====================================== ========================== ========
Total principal payable on maturity 200,307 259,659
====================================== ========================== ========
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR EAADPEEXXEAF
(END) Dow Jones Newswires
March 09, 2017 02:01 ET (07:01 GMT)
Ophir Energy (LSE:OPHR)
Historical Stock Chart
Von Jun 2024 bis Jul 2024
Ophir Energy (LSE:OPHR)
Historical Stock Chart
Von Jul 2023 bis Jul 2024