2013 Annual Report

Transcription

2013 Annual Report

ANNUAL REPORT
2013
1
AT A GLANCE
Reserves & Resources
MMbbl
Balance Sheet
$MM
Income Statement
$ Million
Net Loss
Net Loss per share ($/sh)
2011
16.7
-
2012
58.5
2.10
Capital Expenditures
$ Million
2013 By Activity
2
2013 By Region
2013
185.8
2.04
CONTENTS
4 Chairman’s Message
5 Vision and Values
6 CEO’s Message
8 Our Operations
10 Kurdistan Region of Iraq: Hawler
14 Republic of the Congo: Haute Mer A & B
16 Senegal / Guinea Bissau: AGC
18 Iraq: Wasit Province
20 Nigeria: OML 141
22 Corporate Social Responsibility
24 Kurdistan Children’s Hospital
26 Corporate Governance
28 Board of Directors
30Organisation
32 Reserves & Resources Advisory
33 Management’s Discussion and Analysis of Financial Condition and Results of Operations
49 Consolidated Financial Statements
This Annual Report contains forward-looking information. By its nature, forward-looking information requires us to make assumptions and
is subject to risks and uncertainties. Please refer to the Forward-Looking Information advisory on page 46 for a discussion of such risks and
uncertainties and the material factors and assumptions related to the information set forth in this Annual Report.
3
A MESSAGE FROM
OUR CHAIRMAN
“Following the Sale of Addax Petroleum in 2009, my colleagues and I saw an
opportunity to use our experience, relationships and entrepreneurial instincts
to build a leading independent exploration, development and production
company. We established Oryx Petroleum in late 2010. We instilled in this new
company values, ‘ambition, agility and responsibility’, that we believe are keys to
success and that reflect the company’s heritage as an entity affiliated with AOG
(formerly The Addax and Oryx Group).
We decided to focus our efforts on Africa and the Middle East, regions that we
know well and that are endowed with a plethora of established hydrocarbon
basins.
The team has made excellent progress in fulfilling our ambitious vision. We
acquired a portfolio of license areas throughout 2011 and 2012, some in special
situations reminiscent of how Addax Petroleum acquired its key assets. In
2012, we started drilling, and in 2013, we started to achieve results. Five of the
seven exploration wells we drilled in 2013 have resulted in discoveries and we
are well on our way to achieving our objective of building a balanced full-cycle
exploration, development and production company.
Our key focus is currently our operations in the Kurdistan Region of Iraq. It has
been a pleasure to watch the Kurdistan Region develop. The positive changes
that have occurred since I first visited Kurdistan in 2006 are impressive. It is a
source of great satisfaction for me that Oryx Petroleum and previously Addax
Petroleum have played a role in developing the energy industry in the Kurdistan
Region and in contributing to the well being of its inhabitants. Our commitment
to social responsibility is very real. I am proud of the role of Oryx Petroleum and
of AOG in funding the construction of the Kurdistan Children’s Hospital. The
Hospital will be the premier paediatric facility in Iraq and we expect to see it
open its doors in 2014.
I would like to thank management and the Board for their efforts, as well as
all our shareholders who made our initial public offering in 2013 a success.
2014 will undoubtedly be another year with many achievements, including
the expected start of production and an ambitious appraisal and exploration
program. It is an exciting time to be a shareholder of Oryx Petroleum.”
Jean Claude Gandur
Chairman
4
Our vision is simple but ambitious; to become one of the world’s leading independent exploration, development and
production oil companies.
To achieve this, we are implementing an ambitious exploration and appraisal drilling program across our license
areas, capitalising on the breadth of our team’s experience and our extensive knowledge of the regions in which
we operate.
We combine keen entrepreneurial instinct with a rigorous approach to risk and responsibility.
You might say that we are courageous with opportunity, conservative with risk.
Our corporate values can be distilled into the following three drivers:
AMBITIOUS
►► quick to seize new opportunities
►► inquisitive, curious and responsive
►► self-motivated, tenacious and intuitive
AGILE
►► open-minded, flexible and innovative
►► dedicated to working with local cultures for shared success
►► versatile and resourceful in exploring fresh solutions
RESPONSIBLE
►► honest, fair, open and tolerant
►► a culture that encourages personal success
►► committed to maintaining the highest standards of civility, decency, dignity and justice
5
A MESSAGE FROM
OUR CEO
“2013 was a tremendous year for Oryx Petroleum. In the Kurdistan Region of Iraq
our drilling activities resulted in discoveries at all four structures in the Hawler
license area, and we made our first discovery in West Africa with the Elephant
discovery in Congo (Brazzaville). Consequently, Oryx Petroleum has transformed
from a pure exploration company to a company with a sizeable reserves and
contingent resource base and further exploration upside.
In the Kurdistan Region of Iraq we have aggressively progressed appraisal and
development of our Demir Dagh discovery with first production expected shortly.
Appraisal and development drilling will continue throughout 2014 aiming to
convert contingent resources into reserves, and reserves into production. In
2013, the signing of the Energy Framework Agreement between the Kurdistan
Region of Iraq and Turkey, the completion of the Khurmala-Faysh Khabur
pipeline, and the continuation of serious negotiations between the Erbil and
Baghdad governments, all underscore substantive progress in moving towards
a resolution of the export situation in Kurdistan.
In West Africa, our focus for 2014 will be on growing our reserve base through
further exploration, with high impact exploration wells planned in both the AGC
and Congo (Brazzaville).
Demir Dagh Discovery
Hawler
FEBRUARY
2013
6
Initial Public Offering
MAY
2013
Elephant Discovery
Congo (Brazzaville)
SEPTEMBER
2013
Ain Al Safra Discovery
Hawler
SEPTEMBER
2013
In 2013, we also successfully completed an initial public offering to help fund our activities through to mid-2014 and we
will seek to further strengthen our capital structure as the year progresses.
We continue to evaluate new venture opportunities, particularly add-on acquisitions in our core focus areas, but our
primary focus is on maximising the value of our existing properties.
As our organisation and operations have grown we have maintained our focus on safety, environmental stewardship and
social responsibility. Progress on construction of the Kurdistan Children’s Hospital, which we have helped organise and
fund, progressed in 2013 and is expected to open in 2014. Our funding of this project was recognised as the Outstanding
Community Initiative of 2013 by the Kurdistan Regional Government. Other important community activities included
providing medical support to local communities within our Hawler license area and the funding of school and infrastructure
construction upgrades. We are as proud of our achievements in these areas as we are of our operational achievements.
As always I would like to thank our management and staff, who in combination with the support of our Board, business
partners and shareholders have made our progress in 2013 possible. 2014 promises to be another transformational year
for Oryx Petroleum.”
Michael Ebsary
CEO
Tie-In Points to
Khurmala-Faysh Khabur
Pipeline completed
Hawler
NOVEMBER
2013
Zey Gawra Discovery
Hawler
DECEMBER
2013
Declaration of
Commercial Discovery
for Demir Dagh-2
Hawler
FEBRUARY
2014
Banan Discovery
Hawler
MARCH
2014
7
OUR OPERATIONS
We are rapidly building a diverse portfolio of petroleum license
areas, strategically focused in Africa and the Middle East.
Oryx Petroleum is an international oil
exploration company focused in Africa
and the Middle East. Oryx Petroleum was
founded in 2010 by The Addax & Oryx Group
(AOG) and key members of the former senior
management team of Addax Petroleum,
a company founded in 1994 by AOG and
acquired in 2009 by Sinopec Corporation.
Oryx Petroleum has interests in six license
areas within its strategic focus areas of Africa
and the Middle East, namely in the Kurdistan
Region and the Wasit governorate (province)
of Iraq, Nigeria, the AGC administrative area
offshore Senegal and Guinea Bissau, and
Congo (Brazzaville). Oryx Petroleum is the
operator or technical partner in four of the six
license areas.
As at December 31, 2013, Oryx Petroleum had
gross (working interest) proved plus probable
oil reserves of 213 MMbbl, best estimate gross
(working interest) contingent oil resources of
223 MMbbl and best estimate unrisked gross
(working interest) prospective oil resources
of 1,167 MMbbl (risked: 209 MMbbl). As at
December 31, 2013, the after-tax net present
value of the future net revenue for the
Corporation’s gross (working interest) proved
plus probable oil reserves is $1,287 million
and best estimate gross (working interest)
contingent oil resources is $697 million,
using forecast prices and costs and a 10%
discount rate. The Corporation’s oil reserves
and resources and associated net present
values as at December 31, 2013 are based on
evaluations made by NSAI, an independent oil
and gas consulting firm providing reserve and
resource reports to the worldwide petroleum
industry. See Reserves & Resources Advisory
on page 32.
Location
Licence
Area (km2)
Water Depth
(metres)
W.I. (%)
Operator /
Technical Partner
Iraq
Kurdistan Region
Hawler
788
Onshore
65.00
ORYX
PETROLEUM
Wasit
Province
Wasit
3,500
Onshore
40.00
ORYX
PETROLEUM
Nigeria
OML141
1,295
0-30
38.67
ORYX
PETROLEUM
AGC (Senegal /
Guinea Bissau
AGC Shallow
1,700
0-100
80.00
ORYX
PETROLEUM
Congo
(Brazzaville)
Haute Mer A
488
350-1,100
20.00
CNOOC Ltd
Haute Mer B
402
150-1,050
30.00
TOTAL
Total
8,173
Reserves and Resources (Working Interest)
Location
License
Oil Reserves(1)
Iraq Kurdistan Region
Proved plus Probable (Working Interest)
(MMbbl)
Hawler
($ million)(4)
213
1,287
Gross Oil (Working Interest)
Contingent Oil Resources(2)
Congo (Brazzaville)(6)
(MMbbl)
Hawler
Haute Mer A
Total Contingent Oil Resources(7)
($ million)(4)
217
697
6
-
223
697
Gross Oil (Working Interest)
Unrisked
Prospective Oil Resources(3)
Wasit Province
Nigeria
Risked
(MMbbl)
Hawler
238
50
Wasit
404
77
67
10
38
OML141
AGC
AGC Shallow
267
Congo (Brazzaville)
Haute Mer A
31
4
160
31
1,167
209
Haute Mer B(5)
Total Prospective Resources(7)
1. The oil reserves data is based upon evaluations by NSAI, with an effective date at December 31, 2013.
2. The contingent oil resources data is based upon evaluations by NSAI, and the classification of such resources as “contingent oil resources” by NSAI,
with an effective date at December 31, 2013. The figures shown are NSAI’s “best estimate”, using deterministic methods. Once all contingencies have
been successfully addressed, the probability that the quantities of contingent oil resources actually recovered will equal or exceed the estimated
amounts is 50% for the best estimate. Contingent oil resources estimates are volumetric estimates prior to economic calculations.
3. The prospective oil resources data is based upon evaluations by NSAI, and the classification of such resources as “prospective oil resources” by NSAI,
with an effective date at December 31, 2013. The figures shown are NSAI’s “best estimate”, using a combination of deterministic and probabilistic
methods and are dependent on a petroleum discovery being made. If discovery is made and development is undertaken, the probability that the
recoverable volumes will equal or exceed the unrisked and risked estimated amounts is 50% for the best estimate. Prospective oil resources
estimates are volumetric estimates prior to economic calculations.
4. After-tax net present value of future net revenue associated therewith using forecast prices and costs and a 10% discount rate. Gross contingent
resources estimates used to calculate future net revenue are estimated based on economically recoverable volumes within the development/
exploitation period specified in the PSC, REC or fiscal regime applicable to each license area.
5. Oryx Petroleum’s interest in Haute Mer B is subject to final approval from the government of Congo (Brazzaville). The National Assembly announced
on July 25, 2013 that it had approved the award of the Haute Mer B license area. The PSC in respect of the Haute Mer B license area has since been
finalised and initialled by all members of the contractor group who are now awaiting formal approval of the PSC by the National Assembly.
6. An economic evaluation has not been performed on the contingent oil resources in the Haute Mer A license area since the field development plan is
still under consideration.
7. Individual numbers provided may not add to total due to rounding.
8
Our business strategy has been designed to ensure that
we capitalise on our strengths and achieve our vision to
become one of the world’s leading independent exploration,
development and production oil companies.
IRAQ
SENEGAL /
GUINEA BISSAU
NIGERIA
CONGO (BRAZZAVILLE)
9
KURDISTAN REGION OF
IRAQ: HAWLER
Oryx Petroleum has a 65% participating and working interest in
the Hawler license area. Oryx Petroleum has made discoveries
on all four identified structures of the Hawler license area:
Demir Dagh, Banan, Ain Al Safra and Zey Gawra. First
production is expected in the second quarter of 2014.
Oryx Petroleum acquired its 65% working and
participating interest in the Hawler license
area in August 2011. The Korean National Oil
Corporation has a 15% participating interest
and the Kurdistan Regional Government
(KRG) has a 20% participating interest. Oryx
Petroleum is the operator of the Hawler
license area.
The Hawler license area is characterised
by large thrust-bound anticlines. These
structures produce both the potential for
large trapped hydrocarbon volumes as well
as fracturing within the reservoir to aid
well productivity. Prior to drilling by Oryx
Petroleum, there had been two previous wells
drilled in the license area by the Iraqi national
oil companies: Demir Dagh-1 in 1960, and
Zab-1 (on the currently named Zey Gawra
discovery) in 1990 and 1991. Both previous
wells encountered oil shows and flowed oil
under limited test conditions.
10
We identified four structures based on
the previous wells drilled and 2D seismic
data acquired by the previous operator:
Demir Dagh, Zey Gawra, Ain Al Safra and
Banan. Drilling commenced in mid-2012.
Oryx Petroleum has made discoveries on all
four identified structures. A declaration of
commercial discovery was submitted to the
KRG on February 25, 2014 in respect of the
Demir-Dagh 2 discovery. Contemporaneously
with this submission, it was agreed with the
KRG that Oryx Petroleum would relinquish
approximately 850 km2 of the license area,
representing that portion of the license area
that Oryx Petroleum has determined is not
required in connection with the appraisal
and/or development of the Demir Dagh,
Banan, Ain Al Safra and Zey Gawra fields. Any
decision regarding development of the Banan,
Ain Al Safra and Zey Gawra fields is subject
to further appraisal activity, which must
be concluded by June 30, 2015. Following
such appraisal, these areas must either be
developed or relinquished.
The Demir Dagh Discovery and Development
The Demir Dagh discovery was announced
in February 2013 after the conclusion of
a successful test program that flowed oil
from Cretaceous and Jurassic reservoirs.
The discovery is estimated to contain
258 MMbbl of gross (100%) proved plus
probable oil reserves, as well as 271 MMbbl
of best estimate gross (100%) contingent oil
resources and 50 MMbbl of best estimate
unrisked gross (100%) prospective oil
resources (risked: 10 MMbbl).
Approximately 92% of the estimated
reserves at Demir Dagh consist of 23°API oil
in the Shiranish, Kometan and Qamchuqa
formations in the Upper Cretaceous. Testing
and analysis confirmed matrix porosity. The
oil in this reservoir is also very low in gas
and hydrogen sulphide content and has
good viscosity making it easy to process.
The remaining 8% of the estimated reserves
at Demir Dagh consist of light oil (37°API to
42°API) from the Mus and Adaiyah formations
A world class asset: Four discoveries with
first production expected in 2014
in the Lower Jurassic, with reservoir and
liquid properties more similar to other
discoveries in Kurdistan. The estimated
contingent oil resources at Demir Dagh are
comprised of approximately 84% of 23°API
oil in the Shiranish, Kometan and Qamchuqa
formations in the Upper Cretaceous, with
the balance consisting of light oil (29°API to
32°API) from the Naokelekan and Sargelu
formations in the Middle Jurassic.
The estimated prospective oil resources
at Demir Dagh consist entirely of light oil
(40+°API) in the Butmah formation in the
Lower Jurassic and the Kurra Chine formation
in the Triassic.
We are pursuing an aggressive appraisal
and development plan for Demir Dagh with
three appraisal wells and five development
wells planned for 2014. We have recompleted
the Demir Dagh-2 discovery well as a
producer and have already drilled, tested
and completed the Demir Dagh-4 appraisal
well as a producer. We are progressing on the
installation of an Early Production Facility
with a capacity of 40,000 bbl/d. We expect
first production in the second quarter of 2014
with production increasing to the full capacity
of the Early Production Facility sometime
in 2015. We are planning for a Permanent
Production Facility with a 100,000 bbl/d of
initial capacity that we are targeting to have
online in 2016.
We are expecting to sell some of our first
production into the domestic market and are
building a Truck Loading Facility. Importantly,
we have completed construction of tie-ins to
the recently built Khurmala-Faysh Khabur
pipeline which will accommodate production
from all our discoveries once pipeline exports
from Kurdistan commence.
As we progress our appraisal and development
plans we could potentially add to our reserve
volumes.
11
KURDISTAN REGION OF
IRAQ: HAWLER
The Zey Gawra Discovery
We announced the Zey Gawra discovery
in December 2013 after completion of a
successful testing program that flowed
light oil from the Shiranish, Kometan and
Qamchuqa formations in the Cretaceous. The
discovery is more than three times our predrill estimate in terms of volumes and the
crude quality was much better than expected.
The structure is estimated to contain 71
MMbbl of best estimate gross (100%) proved
plus probable oil reserves and 32 MMbbl
of best estimate unrisked gross (100%)
prospective oil resources (risked: 12 MMbbl).
The estimated reserves at Zey Gawra consist
entirely of light oil (35°API) in the Shiranish,
Kometan and Qamchuqa formations in the
Upper Cretaceous. The estimated prospective
oil resources at Zey Gawra consist of heavy
oil (less than 23°API) in the Pila Spi formation
in the Tertiary, light oil in the Alan, Mus and
Adaiyah formations in the Middle Jurassic,
light oil in the Butmah formation in the Lower
Jurassic, and light oil in the Kurra Chine
formation in the Triassic.
We plan to drill an appraisal well at Zey
Gawra as early as mid-2014 and the field will
be developed with Demir Dagh and Banan if
appraisal is successful.
12
The Ain Al Safra Discovery
We announced the Ain Al Safra discovery
in October 2013 after completing a testing
program that flowed oil from the Jurassic. The
structure is estimated to contain 22 MMbbl
of best estimate gross (100%) contingent oil
resources and 49 MMbbl of best estimate
resources (risked: 10 MMbbl). The estimated
contingent oil resources at Ain Al Safra
consist entirely of heavy oil (18°API) in the
Alan, Mus and Adaiyah formations in the
Middle Jurassic. The estimated prospective oil
resources at Ain Al Safra consist of heavy oil
in the Butmah formation in the Lower Jurassic
and light oil in the Kurra Chine formation in the
Triassic. We believe there is large potential at
Ain Al Safra and we spudded an appraisal well
in March 2014 to further evaluate the Jurassic
formations and explore the potential in the
Triassic that the first exploration well was not
able to assess.
The Banan Discovery
We announced the Banan discovery in
early March 2014 after a successful testing
program that saw oil flowed from Cretaceous
and Jurassic formations. Prior to the test
results the structure was estimated to
contain 40 MMbbl of best estimate gross
(100%) contingent oil resources and 235
MMbbl of best estimate unrisked gross
(100%) prospective oil resources (risked:
46 MMbbl). The estimated contingent oil
resources at Banan consist entirely of light
oil in the Shiranish, Kometan and Qamchuqa
formations in the Cretaceous. The estimated
prospective oil resources at Banan consist
of light oil in the Pila Spi formation in the
Tertiary, light oil in the Alan, Mus and Adaiyah
formations in the Middle Jurassic, light oil in
the Butmah formation in the Lower Jurassic,
and light oil in the Kurra Chine formation in
the Triassic.
This first exploration well was drilled downdip of the crest of the structure as planning
for drilling commenced before an extension of
the Hawler license boundary was agreed with
the KRG. The down-dip location impacted
Oryx Petroleum’s ability to select the most
optimal interval to test in the Cretaceous
formations and impacted the volume ascribed
to best estimate contingent resources. The
large volume ascribed to the high estimate
contingent resources reflects the potential
of Banan. We plan to drill an appraisal well at
Banan in 2014 to better assess this potential.
If appraisal is successful Banan would be
developed together with the Demir Dagh and
Zey Gawra discoveries.
2014 Plans
As at December 31, 2013, Oryx Petroleum’s
budgeted capital expenditures for the Hawler
license area are $366.6 million for 2014. The
2014 budgeted capital expenditures program
includes:
• the recent successfully completed testing
program at BAN-1;
• three appraisal wells and five development
wells at Demir Dagh;
• facilities expenditures related to a 40,000
bbl/d Early Production Facility and initial
expenditures related to the Permanent
Production Facility;
• drilling of appraisal wells at each of Banan,
Ain Al Safra and Zey Gawra;
• the acquisition of 430 km2 3D seismic data
over the Demir Dagh and Banan structures.
13
REPUBLIC OF THE CONGO:
HAUTE MER A&B
Oryx Petroleum’s interests in Congo (Brazzaville) include a 20%
participating and working interest in offshore license area
Haute Mer A and a 30% participating and working interest in
offshore license area Haute Mer B. Haute Mer A and Haute
Mer B were created from a relinquished portion of the Haute
Haute Mer A
In September 2009, CNOOC was awarded an
85% participating and working interest in,
and operatorship of, the Haute Mer A license
area. In November 2012, Oryx Petroleum
acquired a 20% participating and working
interest in the license area from CNOOC Ltd.
CPC Corporation, a Taiwanese company also
aquired a 20% working and participating
interest from CNOOC Ltd. SNPC holds the
remaining 15% participating and working
interest. CNOOC is the operator of the HMA
license area.
The Haute Mer A license area is located 80
kilometres offshore Congo (Brazzaville) and
covers an area of 488 km2 with water depths
ranging from 350 metres to 1,100 metres.
Two exploration wells were drilled in 2013
targeting the Elephant and Horse prospects
with the well targeting Elephant resulting in
a discovery.
14
Elephant Discovery
We announced the Elephant discovery in
September 2013 and a testing program in
early 2014 confirmed the discovery. The
Elephant discovery lies in the middle of the
license area and was previously targeted by
the Libonolo Marine-1 (LIBM-1) well drilled in
1997 by Elf (currently Total), and a discovery
made over the N5 interval of the Tertiary
Miocene turbidites deposits.
In August 2013, the exploration well targeting
the Elephant prospect (E-1) reached a total
depth of 2,497 metres using the Jasper
Explorer Drillship in 550 metres of water
80 kilometres offshore Congo (Brazzaville).
Primary targets for the E-1 well were the N5
and the N3 turbiditic type reservoir intervals
in the Miocene Tertiary.
The E-1 well was drilled approximately
4.5 kilometres south-east of the LIBM-1
well. Based on the data from the E-1 well,
30 metres of gross interval (20.3 metres
net) of crude oil and 102 metres of gross
interval (58.8 metres net) of natural gas
were encountered in the N5 interval and 16
metres of gross interval (9.2 metres net) of
crude oil were encountered in the N3 interval.
Reservoir quality, crude quality and viscosity
were better than pre-drill expectations while
the areal extent of the structure was smaller
than expected. The Elephant discovery was
successfully tested in early 2014 with the oil
bearing intervals in the N3 flowing 24° API oil
and the N5 flowing 18° API oil. Pressure build
up analysis confirmed the excellent porosity
and permeability of the respective sand
channel complexes.
As at December 31, 2013, prior to the
test results, the Elephant discovery was
estimated to contain best estimate gross
(100%) contingent oil resources of 31 MMbbl.
The prospects and leads on the license
area are estimated to contain best estimate
Exploration for oil adjacent to large
producing fields
Mer license area operated by Total. The Haute Mer license area
has yielded a number of discoveries including N’Kossa (1984),
Moho-Bilondo (1995) and Moho Nord (2007). The license areas
are also in close proximity to discoveries in adjacent license
areas in Angola.
resources of 153 MMbbl (risked: 20 MMbbl).
2014 Plans
Our budgeted capital expenditures for the
Haute Mer A license area are $31.8 million for
2014 and include the recently successfully
completed testing of the E-1 well discovery
and an exploration well. We are working with
our partners to determine precise timing and
location of future exploration drilling.
Haute Mer B
In April 2012, Oryx Petroleum was awarded
a 30% participating and working interest
in the Haute Mer B license area. We are
waiting on final approval of the production
sharing contract by the National Assembly
of Congo (Brazzaville). Participating interests
in the license area are: Total (34.62%), Oryx
Petroleum (30%), Chevron (20.38%) and SNPC
(15%). Total is the operator of the Haute Mer
B license area.
The Haute Mer B license area is located 58
kilometres offshore Congo (Brazzaville) and
covers an area of 402 km2 with water depths
ranging from 150 metres to 1,050 metres. A
large amount of 2D and 3D seismic data has
been acquired during successive acquisition
campaigns covering the Haute Mer B license
area, but no well has yet been drilled in the
license area.
The principal targets in the Haute Mer B
license area are Cretaceous carbonate
reservoirs similar to those producing light
oil in neighbouring fields, with additional
targets in shallower Tertiary deposits. Three
prospects in the Cretaceous (Loubossi,
Kaki Main and Kaki East), four leads in the
Cretaceous and four leads in the Tertiary have
been identified in the Haute Mer B license
area. The identified prospects and leads
collectively are estimated to have total best
estimate unrisked gross (working interest)
prospective oil resources of 160 MMbbl
(risked: 31 MMbbl). The three prospects in the
Cretaceous are estimated to have total best
estimate unrisked gross (working interest)
prospective oil resources of 93 MMbbl (risked:
19 MMbbl). Oil quality is expected to be light
in the Cretaceous and heavy in the Tertiary.
2014 Plans
Haute Mer B license area are $39.1 million
for 2014. An exploration well is planned to be
spudded in the second half of 2014.
15
SENEGAL / GUINEA
BISSAU: AGC
An 85% participating interest (80% working interest if the AGC
exercises the AGC Back-In Right) in the AGC Shallow license
area, one of the two license areas in the AGC region offshore
Senegal and Guinea Bissau. The license area is 1,700 km2 in size
with water depths up to 100 metres.
In November 2011, Oryx Petroleum was
awarded an 85% participating interest in the
AGC Shallow license area, with the Agence de
Gestion et de Coopération entre le Senegal et
la Guinea-Bissau (AGC) holding a 15% carried
interest and an option to acquire an additional
5% non-carried interest upon the issuance of
an exploitation permit for the license area.
The AGC Shallow license area, one of the
two license areas in the AGC region offshore
Senegal and Guinea Bissau, is 1,700 km2 in
size with water depths up to 100 metres.
Exploration activities in the region were
commenced by Total in 1958. Seismic data
and geophysical reconnaissance surveys
revealed the presence of several prominent
shallow salt domes. The first exploration
drilling in the areas adjacent to the north
of the AGC commenced in 1966 with four
wells drilled on salt domes. The first drilling
in what is now the AGC began in 1967 with
three exploration wells on Dome Flore. These
16
wells all encountered heavy oil and partially
delineated the shallow water salt diapir. An
additional well found light oil in the Albian
sands (Lower Cretaceous).
We have identified two play types in three
structures for potential light oil exploration:
salt diapir related structural traps and
seismic amplitude prospects.
After the initial shallow discoveries of heavy
(Tertiary) and light (Cretaceous) oil on Dome
Flore and Dome Géa, the license area was
held for the last three decades by a series of
smaller independent exploration companies
whose activities were largely confined to
acquiring 3D seismic data. Only two other
wells have been drilled in the last 30 years with
development of heavy oil being the primary
focus. In 1996 an independent exploration
company drilled a shallow well that had heavy
oil shows. The previous operator of the license
area acquired 385 km2 of 3D seismic data in
2003.
Salt Diapir Related Prospects
Oil is thought to be trapped in very shallow
reservoirs in the Albian associated with salt
diapirs where the heavy nature of the crude
is thought to be because of degradation.
Three structures have been identified: Dome
Flore, Dome Gea and Dome Iris. New seismic
data technology, such as Pre-stack Depth
Migration, developed in recent years has
been used to image deeper reservoirs where
degradation is less likely to have occurred, but
also where the geometries of the salt need to
be properly imaged and defined. In 2012 we
acquired 840 km2 of 3D seismic data over an
area including the three structures and have
reprocessed and studied such data in 2013.
Significant light oil potential with
hydrocarbon system established by
discovered heavy oil
Seismic Amplitude Prospects
Based on the seismic data acquired in
2012, we have also identified some seismic
amplitude prospects in the Maastrichtian in
two of the identified structures: Dome Iris and
Dome Gea.
2014 Plans
Our 2014 budgeted capital expenditures
for the AGC Shallow license area are $44.9
million for 2014 which is primarily related to
the drilling of an exploration well. We have
recently commenced a tendering process for
the planned exploration well.
The light oil prospects and leads are
estimated to contain a total of 267 MMbbl
of best estimate unrisked gross (working
interest)
prospective
oil
resources
(risked: 38 MMbbl).
17
IRAQ: WASIT PROVINCE
A 50% participating interest (40% working interest assuming
the Back-In Rights are exercised) in the Wasit license area with
rights for oil exploration operated by Oryx Petroleum.
In two transactions in December 2011 and
October 2013, Oryx Petroleum acquired a
66.67% shareholding in KPA Western Desert
Energy Limited (“KPA”) that has an indirect
75% participating interest in contracts with
the government of the Wasit Province of Iraq
(the “WPG Contracts”), namely an Asphalt
Exploration Contract, a Seismic Option
Agreement and a Risk Exploration Contract
(“REC”). Oryx Petroleum is the contract
operator with regard to all of the WPG
Contracts. Assuming that the Wasit Provincial
Government (“WPG”) exercises certain BackIn Rights then, as a result of its shareholding
in KPA, Oryx Petroleum will have a 40%
working interest in the WPG Contracts.
The Seismic Option Agreement grants nonexclusive rights to acquire 2D seismic data on
behalf of the WPG over any part of the Wasit
province up to a total of 7,000 kilometres. The
initial term of the Seismic Option Agreement
is five years, expiring in September 2016, with
an option to extend for an additional five years.
18
Pursuant to the Seismic Option Agreement,
KPA can nominate non-contiguous areas
totalling up to 3,500 km2 to be “Contract
Areas” governed by the terms of the REC.
The Asphalt Exploration Contract provides
KPA exclusive rights to mine heavy oil,
asphalts tar and bitumen (less than 25°API)
throughout the Wasit province.
The Wasit REC provides KPA with the
right to conduct all exploration, gas
marketing, development, production and
decommissioning operations relating to
petroleum in nominated Contract Areas.
At present, no Contract Areas have been
nominated by KPA. Each nominated Contract
Area would be deemed to be a new REC, and
the WPG is granted the WPG Back-In Right
to acquire up to a 20% participating interest
in each Contract Area so nominated by KPA.
Existing producing regions within the Wasit
province are excluded from the Wasit REC.
The overall geological profile of the Wasit
province appears to be very favourable for
hydrocarbon exploration, with a proven
active petroleum system (Jurassic and Early
Cretaceous source rocks) charging many
large discoveries in the province (Ahdab,
Dufriyah and Badrah fields) and in the
surrounding area, including accumulations
such as the super-giant East Baghdad field.
Geologically, the Wasit province spans
three distinct domains, namely the Arabian
Shelf, the Mesopotamian Foredeep, and the
Zagros Fold Belt, providing an attractive
diversity of charge and trap mechanisms and
potential reservoirs.
Unique early stage oil opportunity in
under-explored and under-developed
province
China National Petroleum Corporation
(Ahdab field), OAO Gazprom (Badrah field)
and Pakistan Petroleum Limited are already
present in the Wasit province under contracts
with the Iraqi Federal Government.
The Wasit province is under-explored, with
only five exploration and appraisal wells
drilled to date and limited 2D seismic data
coverage. All five exploration and appraisal
wells drilled in the Wasit province to date
have been successful: two wells on the
Badrah field, two wells on the Ahdab field and
one well on the Dufriyah field.
The Iraq National Oil Company (INOC)
acquired and interpreted 2D seismic data in
the 1990s, from which it identified a number
of leads in the province. Oryx Petroleum
reviewed a small selection of these seismic
data lines. Fifteen leads were identified in the
Wasit province, from which Oryx Petroleum
has chosen to develop a sub-set of five leads
into prospects. The five leads to be developed
into prospects are Sa’d, Wasit West, Wasit
East, Wasit Central, and Dufriyah North.
Collectively, the five leads are estimated to
have best estimate unrisked gross (working
interest) prospective oil resources of 404
MMbbl (risked: 77 MMbbl).
2014 Plans
Efforts to secure approvals and preparations
for planned seismic data acquisition
continued in 2013. Our budgeted capital
expenditures for the Wasit province for
2014 are $27 million and include a seismic
data acquisition campaign on the Wasit
license area.
19
NIGERIA: OML141
A 38.67% participating and working interest in OML 141,
a shallow water offshore exploration area operated by an
indigenous company, with Oryx Petroleum as the technical
partner.
In September 2011, Oryx Petroleum acquired
a 38.67% participating and working interest
in the OML 141 license area through a
farm-in transaction. OML 141 is a shallow
water offshore exploration area operated
by an indigenous company, Emerald Energy
Resources Limited, with Oryx Petroleum
acting as the technical partner.
The OML 141 license area is located partly in
the swamp and partly offshore in the central
part of the Niger Delta. The modern-day
environment consists of coastal mangrove
swamp, brackish water within the transition
zone, and delta platform to pro-delta slope
environments in the offshore marine.
20
There has been limited exploration activity
in the license area in recent years with only
three wells drilled since the 1960s and
much of the license area does not have
3D seismic coverage.
The Dila-1 exploration well was drilled to a
depth of 12,000 feet (3,658 metres) in 2013.
Based on logging information 8 feet net pay
of natural gas and 14 feet net pay of oil were
encountered in one of the targeted sands. We
determined that the oil discovered was not
in sufficient quantities to be commercially
developed on a stand-alone basis and
deemed the well unsuccessful.
Since the drilling of the Dila-1 well we have remapped the prospects in the portions of the
license area covered by 3D seismic data. Ten
of the identified prospects are estimated to
contain best estimate unrisked gross (working
interest) prospective oil resources of 67 MMbbl
(risked: 10 MMbbl). We have also identified a
number of stratigraphic plays in the portion of
the license area covered only by 2D seismic
data and plan to acquire 3D seismic data over
such area.
Large under-explored license area within
the prolific Niger Delta
2014 Plans
We continue to analyse existing 3D seismic
data and the results of the Dila-1 well and
plan to acquire additional 3D seismic data
in 2014 in order to determine the course of
future activity in the OML 141 license area.
OML 141 license area are $19.1 million for
2014 which is comprised primarily of the cost
to acquire additional 3D seismic data.
21
CORPORATE SOCIAL
RESPONSIBILITY
Social responsibility is at the forefront of Oryx Petroleum’s
thinking and our everyday business practices and is a pillar
to our corporate philosophy of being “Ambitious, Agile and
Responsible”.
Our Principles
We believe that acting in a responsible
manner and working closely together with
our host communities not only helps us meet
our social commitments but also allows us to
meet and exceed our business goals.
Oryx Petroleum values the principles of
accountability, honesty and integrity in all
aspects of our business.
We are committed to achieving the highest
principles of corporate citizenship by
safeguarding the environment, protecting the
health and safety of our workforce and the
communities in which we operate, creating
and delivering on opportunities to enhance
benefits to society, and respecting all
human rights.
Fulfilling our social responsibilities is integral
to creating value for our shareholders,
employees, partners, host governments and
host communities.
22
In conducting our business, we are guided by
the following principles:
• We support and adhere to the principles of
the Universal Declaration of Human Rights;
• We carry out our business based on the
highest principles of business integrity.
Our Code of Conduct expresses this
commitment, and should be considered
as a guide for everyone who works for, or
on behalf of, Oryx Petroleum. Our Code of
Conduct is embedded into all contracts and
we expect everyone to adhere its principles;
• We expect our suppliers and contractors
to abide by our Code of Conduct and AntiBribery and Anti-Corruption Policy.
• We are committed to operating our
business in a manner consistent with
the laws of the jurisdictions in which
we operate;
• We are committed to carrying out our
business fairly, openly and honestly and
condemn corruption in all its forms. Our
Anti-Bribery and Anti-Corruption Policy
are considered as a guide for everyone who
works for, or on behalf of, Oryx Petroleum;
• We do not allow employment of under aged
children in our workforce in any of our
operations around the globe;
• We
provide
equal
employment
opportunities to all workers, regardless of
race, colour, sex, age, sexual orientation,
creed, national origin or disability; and
• We do not tolerate any form of
workplace harassment, including sexual
harassment of an employee, contractor or
employment candidate.
Local Communities
We believe in proactively engaging the local
communities, host governments and civil
society to secure a social license to operate.
We believe that early, proactive stakeholder
consultation is beneficial to both the
company and the community and makes for
high-impact, sustainable outcomes.
We believe in working in partnership with
the local communities, host government and
civil societies to develop long lasting positive
impacts on social development, particularly
in the areas of education and health.
We carry out assessments of social, economic
and environmental potential positive and
negative impacts of operations on the
communities before establishing any major
investment, new projects and potential
acquisitions. Once these impacts are
identified, we identify mitigation measures
for negative impacts and look for methods for
enhancing the socio-economic opportunities
that flow from positive impacts.
We aim to manage social, environmental
and security risks to avoid or minimise risks
to stakeholders and to Oryx Petroleum’s
operations.
We recognise and respect local cultures and
develop effective strategies and policies to
support the rights of the local communities.
We respect and support human rights in all
areas that we conduct operations.
We aim to mitigate any negative safety,
health and environmental effect on the
host communities as a consequence
of our operations.
2013 Activities
Our commitment to social responsibility is
backed up with tangible actions.
Our team of medical professionals has
conducted visits to over 60 communities in
the Hawler license area and treated over
3,500 patients most of whom are women
and children.
In the Hawler license area we have invested in
school and village infrastructure construction
and upgrades, provided employment to locals
and hosted village social events.
Our most ambitious project is the funding
of the construction of the Kurdistan
Children’s Hospital in Erbil.
23
KURDISTAN CHILDREN’S
HOSPITAL
The Kurdistan Children’s Hospital is an ambitious and farsighted new healthcare facility located on the outskirts of Erbil,
in the Kurdistan Region of Iraq. Oryx Petroleum is playing a
critical role in its construction and development.
The Kurdistan Children’s Hospital is an
ambitious and far-sighted new healthcare
facility currently under construction on the
outskirts of Erbil, in the Kurdistan Region
of Iraq. In 2013 Oryx Petroleum provided the
most of its $40 million commitment to fund
the construction of the Hospital.
The Kurdistan Children’s Hospital is owned
and operated by the Kurdistan Children’s
Hospital Foundation, a United Kingdom
registered charitable company, supported by
private philanthropy. The Foundation’s charter
provides for the not-for-profit management
and operation of the hospital and its facilities.
Upon completion, the Kurdistan Children’s
Hospital will provide a new paediatric
healthcare facility that has no peer in Iraq.
This is essential, as there are a large number
of children and mothers that are currently
unable to access suitable medical treatment
or surgery inside Iraq. The only option for
many children and mothers to date has
been to travel to the US, Europe or other
neighbouring countries in order to acquire
the proper medical assistance that is not
currently available in Iraq.
24
The Proposed Facilities
The Kurdistan Children’s Hospital complex
will include a 120-bed main hospital building,
2 support buildings, a warehouse, an oxygen
plant, a generator facility and a residential
area for medical staff.
The main hospital building will include:
• 80 single-bed rooms
• 20 multi-use rooms
• 5 operating rooms
• An emergency department
• Various specialty clinics
• A dedicated dental suite
• A paediatric and neonatal ICU (intensive
care unit)
• A pharmacy and dispensary
• Various medical laboratories
• A state-of-the-art imaging department (including MRI, CT scanning and
ultrasounds)
• Education and training facilities
• Administration offices
• Catering facilities
• Suitable retail facilities
• Staff accommodation and recreational
facilities
• Dedicated public and staff car parks
• Outdoor facilities for patients and their
families
Status
Construction of the Kurdistan Children’s
Hospital commenced in Late 2010 and a soft
opening is targeted for mid-2014.
In addition to funding we have provided
legal advice, helped facilitate a third party
engineering audit, assisted with recruiting
senior management and we provide ongoing
advice and governance through membership
on the Foundation`s Board of Directors.
25
WE ARE COMMITTED TO
STRONG CORPORATE
GOVERNANCE
Our Board is comprised of eight directors, six of whom are independent. Our independent directors
bring a wealth of experience in operations, finance, law and accounting. There is clear separation
of the roles of the Chairman and the Chief Executive Officer to ensure an appropriate balance of
responsibility and accountability. The Board has also established detailed charters to enable it to
function independently of management and to facilitate open and candid discussion among the
independent directors. The Board holds in-camera independent director meetings through the
Corporate Governance Committee at every scheduled Board meeting, and otherwise as deemed
necessary and upon the request of independent directors.
26
CHAIRMAN
CHIEF EXECUTIVE OFFICER
The Chairman, Jean Claude
Gandur, is responsible for the
effective running of the Board,
ensuring that the Board
plays a full and constructive
part in the development and
determination of our strategy,
and acts as guardian and
facilitator of the Board’s
decision-making process.
The Chief Executive Officer, Michael Ebsary, is responsible for
managing Oryx Petroleum’s business, proposing and developing
the company’s strategy and overall commercial objectives in
consultation with the Board and, as leader of the executive team,
implementing the decisions of the Board and its Committees.
In addition, the Chief Executive Officer is responsible for
maintaining regular dialogue with shareholders as part of Oryx
Petroleum’s overall investor relations program.
LEAD INDEPENDENT DIRECTOR
The Lead Independent Director is Richard Alexander.
Mr. Alexander is an independent director and, in his role as Lead
Independent Director, acts in a leadership role facilitating the
functioning of the Board independently of management and
providing independent leadership to the Board as required.
27
BOARD OF DIRECTORS
Oryx Petroleum’s Board of Directors* is comprised of
accomplished individuals with a diversity of skills and
experience relevant to our operations.
Richard Alexander
David Codd
Michel Contie
Richard Alexander has a breadth of
experience in the energy sector. From May
2006 to June 2011, he held various positions
at AltaGas Ltd., including the position of
President. Mr. Alexander was also the Vice
President, Finance and Chief Financial Officer
of Niko Resources Ltd. from September 2003
to April 2006 and the Vice President, Investor
Relations and Communications of Husky
Energy Inc. from July 2000 to August 2003.
David Codd is a retired solicitor and has over
32 years’ experience in the international
oil industry. He was Chief Legal Officer of
Addax Petroleum from February 2005 until
his retirement in 2011. After qualifying
with a major U.K. law firm, Mr Codd worked
from 1980 to 1984 for Burmah Oil Company
Ltd. In 1984 he joined Britoil PLC as Senior
Legal Adviser. Following two years with
ConocoPhillips Company in the U.K., in 1990
he was appointed General Counsel to Texaco’s
integrated operations in the U.K. From 1999
to 2001, Mr Codd was Managing Director
of Texaco in the U.K., being Texaco’s senior
corporate representative in the U.K. with
business responsibility for Texaco’s regional
upstream business development. Following
Texaco’s merger with Chevron, Mr. Codd was
Chairman of a start-up company engaged in
project development work in the Middle East
until he joined Addax Petroleum in February
2005.
Michel Contie has a wide-range of experience
in the oil and gas sector. Mr Contie has
acted as a non-executive director at John
Wood Group PLC since February 2010. Prior
to this, Mr Contie started a consultancy
practice, Mentorca (SARL), where he was
a director from January 2010 to November
2011. Through Mentorca (SARL), Mr Contie
negotiated contracts with John Wood Group
PLC and Expro International Holdings Ltd.
From May 2006 to December 2009, Mr Contie
acted as the Vice President, Europe for Total.
Mr Alexander is currently a director of Global
Water Resources Corp., Marquee Energy Ltd.
and Parallel Energy Trust, and the President &
CEO of Parallel Energy Trust.
Mr Alexander is a citizen of Canada and
received a B.B.M. from Ryerson Polytechnical
Institute in Toronto, Canada.
Mr Codd is a citizen of the United Kingdom
and has an MA (Jurisprudence) and a BCL,
both from Oxford University.
28
Mr Contie is a citizen of France and obtained
an engineering degree in fluid mechanics
from the University of Toulouse, France and
also holds a degree as a petroleum engineer
from École Nationale Supérieure du Pétrole in
Paris, France.
*including Jean Claude Gandur and Michael Ebsary
Evan Hazell
Gerald Macey
Peter Newman
Evan Hazell is an engineer and has
experience in both the financial and energy
sectors. From 1998 to 2011 Mr Hazell
acted as a managing director at several
financial institutions including HSBC Global
Investment Bank and RBC Capital Markets.
Mr Hazell was granted the designation of
P.Eng from the Association of Professional
Engineers and Geoscientists of Alberta
in 1983.
Gerald Macey has over 40 years of oil and
gas industry experience. In particular, from
2002 to April 2004, he served as Executive
Vice President and President, International
New Ventures Exploration Division, of EnCana
Corporation, and from 1999 to 2002, he served
as Executive Vice President, Exploration, of
PanCanadian Petroleum Corporation. He is
also a director and Chairman of PanOrient
Energy Corp. and a director of Gran Tierra
Energy Inc. He was previously a director of
Addax Petroleum.
Peter Newman was a partner at Deloitte LLP
in London where he led the firm’s oil and gas
sector practice globally from 2002 until his
retirement in 2009. Prior to that, Mr Newman
joined the oil and gas group at Arthur
Andersen LLP in London in 1984, became a
partner in 1989 and led the firm’s oil sector
practice across Europe, the Middle East, India
and Africa. Mr Newman also worked with
Mobil Corporation from 1980 to 1984 as an
auditor in several countries across Europe,
Africa and the Far East. Mr Newman is nonexecutive director of AOG and Chairman of its
audit committee.
Mr Hazell is a Canadian citizen and received a
B.A. (Sc) from Queen’s University in Kingston,
Canada, a M. Eng from the University of
Calgary, Canada and an M.B.A. from the
University of Michigan in Ann Arbour, U.S.
Mr Macey is a Canadian citizen and holds a
Bachelor of Science degree in geotechnical
science from the University of Montreal
(Loyola College) and a Master of Science
degree in geology from Carleton University
in Ottawa.
Mr Newman is a citizen of the United Kingdom,
and studied geography at the University
of Oxford before qualifying as a Chartered
Accountant in England.
29
ORGANISATION
Our senior management team is shrewd, resourceful and
focused. They are supported by teams of technical, financial
and legal experts, whose expertise in all aspects of the
Jean Claude Gandur
Chairman
Michael Ebsary
Chief Executive Officer
Henry Legarre
Chief Operating Officer
Jean Claude Gandur founded The Addax and
Oryx Group in 1987 with three associates
from the energy industry, and focused on
Africa. With an instinctive ability to recognise
new opportunities, he rapidly diversified
the group’s activities from oil trading, to
downstream storage and distribution,
before launching into upstream exploration
and production in 1994, and a pioneering
bioenergy project in 2008. Following the sale
of Addax Petroleum in 2009, he initiated the
creation of Oryx Petroleum.
Michael Ebsary helped found Oryx Petroleum
in September 2010, when he was appointed
Chief Executive Officer.
Henry Legarre helped found Oryx Petroleum
in September 2010, when he was appointed
Chief Operating Officer.
Prior to this he had worked as Chief Financial
Officer of Addax Petroleum for eleven years
after having held various positions in project
finance and treasury with Elf and Occidental
Petroleum, both in France and the United
Kingdom. He began his working life in
multinational banking institutions in Canada
and the UK.
Prior to joining Oryx Petroleum, he was with
Addax Petroleum for four years, where he
was Managing Director, Middle East Business
Unit, and Acting General Manager for the
TaqTaq Operating Company in the Kurdistan
Region of Iraq. He had previously worked with
Chevron for 20 years, in various positions,
including projects in the United States, West
Africa, Latin America and the Middle East.
He has a degree in law and political science
from the University of Lausanne, Switzerland.
He is a graduate of Queen’s University
in Canada.
A member of the American Association
of Petroleum Geologists and the Society
of Petroleum Engineers, he is published
in geochemistry, petrophysics, reservoir
modelling and simulation and has served on
the steering committee of a number of Joint
Industrial Projects.
He has a degree in geological sciences from
the University in San Diego, California.
30
upstream energy industry give Oryx Petroleum the unique blend
of capabilities it needs to operate effectively, efficiently and
profitably in all license areas.
Craig Kelly
Chief Financial Officer
Craig Kelly helped found Oryx Petroleum in
September 2010, when he was appointed
Chief Financial Officer.
Before joining Oryx Petroleum, he was Head
of Corporate Finance for Addax Petroleum
for four years. Prior to this he had been a
director in the Energy Group of RBC Capital
Markets where he developed an expertise
in advisory work for clients involved in
mergers, acquisitions and financing in the
energy industry.
A graduate of Queen’s University in Canada,
he is a member of the Alberta Institute of
Chartered Accountants and earned his
Chartered Accountant designation while with
Ernst & Young in Hong Kong, Toronto and
Vancouver, Canada.
Paul Shillington
Chief Legal Officer
and Corporate Secretary
Paul Shillington joined Oryx Petroleum as
Chief Legal Officer and Corporate Secretary in
May 2011.
Prior to this, he had spent the previous six
years as an independent legal consultant,
based in Paris, France and Perth, Australia,
serving clients in the energy industry. His
clients included ExxonMobil and Addax
Petroleum. From 1999 to 2004 he was Asia
Pacific legal counsel for Technip, after having
commenced his legal career as a commercial
and litigation lawyer in Australia with Freehill
Hollingdale & Page and Phillips Fox.
He is a graduate of the University of
Western Australia.
31
RESERVES & RESOURCES
ADVISORY
Oryx Petroleum’s reserves and resource
estimates have been prepared and evaluated
in accordance with National Instrument
51-101 - Standards of Disclosure for
Oil and Gas Activities and the Canadian
Oil and Gas Evaluation Handbook as at
December 31, 2013.
Proved oil reserves are those reserves which
are most certain to be recovered. There is at
least a 90% probability that the quantities
actually recovered will equal or exceed the
estimated proved (1P) oil reserves. Probable
oil reserves are those additional reserves
that are less certain to be recovered than
proved oil reserves. There is at least a 50%
probability that the quantities actually
recovered will equal or exceed the sum of
the estimated proved plus probable (2P)
oil reserves. Possible oil reserves are those
additional reserves that are less certain to be
recovered than probable oil reserves. There is
a 10% probability that the quantities actually
32
recovered will equal or exceed the sum of
proved plus probable plus possible (3P)
oil reserves.
Contingent oil resources are those quantities
of petroleum estimated, as of a given date,
to be potentially recoverable from known
accumulations using established technology
or technology under development, but
which are not currently considered to be
commercially recoverable due to one or more
contingencies. There is no certainty that it will
be commercially viable to produce any portion
of the contingent oil resources.
Prospective oil resources are those quantities
of petroleum estimated, as of a given date, to
be potentially recoverable from undiscovered
accumulations by application of future
development projects. Prospective oil
resources have both a chance of discovery and
a chance of development. There is no certainty
that any portion of the prospective resources
will be discovered. The risked prospective
oil resources reported in this document are
partially risked resources that have been
risked for chance of discovery, but have not
been risked for chance of development. If
discovered, there is no certainty that it will be
commercially viable to produce any portion of
the prospective resources.
Use of the word “gross” to qualify a reference
to reserves or resources means, in respect
of such reserves or resources, the total
reserves or resources prior to the deductions
specified in the Production Sharing Contract,
Risked Exploration Contract or fiscal regime
applicable to each license area. Reference to
100% indicates that the applicable reserves,
resources or production are volumes
attributed to the discovery or prospect as a
whole and do not represent Oryx Petroleum’s
working interest in such reserves, resources
or production.
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2013
33
The following should be read in
conjunction with the consolidated
financial statements of Oryx Petroleum
Corporation Limited (“OPCL”) for year
ended December 31, 2013, which
have been prepared in accordance
with International Financial Reporting
Standards (“IFRS”) as issued by the
International Accounting Standards
Board (“IASB”). The date of this
Management’s Discussion and Analysis
is March 12, 2014.
On May 5, 2013, OPCL announced the
filing of a supplemented PREP prospectus
with the securities regulatory authorities
in each of the provinces of Canada, other
than Quebec, in connection with its initial
public offering of 16,700,000 common
shares, at a price of CAD$15.00 per
common share (the “Offering”) for total
gross proceeds of CAD$250.5 million
($249.4 million). The Offering closed
on May 15, 2013. Immediately prior to
closing, a corporate re-organisation
occurred whereby OPCL became the
parent company of Oryx Petroleum
Holdings PLC (formerly Oryx Petroleum
Company PLC and Oryx Petroleum
Company Limited).
All comparative
balances dated before May 15, 2013
included in the consolidated financial
statements for the year ended December
31, 2013 and these documents were
originally reported by Oryx Petroleum
Holdings PLC. Such balances have been
prepared in accordance with IFRS as
issued by the IASB.
Unless otherwise noted, tabular amounts
are in thousands of U.S. dollars and
amounts in commentary are in millions of
U.S. dollars.
Investors should read the “ForwardLooking Information” advisory on page
46. Additional information relating to
OPCL is on SEDAR at www.sedar.com.
Executive Summary
The following table summarises the results of OPCL and its subsidiaries (“Oryx
Petroleum”) for the year ended December 31, 2013 compared to the year ended
December 31, 2012:
Year ended
General and administrative expense
Pre-license costs
Impairment of oil and gas assets
Dec 31, 2013
($ thousand)
Dec 31, 2012
($ thousand)
40,131
22,612
6,383
6,608
82,948
29,017
728
361
54,314
142
184,504
58,740
Depreciation and amortisation expense
Other
(1)
Loss before income tax
Income tax expense / (benefit)
1,319
(203)
185,823
58,537
1,424
2,542
Total comprehensive loss
187,247
61,079
Cash surplus
306,034
64,944
248,482
137,399
Net Loss
Remeasurement of defined benefit
obligation(2)
Capital expenditure
(3)
Notes:
1. Includes finance (income) / expense, foreign exchange (gains) / losses and other operating expenses
2. In the current year, the Group has applied IAS 19 Employee Benefits (as revised in 2011) and the related consequential
amendments for the first time. The impact on the opening retained earnings as at January 1, 2012 and the 2012 and 2013
financial statements are summarised in the consolidated financial statements for the year ended December 31, 2013:
3. Refer to “Capital Expenditure” below.
Net loss increased by $127.3 million to $185.8 million for the year ended December 31, 2013
compared to 2012 mainly due to an upward revision to the fair value of the Hawler license
area’s contingent consideration ($56.9 million), as further described below, as well as the net
impairment expense recorded during the period ($82.9 million), mainly relating to the Dila-1
well in the OML 141 license area ($21.7 million), the Sindi Amedi license relinquishment ($45.2
million) and the Horse well in the Haute Mer A license area ($17.3 million). The remaining increase
in the net loss relates to a $17.5 million increase in general and administrative expense, partially
offset by net foreign exchange gains of $2.6 million.
A cash surplus of $64.9 million as at 31 December 2012 increased to $306.0 million at the end
of the 2013 fiscal year. The increase in cash is mainly due to additional equity funding of $234.8
million received from The Addax and Oryx Group Limited (“AOG”) in January 2013 as well as net
proceeds received upon the closing of the Offering on May 15, 2013 of CAD $239.0 million (gross
proceeds CAD $250.5 million).
The following table summarises the $248.5 million in capital expenditure incurred during the
year ended December 31, 2013 compared to 2012.
License Area
Location
Year ended
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
Hawler
Iraq - Kurdistan Region
146,560
74,694
Sindi Amedi
Iraq - Kurdistan Region
4,006
11,305
Wasit
Iraq – Wasit province
4,119
5,603
AGC Shallow
Senegal and Guinea
Bissau
2,830
19,303
OML 141
Nigeria
47,416
11,129
Congo Haute Mer A
Congo (Brazzaville)
41,464
14,092
Corporate
2,087
1,273
Total capital expenditure
248,482
137,399
The capital expenditure in the Hawler license area during the year ended December 31, 2013
includes $105.4 million in drilling expenditure. This expenditure is comprised of exploration
drilling, appraisal and testing activities conducted during the year. Drilling of the Demir Dagh-
34
2 well, which was completed in the first
quarter of 2013, incurred $1.8 million in
drilling expenditure. A further $11.1 million
in costs relating to testing on this well were
also incurred during the year. Three additional
exploration wells were drilled and tested in
2013; Ain-Al-Safra, Zey Gawra and Banan
which incurred a total of $61.7 million in
drilling costs. Testing was completed on the
Ain-Al-Safra and Zey Gawra wells during 2013
incurring a total of $16.7 million in costs. The
Demir Dagh-4 appraisal well spudded in late
December 2013 and incurred $2.1 million in
capital expenditure before year end. During
the year, the Demir Dagh-3 appraisal well
was spudded incurring $12.0 million in costs.
million in capital expenditure relates to capitalised general and administrative costs for the year.
In addition to the drilling costs, $8.6 million in
costs were capitalised relating to the Hawler
Early Production Facility (EPF). The facility is
expected to facilitate first production from
Demir Dagh which is planned for Q2 2014. The
EPF may also be utilised for the appraisal of
other prospects in the Hawler license area.
During 2013, Oryx Petroleum carried out exploration, appraisal and development activities in its
license areas. Oryx Petroleum had no commercial production during 2013 and, accordingly, did
not book any revenue from continuing operations.
A further $17.6 million was capitalised during
the year relating to an upward revision in fair
value of the contingent payment on the Hawler
license area, acquired as part of the business
combination with OP Hawler Kurdistan Ltd
(formerly Norbest Ltd) in 2011. Finally, $5.0
million in costs were incurred during the year
relating to the 2D seismic campaign on the
Banan area and the 3D seismic campaign on
the Demir Dagh area. The remaining capital
expenditure of $10.0 million relates to indirect
capitalised general and administrative costs.
The actual costs incurred in 2013 for all license areas, other than Hawler and OML 141, were
lower than the amounts budgeted. However this was more than offset by higher than budgeted
costs in the Hawler license area due to accelerated exploration and development activities.
There are no trends or events that have been identified that will have a material adverse
effect on the financial performance of Oryx Petroleum. The Company is planning to commence
production at Demir Dagh in the Kurdistan region of Iraq in the second quarter of 2014. It is
currently uncertain if the oil produced will be able to be sold on the international market. This
uncertainty could affect the future price of oil sold and thus OPCL’s cash flow. In addition, Oryx
Petroleum is not currently aware of any official allocation on the pipeline in the region and how
commercial terms for international sales would be established. The political instability in the
regions in which Oryx Petroleum operates and other risk factors identified in the Forward Looking
Information section could have an adverse effect on Oryx Petroleum’s performance; however this
has not affected Oryx Petroleum’s business, results of operations or financial conditions to date.
Summary of Reserves and Resources
The following is a summary of NSAI’s evaluation as at December 31, 2013 with comparatives to
NSAI’s evaluation as at March 31, 2013:
Oil reserves (1)
Location
License
The $4.1 million of capital expenditure
relating to the Wasit license area in 2013
relates to $1.3 million in seismic acquisition
costs and $2.8 million in capitalised
general
and
administrative
expense.
The OML 141 license area in Nigeria incurred
$47.4 million in capital expenditure in
2013. This amount mainly relates to $42.3
million in drilling costs (including carried
costs) relating to the Dila exploration well.
However the well was deemed unsuccessful
and $21.7 million in costs, representing
OPCL’s share of well costs, were written
off during the second quarter of 2013.
Two wells were drilled in the Haute Mer A
license area offshore Congo (Brazzaville) in
2013. Drilling on the Horse prospect (formerly
Ma) incurred $17.3 million of exploration
drilling costs and the Elephant prospect
incurred $15.6 million in drilling costs. Testing
on the Horse prospect was completed during
the year but was deemed unsuccessful
and an impairment charge of $17.3 million
was recognised. Testing on the Elephant
discovery began in December 2013 and was
not completed at the time of issuance of this
document; $5.5 million in testing costs were
incurred prior to year end. The remaining $3.0
March 31, 2013
Proved plus Probable Gross Oil (Working interest)
(2)
Iraq Kurdistan region
Seismic acquisition and studies expenditure
of $4.7 million was incurred in the Sindi Amedi
license area during the 2013 fiscal year. A
further $0.9 million in capital expenditure was
incurred relating to PSC compliance costs
and capitalised general and administrative
expense. These amounts were offset by $1.6
million in drilling costs that were recovered
from the operator during the period. However,
all capital expenditure relating to this license
area was written off in 2013 ($44.0 million)
following the relinquishment of the license
area to the Kurdistan Regional Government.
December 31, 2013
Hawler
Total oil reserves
Reserves
Future Net
Revenue(3)
Reserves
Future Net
Revenue(3)
(MMbbl)
($ million)
(MMbbl)
($ million)
213
1,287
164
815
213
1,287
164
815
Notes:
1. The oil reserves data is based on evaluations by NSAI, with effective dates as at March 31, 2013 and December 31, 2013 as
indicated. Volumes are based on commercially recoverable volumes within the life of the production sharing contract.
2. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the total
reserves or resources prior to the deductions specified in the production sharing contract, risk exploration contract or fiscal
regime applicable to each license area.
3. After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate. Gross proved plus probable oil reserve estimates used to calculate future net revenue are estimated based on
economically recoverable volumes within the development/production period specified in the production sharing contract,
risk exploration contract or fiscal regime applicable to each license area. The estimated values disclosed do not represent
fair market value.
Contingent oil resources (1)
Location
License
March 31, 2013
December 31, 2013
Best Estimate 2C Gross Oil (Working interest)
(2)
Iraq
Kurdistan region
Hawler
Congo
(Brazzaville)
Haute Mer A(4)
Total contingent
oil resources
Resources
Future Net
Revenue(3)
Resources
Future Net
Revenue(3)
(MMbbl)
($ million)
(MMbbl)
($ million)
217
697
200
1,451
6
-
-
-
223
697
200
1,451
Notes:
1. The contingent oil resource data is based on evaluations by NSAI, and the classification of such resources as “contingent oil
resources” by NSAI, with effective dates as at March 31, 2013 and December 31, 2013 as indicated. The figures shown are
NSAI’s best estimate using deterministic methods. Once all contingencies have been successfully addressed, the probability
that the quantities of contingent oil resources actually recovered will equal or exceed the estimated amounts is 50% for the
best estimate. Contingent oil resources estimates are volumetric estimates prior to economic calculations.
2. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the
total reserves or resources prior to the deductions specified in the production sharing contract, risk exploration contract or
fiscal regime applicable to each license area.
3. After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount
rate. Gross contingent oil resource estimates used to calculate future net revenue are estimated based on economically
recoverable volumes within the development/production period specified in the production sharing contract, risk exploration
contract or fiscal regime applicable to each license area. The estimated values disclosed do not represent fair market value.
4. An economic evaluation has not been performed by NSAI on the contingent oil reserves in Haute Mer A because the field
development plan is still under construction.
35
Prospective Oil Resources (1)
Location
License
December 31, 2013
March 31, 2013
Best Estimate Gross(2) Oil (Working interest)
Iraq
Kurdistan region
Hawler
Iraq
Kurdistan region
Sindi Amedi
Iraq
Wasit province
Unrisked
Risked
Unrisked
Risked
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
238
50
321
107
-(4)
-(4)
110
8
Wasit
404
78
404
77
AGC
AGC Shallow
AGC Shallow
267
38
243
31
Nigeria
OML 141
67
10
153
42
Congo (Brazzaville)
Haute Mer A
31
4
56
12
Congo (Brazzaville)
Haute Mer B
160
31
104
23
1,167
209
1,391
299
Total prospective
oil resources(3)
$33.5 million of the exploration drilling costs
in 2013 relate to the Zey Gawra well (“ZEG1”), representing $21.8 million in drilling
costs and $11.7 million in testing. The ZEG-1
well reached a total depth of 4,398 metres in
early August 2013. The Company announced
the successful discovery of oil at Zey Gawra
in December 2013 based on a successful
flow test from the Cretaceous reservoirs.
The Company is conducting further analysis
of the ZEG-1 well and intends to drill an
appraisal well at Zey Gawra in 2014 as part
of the multi-well appraisal and development
drilling program in the Hawler license area.
Depending upon the ultimate size of the Zey
Gawra discovery, the field could be tied into
the Company’s planned development at Demir
Dagh or developed on a standalone basis.
Notes:
1. The prospective oil resource data is based on evaluations by NSAI, and the classification of such resources as “prospective
oil resources” by NSAI, with effective dates as at March 31, 2013 and December 31, 2013 as indicated. The figures shown
are NSAI’s best estimate using a combination of deterministic and probabilistic methods and are dependent on a petroleum
discovery being made. If discovery is made and development is undertaken, the probability that the recoverable volumes will
equal or exceed the risked estimates is 50% for the best estimate. Prospective oil resources estimates are volumetric estimates prior to economic calculations.
2. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the
total reserves or resources prior to the deductions specified in the production sharing contract, risk exploration contract or
fiscal regime applicable to each license area.
3. Individual numbers provided may not add to total due to rounding.
4. The Sindi Amedi license area was relinquished in October 2013.
Capital Expenditure
The following table summarises the components of Oryx Petroleum’s capital expenditure per
region for the periods indicated:
Year ended
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
85,919
37,346
Middle East
Exploration drilling
Seismic acquisition
9,618
2,900
Studies and capitalised G&A
11,072
11,355
License acquisition costs
17,575
40,000
Property, plant & equipment
30,501
-
Sub-Total Middle East
154,686
91,601
49,564
4,233
West Africa
Exploration drilling
Seismic acquisition
834
18,273
Studies and capitalised G&A
10,556
15,324
License acquisition costs
30,672
6,695
Property, plant & equipment
83
98
Sub-Total West Africa
91,709
44,623
Corporate
2,087
1,175
Total Capital Expenditure
248,482
137,399
Middle East
Exploration drilling costs of $85.9 million in 2013 relate to drilling and testing in the Hawler
license area on the Zey Gawra, Ain Al Safra, Banan and Demir Dagh wells. This is a $48.6 million
increase from the exploration drilling costs incurred in 2012. The increase from 2012 relates
solely to an expanded drilling program in 2013 compared to the prior year.
36
The Ain Al Safra well (“AAS-1”), which incurred
$27.9 million in exploration drilling and
testing costs in 2013, reached target depth in
the third quarter of 2013 and the oil discovery
was announced by the Company in October
2013. AAS-1 was originally scheduled to
drill to a total depth of 3,700 meters in Q4
2013. Drilling was suspended and the well
secured at the 3,039 metre depth as heavy
losses of drilling fluids caused the bottom
hole assembly to become stuck. The well
was logged down to the lowermost Jurassic
and there was evidence of oil shows in the
Cretaceous, Jurassic and lower Jurassic of
varying quality. The Cretaceous reservoir
was deemed wet and not tested. In the lower
Jurassic reservoirs, free oil on the shakers and
sizable losses of drilling fluids were observed
with significant quantities of oil flowing to the
surface while drilling. Testing was completed
in 2013. Oryx Petroleum is conducting further
analysis of the AAS-1 well and intends to drill
an appraisal well at Ain Al Safra in 2014.
Oryx Petroleum spudded the BAN-1 well,
also in the Hawler license area, late in the
third quarter of 2013, targeting oil potential
in the Cretaceous, Jurassic and Triassic.
Drilling depth of 4,000 meters was reached
at the end of 2013 with a planned total depth
of 4,153 metres to be reached in Q1 2014. A
total of $18.4 million in drilling expenditure
was incurred. In January 2014, the drilling
program concluded and hydrocarbons
were encountered in the Cretaceous, Upper
and Lower Jurassic and Triassic. The well
experienced a significant pressure kick
while drilling at approximately 4,000 meters
in a fractured section of the Kurra Chine.
During the following well control operation,
light oil from the Kurra Chine formation
was burned at the flare. As the well had not
been designed for conditions encountered
in the Triassic, the well was plugged back
to 3,400 meters in preparation for testing
operations in the shallower Cretaceous and
Jurassic formations. A future appraisal well
with modified well design, if pursued, should
enable evaluation of the Kurra Chine formation
in the Banan structure. The Company’s testing
program for BAN-1 consists of five casedhole drill stem tests and one contingent
cased-hole drill stem test. It is expected that
the testing program will conclude in March
2014. Should the testing be successful, the
Company is considering accelerating plans
to drill an appraisal well on the crest of the
Banan structure.
The first well in the Demir Dagh Appraisal
program (DD-3) was spudded in midNovember and drilling reached 2,875 meters
as at December 31, 2013. The DD-3 well is
on schedule and is expected to reach a total
depth of 4,115 meters in Q2 2014.
reach gross (100%) production capacity of
25,000 bbl/d in Q4 2014.
With further development drilling, Oryx
Petroleum expects to achieve the full gross
(100%) production design capacity of 40,000
bbl/d in 2015. The Company plans to transport
production by truck or through export
pipelines. The EPF may also be utilised for the
appraisal of the other prospects in the Hawler
license area.
The timing of the start of production is
dependent on the timing of the installation of
the facilities and completion of wells drilled.
the AGC Shallow license area. An additional
adjustment of $0.5 million was recorded on
the OML 141 license area. This amount has
decreased by $4.7 million compared to $15.3
million in expenditure for the year ended in
2012. This decrease is related to pre-drilling
activity on the OML 141 license area in 2012
that was not performed in 2013. All costs
relating to the Dila well in the OML 141 license
area were impaired during the year.
The license acquisition costs incurred in 2013
relate solely to the cost of farming-in to the
OML 141 license area.
West Africa
Seismic acquisition expenditure increased
by $6.7 million to $9.6 million from 2012 to
2013. This amount includes $4.0 million in
expenditure on the Sindi Amedi license area,
$4.4 million on the Hawler license area and
$1.3 million in the Wasit license area.
Studies and capitalised general and
administrative expenditure of $11.1 million
remained consistent with prior year.
The acquisition costs recognised in 2013
relate to an upward revision in fair value of
$17.6 million to the contingent payment on
the Hawler license area, acquired as part of
the business combination with OP Hawler
Kurdistan Ltd (formerly Norbest Ltd) in 2011.
In September, 2013, Oryx Petroleum and its
partner relinquished the Sindi Amedi license
area resulting in an impairment charge of
$45.2 million.
The $30.5 million expenditure in property
plant & equipment (“PP&E”) during 2013
relates to the development of the Demir
Dagh area. The discovery on this license
area was announced in the first quarter
of 2013 therefore there were no costs in
PP&E associated with this development in
2012. Subsequent to year end, the Company
determined the discovery at the Demir Dagh
area to be commercial pursuant to the terms
of the Hawler Production Sharing Contract.
Oryx Petroleum is currently undertaking an
extensive appraisal program in relation to
the full Demir Dagh field, and will continue
to undertake such appraisal activities
through 2014.
During 2013 Oryx Petroleum agreed to
lease an early production facility (“EPF”)
from Expro, an international oilfield
services company specialising in well flow
management. The facility will have multiple
trains with the ability to process light, heavy,
sweet or sour crude types. The EPF will have
an initial capacity of 25,000 bbl/d and will be
re-engineered to a capacity of 40,000 bbl/d.
The Company expects the appraisal program
to be largely complete by mid-2014 with first
production targeted for Q2 2014 from the
Demir Dagh-2 well and the Demir Dagh-4
appraisal well with gross (100%) production
totalling approximately 7,000 to 9,000 bbl/d.
It is expected that following the drilling of
Demir Dagh-3, an additional appraisal well
and three development wells, the EPF will
In West Africa, exploration drilling for the year
ended December 31, 2013 of $49.6 million
relates to drilling on the E-1 exploration
well targeting the Elephant (formerly Xiang)
prospect and the H-1 well targeting the Horse
prospect (formerly Ma) in the Haute Mer A
license area in Congo (Brazzaville), as well as
drilling on the Dila well in OML 141 in Nigeria.
On the E-1 exploration well, Oryx Petroleum
discovered natural gas and crude oil. The
Elephant discovery will be tested in early 2014
as part of the multi-well drilling and testing
program in the Haute Mer A license area. The
H-1 well spudded during the third quarter of
2013, and drilling was completed in the fourth
quarter. Although the H-1 well encountered
both Tertiary and Cretaceous reservoirs with
good porosity, the reservoirs were water
bearing and the Company considers the well
unsuccessful. An impairment charge of $17.3
million was recognised during the fourth
quarter of 2013.
During 2013, drilling expenditure of $17.6
million related to the Dila well in OML
141 in Nigeria. The costs for this well
were impaired in the second quarter of
2013 as no commercially viable reserves
were discovered.
Seismic acquisition expenditure of $0.8
million for the year ended December 31, 2013
relates mainly to the AGC Shallow license
area. This amount has decreased by $17.4
million compared to the same period in
2012 as activity was mainly focused on data
evaluation during the current year.
Studies and capitalised general and
administrative expenditure of $10.6 million
for the year ended December 31, 2013
includes $9.1 million of expenditure on the
Haute Mer A license area and $2.0 million on
37
2014 Budgeted Capital Expenditure
The following table summarises Oryx Petroleum’s 2014 annual budgeted capital expenditure programs.
Location
License
($ million)
Kurdistan region
Hawler
Wasit Province
Wasit
Nigeria
Acquisition &
Special Permits
Drilling
Facilities
Seismic &
Studies
Other
Total
($ million)
($ million)
($ million)
($ million)
($ million)
($ million)
-
217.0
81.0
45.6
23.0
366.6
1.6
-
-
18.7
6.7
27.0
OML 141
-
-
-
14.6
4.6
19.1
AGC
AGC
-
40.0
-
0.3
4.6
44.9
Congo
HMA
-
27.3
-
1.4
3.1
31.8
HMB
-
34.8
-
0.8
3.5
39.1
Corporate
-
-
-
-
1.3
1.3
1.6
319.1
81.0
81.4
46.7
529.8
Corporate
Capex Total
Budgeted capital expenditures include 14 wells to be completed in 2014 – 3 exploration (Banan on Hawler, HMB and AGC), 6 appraisal (5 wells
on Hawler and 1 on HMA) and 5 development (all on Hawler). Budgeted seismic expenditures include seismic campaigns on Hawler, Wasit and
OML141 license areas. Budgeted facilities expenditures relate to the installation of an Early Production Facility and expenditures on the Permanent
Production Facility on the Hawler license area.
Exploration and Evaluation Assets
Oryx Petroleum invested further in exploration and evaluation assets, transferred a portion of costs to property, plant and equipment relating to
discovered reserves and impaired a portion of costs related to unsuccessful exploration during 2013.
Net book value
Exploration and Evaluation Assets
At December 31, 2013
($ thousand)
($ thousand)
199,900
478,302
Following a reserve report from Netherland, Sewall & Associates Inc. (NSAI), effective March
31, 2013, indicating the discovery of reserves at Demir Dagh within the Hawler license area
in Kurdistan, a portion of the exploration and evaluation costs relating to this license area
were transferred to property, plant and equipment (PP&E). As a result, $373.2 million of costs
associated with the license were transferred from intangible assets to oil and gas assets
classified as PP&E as of December 31, 2013.
A subsequent NSAI report, effective December 31, 2013 included the discovery of reserves at
Zey Gawra within the Hawler license area. As a result, $33.5 million of costs associated with Zey
Gawra were transferred to PP&E from intangible oil and gas assets during 2013.
A total of $82.9 million in impairment expense was recorded during 2013. This impairment
expense is comprised of $21.7 million relating to the Dila prospect in the OML 141 license area
in Nigeria, $17.3 million relating to the Horse prospect (formerly Ma) in the Haute Mer A license
area offshore Congo (Brazzaville), and $43.9 million relating to the relinquishment of the Sindi
Amedi license.
The net reduction in intangible assets during the year ended December 31, 2013 of $278.4
million reflects the transfer to PP&E of $406.7 million due to the successful drilling on the
Hawler license area at Demir Dagh and Zey Gawra, and the impairment charge of $82.9 million,
offset by additions of $211.3 million.
38
Property Plant and Equipment
The property plant and equipment balance comprises oil and gas assets relating to the Hawler license area, as well as furniture and fixtures.
Oil and gas assets
Furniture and fixtures
Property plant and equipment
($ thousand)
($ thousand)
441,767
-
2,057
575
443,824
575
Oil and gas assets as at December 31, 2013 includes $406.7 million in expenditure transferred from intangible E&E assets following the discovery
of reserves at Demir Dagh ($373.2 million) and Zey Gawra ($33.5 million), both within the Hawler license area. A further $35.0 million in additions
were incurred during the year which relate to the development of the Hawler license area.
Financial Results
General and Administrative Expense
The following table summarises the component parts of general and administrative expense for the 2013 and 2012 financial years.
Year ended
General and administrative costs
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
15,084
10,883
(1)
25,047
11,729
Total General and administrative expense
40,131
22,612
Stock-based compensation
Notes:
1. Includes cash and non-cash expenses related to the OPCL Long Term Incentive Plan (“OPCL LTIP”).
General and administrative expense increased by $17.5 million to $40.1 million during the year ended December 31, 2013 compared
to the previous year (2012: $22.6 million). The increase was primarily due to the increase in stock-based compensation expense in the
second quarter due to the share grant to employees and management in conjunction with the Offering ($13.7 million). The increase in other
general and administrative costs was mainly due to additional staff numbers (average headcount for 2013 of 71 compared to 39 in 2012).
Exploration Expense
Pre-license costs in 2013 were at a similar level to those in 2012. Impairment of oil and gas assets includes the impairment of unsuccessful
exploration wells during the year.
Year ended
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
Pre-license costs
6,383
6,608
82,948
29,017
Total Exploration Expense
89,331
35,625
The $53.9 million increase in impairment of oil and gas assets in 2013 compared to 2012 relates to an increase in wells written off during the
current year. In 2012, the impairment expense solely relates to the Mateen-1 well drilled in conjunction with the operator of the Sindi Amedi
license area. This impairment charge was adjusted downward in the second quarter of 2013 by $1.2 million based on new information from the
operator.
During 2013, the drilling on the Dila prospect in the OML 141 license area was impaired as the well was considered unsuccessful, resulting in an
impairment charge of $21.7 million. A further impairment charge of $17.3 million was recognised relating to the H-1 well in the Horse prospect
of Haute Mer A license area offshore Congo (Brazzaville). The remaining impairment expense of $45.2 million relates to the relinquishment of the
Sindi Amedi license area.
39
Depreciation and Amortisation Expense
The following table summarises the component parts of depreciation and amortisation expense for years ended December 31, 2013 and December
31, 2012.
Year ended
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
Intangible assets: amortisation expense
437
271
Property, Plant and Equipment assets:
depreciation expense
291
90
Total Depreciation and Amortisation
Expense
728
361
Other Expenses
The following table summarises the components of other operating expense for the years ended December 31, 2013 and December 31, 2012.
Year ended
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
Other operating expense
56,887
-
Financial (income) / expense - net
(2,573)
142
Other expenses
54,314
142
During 2013, total other operating expense
increased to $56.9 million due to the reevaluation of contingent consideration arising
from the acquisition of OP Hawler Kurdistan
Ltd in 2011. In accordance with the terms
of the agreement for the acquisition of OP
Hawler Kurdistan Ltd, which holds the interest
in the Hawler license area, Oryx Petroleum is
obliged to provide additional consideration
upon a declaration of commercial discovery
as outlined in the Hawler production sharing
contract (“PSC”). The aggregate fair value of
the contingent consideration, based on the
estimated probability of success, was initially
evaluated by the directors of Oryx Petroleum
Corporation Limited at $46.3 million in
total and $27.7 million of this amount was
recognised in Oryx Petroleum’s statement of
financial position at December 31, 2012 with
the remaining amount included as an increase
in intangible E&E assets.
In addition, the net assets and liabilities
acquired with OP Hawler Kurdistan Ltd
included a contingent payment to the
Kurdistan Regional Government in relation
to the first commercial discovery. The total
potential liability is $50.0 million, the fair
value of which was initially evaluated by
the directors of Oryx Petroleum Corporation
Limited at $32.4 million and recognised in
the fair values of identifiable assets and
liabilities acquired.
Following the discovery of reserves at Zey
Gawra and Demir Dagh, the fair value of the
contingent consideration was re-evaluated
and estimated at $134.6 million, resulting in
increases in fair value recorded for contingent
consideration and the contingent payment,
amounting to $74.5 million, of which $56.9
million in relation to contingent consideration
was recognised in the statement of
comprehensive income and $17.6 million
in relation to the contingent payment was
capitalised and then transferred from
intangible assets to property, plant and
equipment oil and gas assets.
A portion of the contingent consideration
is expected to be paid within one year. A
payment of $50.0 million was made to the
Kurdistan Regional Government in February
2014 in full settlement of the contingent
payment due.
Income Tax Expense
The following table summarises the component parts of income tax expense for the 2013 and 2012 fiscal years.
Year ended
40
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
Current income tax expense
1,361
667
Deferred tax benefit
(42)
(870)
Total Income Tax Expense / (Benefit)
1,319
(203)
Summary of Quarterly Results
The following table sets forth a summary of Oryx Petroleum’s results for the quarterly periods indicated.
2012
Mar 31
Jun 30
2013
Sept 30
Dec 31
Mar 31
($ thousand)
Jun 30
Sept 30
Dec 31
($ thousand)
Net (Income) Loss from
Continuing Operations
before Income Taxes is
Comprised of:
Oil and Gas (1)
1,189
32,652
95
1,689
1,672
21,934
47,040
18,685
Corporate and
Other(2)
2,363
3,003
7,025
10,724
45,237
16,062
17,855
16,019
Net loss before income
tax
3,552
35,655
7,120
12,413
46,909
37,996
64,895
34,704
Income Tax Expense /
(Benefit)
(205)
65
7
(70)
67
494
252
506
Net loss
3,347
35,720
7,127
12,343
46,976
38,490
65,147
35,210
per share
0.19
1.99
0.13
0.23
0.59
0.44
0.66
0.35
Net loss attributable
to owners of OPCL
(excluding noncontrolling interests)
3,285
35,685
7,046
12,343
46,815
38,457
65,109
35,183
Per share
0.18
1.99
0.27
0.23
0.59
0.43
0.65
0.35
Remeasurement
of defined benefit
obligation
-
-
-
2,542
-
-
-
1,424
Total
comprehensive loss
3,347
35,720
7,127
14,885
46,976
38,490
65,147
36,634
per share
0.18
1.99
0.27
0.28
0.59
0.43
0.65
0.37
Total comprehensive
loss attributable
to owners of OPCL
(excluding noncontrolling interests)
3,285
35,685
7,046
14,885
46,815
38,457
65,109
36,607
Per share
0.18
1.99
0.27
0.28
0.59
0.43
0.65
0.37
Capital expenditure
11,728
13,689
30,507
81,475
54,430
48,946
69,241
75,865
Notes:
1. Oil and gas expense includes pre-license and impairment expense
2. Corporate and other expense includes general and administrative expense, depreciation and amortisation expense and other operating expense
The net loss of $35.2 million for the three
months ended December 31, 2013 includes
the $17.3 impairment expense relating to the
Horse prospect (formerly Ma) in the Haute Mer
A license area offshore Congo (Brazzaville).
Drilling on this well was completed in the
fourth quarter of 2013. Although the H-1 well
encountered both Tertiary and Cretaceous
reservoirs with good porosity, the reservoirs
were water bearing. The Company considers
the well unsuccessful. The loss for the
quarter also includes $2.3 million recorded
as interest expense relating to accrued
interest on contingent consideration arising
from the acquisition of OP Hawler Kurdistan
Ltd. A further $7.8 million was expensed due
to the re-evaluation of the fair value of the
contingent consideration relating to Hawler.
The remaining costs consist of $2.3 million in
stock-based compensation and $3.7 million
in general and administrative costs.
months ended September 30, 2013 includes
the impairment expense relating to the
relinquishment of the Sindi Amedi license
during the period ($45.2 million). In addition
$9.8 million was expensed due to the reevaluation of the contingent consideration
relating to Hawler by moving a portion of the
payment from long-term to short-term as well
as changes to the risking based on recent
drilling results. A stock-based compensation
expense of $4.5 million was also recorded in
the third quarter of 2013.
months ended June 30, 2013 includes the
impairment of the Dila-1 well in the OML 141
license area of $21.7 million and the share
gift granted to employees and management in
conjunction with the IPO of $13.7 million.
months ended March 31, 2013 includes
the change in fair value of contingent
consideration for Hawler of $39.3 million
following the discovery of reserves at
Demir Dagh-2.
The increase in the fourth quarter 2012 net
loss of $12.3 million compared to the third
quarter 2012 net loss of $7.1 million was
due to bonus payments in December of $1.2
million, IPO preparation costs of $1.7 million
and additional LTIP costs for new employees
and costs for directors of $1.8 million.
Net loss from continuing oil and gas
operations comprises pre-license costs and,
in June 2012, the impairment of the Mateen
well in the Sindi Amedi license area of $31.1
million and in June 2013, the impairment of
the Dila-1 well in the OML-141 license area
of $21.7 million. The impairment charge for
Sindi Amedi was subsequently reviewed and
adjusted in September 2012 based on new
information, resulting in a write-back of $2.1
million and an additional write-back in the
second quarter of 2013 of $1.2 million.
41
Annual Information
The following table sets forth a summary of Oryx Petroleum’s results for the years indicated.
Year ended
Dec 31, 2013
Dec 31, 2012
Dec 31, 2011
($ thousand)
($ thousand)
($ thousand)
Net (Income) Loss from Continuing Operations before Income Taxes is
Comprised of:
89,331
35,625
1,894
(2)
95,173
23,115
14,458
Oil and Gas (1)
Corporate and Other
Net loss before income tax
184,504
58,740
16.352
Income Tax Expense / (Benefit)
1,319
(203)
348
Net loss
185,823
58,537
16,700
per share
2.05
2.10
2.72
Net loss attributable to owners of OPCL (excluding non-controlling
interests)
185,564
58,359
16,700
Per share
2.04
2.10
2.72
Remeasurement of defined benefit obligation
1,424
2,542
-
Total comprehensive loss
187,247
61,079
16,700
per share
2.06
2.19
2.72
Total comprehensive loss attributable to owners of OPCL (excluding
non-controlling interests)
186,988
60,901
16,700
Per share
2.06
2.19
2.72
Capital expenditure
248,482
137,399
371,581
Total assets
976,212
576,265
401,142
Long term debt
-
-
16,599
Notes:
1. Oil and gas expense includes pre-license and impairment expense
2. Corporate and other expense includes general and administrative expense, depreciation and amortisation expense and other operating expense
The company has not distributed cash dividends during the 2013, 2012 or 2011 financial years.
Liquidity and Capital Resources
The following table summarises the components of Oryx Petroleum’s consolidated change in
cash flow for the periods indicated:
Year ended
Dec 31, 2013
Dec 31, 2012
($ thousand)
($ thousand)
Funds flow absorbed by operations
(77,273)
(17,850)
Decrease / (Increase) in non-cash
Working Capital
68,541
(5,906)
Net cash used in operating activities
(8,732)
(23,756)
Net cash used in investing activities
(234,079)
(92,900)
Net cash generated by financing activities
476,120
164,100
Net Increase in Cash and cash equivalents
233,309
47,444
The net change in cash for the year ended
December 31, 2013 of $233.3 million is
primarily due to $476.1 million from financing
activities which is offset by cash used in
investing activities of $234.1 million. The cash
received from financing activities includes
funding received from AOG ($234.8 million)
and the net proceeds received from the IPO
($230.5 million) and other investors ($10.8
million). The net investing activities for year
42
ended December 31, 2013 of $234.1 million
comprises mostly of $136.8 million on the
Hawler license area, $38.1 million on the
OML-141 license area, $45.0 million on the
Congo Haute Mer A license area, $5.3 million
on the Sindi Amedi license area, $4.9 million
on the Wasit license area and $2.8 million on
the AGC Shallow license area.
Oryx Petroleum meets its day to day working
capital requirements through the funding
received from the IPO and the balance of $723
million in equity funding provided by AOG and
other investors. AOG’s equity funding ($700
million) was fully invested in shares by the
end of the first quarter 2013.
Oryx Petroleum entered into an uncommitted
bond facility agreement in 2013 whereby up
to a maximum of US$15 million may be used
by Oryx Petroleum for bank guarantees. As
of December 31, 2013, no guarantees were
issued under this agreement. This agreement
was extended for an additional twelve months
in February 2014.
Oryx
Petroleum’s
business
requires
significant capital expenditures for the
foreseeable future with respect to the
exploration, appraisal, development and
maintenance of its oil and gas assets. There
can be a long lead time between discovery
and production of oil and gas, particularly for
gas. During this lead time, Oryx Petroleum will
continue to incur significant costs at a level
which may be difficult to predict, but may not
have any earnings from oil or gas production.
Oryx Petroleum intends to fund these planned
capital expenditures from its cash reserves in
the short term and, in the longer term, from
new equity financing and, if successful in its
exploration and development efforts, from operating cash flow and new debt. The ability of Oryx Petroleum to arrange such financing in the future
will depend in part upon prevailing market conditions, as well as the business performance of Oryx Petroleum.
OPCL has a substantial capital expenditure program, budgeted to be approximately $529.8 million in 2014. This capital expenditure program is
expected to fund three exploration wells (Banan on Hawler, HMB and AGC), six appraisal wells (five wells on Hawler and one on HMA) and five
development wells (all on Hawler). In addition, the program is funding two separate 2-D seismic acquisition programs covering over 350 square
kilometres, one 3-D seismic acquisition program and general corporate expenditures. Of the total budgeted capital expenditure program for
2014 ($529.8 million), $141.1 million is committed at December 31, 2013 to be spent within one year. Refer to Contractual Obligations section for
additional details.
Oryx Petroleum has no debt and a considerable degree of control over both the extent and timing of expenditure under its future capital investment
program.
Changes in Working Capital
The following table summarises the components of Oryx Petroleum’s consolidated change in working capital for the periods indicated ($
thousand):
2012
Mar 31
Jun 30
2013
Sept 30
Dec 31
Mar 31
($ thousand)
Jun 30
Sept 30
Dec 31
($ thousand)
Trade and other
receivables
(983)
995
2,291
4,238
(37)
(6,282)
(804)
(1,432)
Inventories
577
1,694
2,545
712
432
3,114
(755)
4,073
Trade and other payables
260
(1,594)
(3,356)
(1,473)
(38,222)
4,553
(16,296)
(16,885)
Total Change in Non-Cash
Working Capital
(146)
1,095
1,480
3,477
(37,827)
1,385
(17,855)
(14,244)
Change in Cash and Cash
equivalents
3,673
10,809
96,769
(63,807)
172,770
191,979
(60,041)
(71,399)
Total Change in Net
Working Capital
3,527
11,904
98,249
(60,330)
134,943
193,364
(77,896)
(85,643)
Short term debt
46,096
(29,209)
188,976
(100)
7,781
-
-
-
Long term debt
-
2,704
13,895
-
-
-
-
-
Equity attributable to
owners of OPCL
(60,092)
34,229
(322,520)
11,094
(198,172)
(218,826)
60,805
25,889
Non-controlling interests
62
35
81
-
161
33
38
8,377
43
Use of Proceeds from IPO
The following table compares the planned use of proceeds from the prospectus offering to the position at December 31, 2013:
As at
May 15, 2013
As at
Dec 31, 2013
Variance
($ million)
($ million)
($ million)
483
306
(177)
The remainder of the 2013 capital expenditure program
284(1)
-
(284)
The remainder of 2013 pre-license and G&A costs
16(1)
-
(16)
The estimated expenditures of 1H 2014 capital expenditure program
124
201
77
The estimated pre-license and G&A costs for 1H 2014
Cash
to fund the following:
12
9
(3)
(2)
47
96
49
Total
483
306
(177)
General corporate purposes
Notes:
1. Estimated as at March 31, 2013.
2. Including contingent acquisition payments, if any, and acquisitions, if any.
Cash has reduced by $177 million due to the expenditure between the IPO date and December 31, 2013. Capital expenditure for the
remainder of 2013 has reduced by $284 million between the IPO date and December 31, 2013 due to expenditure between the two dates
and the relinquishment of the Sindi Amedi license area in which Oryx Petroleum had expected to drill an exploration well. Pre-license costs
and general and administrative costs for the remainder of 2013 have decreased by $16 million due to expenditure between the IPO date and
December 31, 2013.
None of the variances will impact OPCL’s ability to achieve its business objectives and milestones.
The estimated expenditures of the 1H 2014 capital expenditure program, and pre-license costs and general administrative costs for 1H 2014, have
increased to reflect OPCL’s 2014 capital budget as announced in November 2013. The major changes between the estimated and budget amounts
are the removal of exploration and appraisal wells in Sindi Amedi, Wasit and OML 141 which have been more than offset by two additional rigs
drilling appraisal and development wells, together with expenditure on early production facilities, at Demir Dagh in the Hawler license area and an
appraisal well in the Haute Mer A license area in Congo (Brazzaville).
Non-IFRS Measures
OPCL defines “Cash surplus / (Net debt)” as long-term debt and short-term borrowings less
cash and cash equivalents. OPCL uses net debt as a key indicator of its leverage and to monitor
the strength of its balance sheet. Net debt is directly tied to OPCL’s operating cash flow and
capital investment. Net debt is not recognised under IFRS as issued by IASB. Readers are
cautioned that these measures should not be construed as an alternative to net income or cash
flow from operating activities determined in accordance with IFRS or as an indication of OPCL’s
performance. OPCL’s method of calculating this measure may differ from other companies and
accordingly, it may not be comparable to measures used by other companies.
The following table summarises the components of Oryx Petroleum’s consolidated change in
“Cash surplus / (Net debt)” for the periods indicated:
As at Dec 31, 2013
As at Dec 31, 2012
($ thousand)
($ thousand)
Borrowings
44
Current
-
7,781
Non- current
-
-
Total Borrowings
-
7,781
Less: Cash and cash equivalents
306,034
(72,725)
Cash surplus
(306,034)
(64,944)
Equity Security
Repurchases
There were no repurchases of OPCL’s equity
securities during the three months or year
ended December 31, 2013.
Outstanding Share Data
The number of common shares outstanding at
as at the date of this document is 99,885,635.
There are no securities convertible into or
exercisable or exchangeable for voting shares.
There are LTIP awards that have been granted
pursuant to the OPCL LTIP which, upon vesting
in accordance with the OPCL LTIP, will result in
the issuance of up to an aggregate of 865,954
shares over 2014 and 2015.
Off Balance Sheet
Arrangements
In order to hedge foreign currency transactions
in the ordinary course of business, Oryx
Petroleum entered into a forward exchange
contract with Credit Suisse in December
2012 to purchase CHF 1,500,000 per month
for the 12 months of 2013. There are no
forward currency contracts outstanding as
at December 31, 2013. Refer to Financial
Instruments and Other Instruments section.
On May 9, 2013, Oryx Petroleum sold CAD $150 million and purchased $149.4 million at the forward rate of CAD $1.0043 per $1, with delivery on
May 21, 2013. A foreign exchange gain of $3.1 million was realised on this transaction.
Other than the above transactions, Oryx Petroleum was not party to any off-balance sheet arrangements during the year ended December 31, 2013
that will have, or is reasonably likely to have, an effect on the performance or financial condition of Oryx Petroleum. Further, on the date of this
MD&A, Oryx Petroleum is not party to any such off-balance sheet arrangements.
Contractual Obligations The table below sets forth information relating to Oryx Petroleum’s contractual obligations and commitments as at December 31, 2013.
The other long term obligations include the lease signed during the third quarter of 2013 for the Early Production Facility relating to the Hawler
license area.
Within One Year
From 1 to 5 Years
More than 5 Years
Total
($ thousand)
($ thousand)
($ thousand)
($ thousand)
Operating leases(1)
677
139
-
816
Other long term obligations(2)
141,110
36,821
-
177,931
Total
141,787
36,960
-
178,747
Notes:
1. Operating leases primarily relate to property and computer hardware
2. Consists principally of obligations related to PSC commitments and capital expenditure commitments. The main purpose of these commitments is to develop oil and gas assets in Oryx Petroleum’s various exploration areas.
Financial Instruments and
Other Instruments
Transactions with Related
Parties
OPCL operates internationally and has foreign
exchange risk arising from various currency
exposures, notably the Swiss franc. In order
to hedge against this exposure, OPCL entered
into a forward exchange contract in December
2012 to sell U.S. dollars and buy Swiss francs.
By entering into this contract, OPCL has the
right and the obligation to sell U.S. dollars and
buy Swiss francs at a predetermined time and
at a predetermined U.S. dollar / Swiss franc
exchange rate if either the spot exchange rate
trades at or below the lower exercise price
or at or above the upper exercise price. This
contract expired in December 2013 and no
forward currency exchange contracts were
outstanding as at December 31, 2013. Any
gains or losses arising from the application
of this contract have been charged to the
statement of comprehensive income.
For the year ended December 31, 2013, OPCL
incurred $4.2 million for goods and services
provided by related parties, all of which are
subsidiaries of AOG (2012: $4.6 million).
Those costs mainly concerned trademark
license fees, parent company guarantees,
management service fees, furniture and
fixtures, and have been incurred under
agreements between OPCL and AOG that
continue to be in place. Additional information
relating to such agreements is available in
OPCL’s Supplemented PREP Prospectus
dated May 8, 2013, which is available on
SEDAR at www.sedar.com.
In addition to the forward exchange contract
above, OPCL entered into a second forward
exchange contract in the second quarter
of 2013 that settled in the same period.
Oryx Petroleum sold CAD $150 million at
a forward rate of CAD $1.0043. A foreign
exchange gain of $3.1 million was realised on
this transaction.
In addition, during the third quarter of 2013,
OPCL made a donation to The Addax and
Oryx Foundation for $0.5 million. The Addax
and Oryx Foundation is an independently
governed, Swiss registered charitable
foundation dedicated to support initiatives
in the provision of medical, educational and
food security needs in Africa and Asia.
In January 2013, AOG subscribed for shares
to the value of $234.8 million. In May 2013,
AOG subscribed for shares through the IPO
to the value of $20.0 million, which brings
total funding from AOG to $720.0 million. In
addition, certain directors of OPCL subscribed
in the IPO in the aggregate amount of $2.0
million.
Proposed Transactions
There are no planned asset or business
acquisitions or dispositions that would have
a material effect on the financial condition,
financial performance and cash flows of
Oryx Petroleum.
New Accounting
Pronouncements
Oryx Petroleum has adopted all of the new
and revised standards and interpretations
issued by the IASB and IFRIC that are
relevant to its operations and effective for
accounting periods beginning on or after
January 1, 2013 as described in Note 2 of the
consolidated financial statements for the
year ended December 31, 2013. The adoption
of these standards and interpretations has
not had a material effect on OPCL, except
for the adoption of IAS 19 (2011) Employee
Benefits. Implementation of this standard
resulted in an additional expense of $2.1
million for the year ended December 31, 2013
(2012: $3.6 million).
During the third quarter of 2013, the directors
of OPCL were awarded, in aggregate, 12,882
common shares ($0.1 million) and $0.1 million
in cash as remuneration for services provided
in the first and second quarter of 2013. In
January 2014, the directors were awarded
12,446 common shares ($0.1 million) and $0.2
million in cash as remuneration for services
provided in the third and fourth quarters of
2014.
45
Financial Controls and Risk
Management
Forward-Looking
Information
Disclosure Controls and Procedures
Certain statements in this MD&A constitute
“forward-looking information”, including
statements related to the nature, timing
and effect of Oryx Petroleum’s future capital
expenditures and budget, financing and
capital activities, business and acquisition
strategy and goals, opportunities, reserves
and resources estimates and potential, drilling
plans, development plans and schedules and
chance of success, future seismic activity,
results of exploration activities, declarations
of
commercial
discovery,
contingent
liabilities and government approvals, the
ability to gain access to exterior facilities or
build necessary facilities to sell future oil
production, if any, future drilling of new wells,
ultimate recoverability of current and longterm assets, future royalties and tax levels,
access to future financing and liquidity,
future debt levels, availability of committed
credit facilities, possible commerciality of
our projects, expected operating capacity,
expected operating costs, estimates on a per
share basis, future foreign currency exchange
rates, future expenditures, changes in any of
the foregoing and statements that contain
words such as “may”, “will”, “would”, “could”,
“should”, “anticipate”, “believe”, “intend”,
“expect”, “plan”, “estimate”, “budget”,
“outlook”, “propose”, “potentially”, “project”,
“forecast” or the negative of such expressions
and statements relating to matters that are
not historical fact, constitute forward-looking
information within the meaning of applicable
Canadian securities legislation.
Disclosure Controls and Procedures (“DC&P”)
have been designed under the supervision
of the Chief Executive Officer (“CEO”) and
the Chief Financial Officer (“CFO”), with
the participation of other management,
to provide reasonable assurance that
information required to be disclosed is
recorded, processed, summarised and
reported within the time periods specified
in applicable securities legislation, and
include controls and procedures designed
to ensure that information required to be
disclosed is accumulated and communicated
to management, including the CEO and CFO,
as appropriate to allow timely decisions
regarding required disclosure.
An evaluation of the design and operation
of OPCL’s DC&P was carried out during
2013 under the supervision of, and with the
participation of management including its
certifying officers. Based on that evaluation,
the certifying officers concluded that the
design and operation of the DC&P were
effective as at December 31, 2013.
Internal Control Over Financial Reporting
Internal Controls over Financial Reporting
(“ICFR”) have been designed under the
supervision of the CEO and the CFO, with the
participation of other management, to provide
reasonable assurance regarding the reliability
of financial reporting and the preparation of
financial statements in accordance with IFRS.
ICFR can only provide reasonable assurance
and may not prevent or detect misstatements.
Projections of an evaluation of effectiveness
to future periods are subject to the risk that
controls may become inadequate due to
changes in conditions, or that the degree of
compliance with the policies and procedures
may deteriorate.
An evaluation of the design and operation
of OPCL’s ICFR was carried out during 2013
under the supervision of, and with the
participation of management, including its
certifying officers. Based on that evaluation,
the certifying officers concluded that the
design and operation of the ICFR were
effective as at December 31, 2013.
46
In addition, information and statements in this
MD&A relating to reserves and resources are
deemed to be forward-looking information, as
they involve the implied assessment, based
on certain estimates and assumptions, that
the reserves and resources described exist
in the quantities predicted or estimated, and
that the reserves and resources described
can be profitably produced in the future. See
“Reserves and Resources Advisory” below.
Although Oryx Petroleum believes these
statements to be reasonable, the assumptions
upon which they are based may prove to
be incorrect. In making certain statements
in this MD&A, Oryx Petroleum has made
assumptions with respect to the following: the
general continuance of the current or, where
applicable, assumed industry conditions,
the continuation of assumed tax, royalties
and regulatory regimes, forecasts of capital
expenditures and the sources of financing
thereof, timing and results of exploration
activities, access to local and international
markets for future crude oil production, if any
and future crude oil prices, Oryx Petroleum’s
ability to obtain and retain qualified staff,
contractors and personnel and equipment
in a timely and cost-efficient manner, the
political situation and stability in jurisdictions
in which Oryx Petroleum has licenses, the
ability to renew its licenses on attractive
terms, Oryx Petroleum’s future production
levels, the applicability of technologies
for the recovery and production of Oryx
Petroleum’s oil reserves and resources, the
amount, nature, timing and effects of capital
expenditures, geological and engineering
estimates in respect of Oryx Petroleum’s
reserves and resources, the geography of the
areas in which Oryx Petroleum is conducting
exploration and development activities,
operating and other costs, the extent of
Oryx Petroleum’s liabilities, and business
strategies and plans of management and Oryx
Petroleum’s business partners.
Forward-looking information is subject to
known and unknown risks and uncertainties
which may cause actual results or events
to differ materially from those anticipated
in the forward-looking information and
statements if the assumptions underlying
them prove incorrect, or if one or more of
the uncertainties or risks described below
materialises. The risks and uncertainties
affecting Oryx Petroleum include, but are
not limited to, imprecision of reserves and
resources estimates; ultimate recovery of
reserves, ability to commercially develop
its oil reserves and/or its prospective and
contingent oil resources; commodity prices;
general economic, market and business
conditions; industry capacity; competitive
action by other companies; refining and
market margins; the ability to produce and
transport crude oil and natural gas to markets;
weather and climate conditions; results of
exploration and development drilling and
other related activities; fluctuation in interest
rates and foreign currency exchange rates;
ability of suppliers to meet commitments;
actions by governmental authorities, including
increases in taxes; decisions or approvals of
administrative tribunals, renewal or granting
of licenses; changes in environmental and
other regulations; international political
events; renegotiations of contracts; reliance
on key managers and personnel; dry wells may
lead to a downgrading of Oryx Petroleum’s
licenses or contracts or require further funds
to continue exploration work; future foreign
currency exchange rates; risks related to the
actions and financial circumstances of our
agents and contractors, counter-parties and
joint venture partners; political uncertainty,
including actions by terrorists, insurgent
or other groups, or other armed conflict,
including conflict between states; and
expected rates of return. More specifically,
future production may be affected by
exploration
success,
start-up
timing
and success, facility reliability, reservoir
performance and natural decline rates, water
handling and drilling progress, restrictions
on ability to access necessary infrastructure,
equipment and services, including but not
limited to, those sourced from third party
providers.
Capital expenditures may be
affected by cost pressures associated
with new capital projects, including labour
and material supply, project management,
drilling rig rates and availability and seismic
costs. Risk factors are discussed in greater
detail in filings made by OPCL with Canadian
securities commissions.
Any forward-looking information concerning
prospective exploration, results of operations,
financial position, production, expectations
of capital expenditures, cash flows and future
cash flows or other information described
above that is based upon assumptions
about future results, economic conditions
and courses of action are presented for the
purpose of providing readers with a more
complete perspective on Oryx Petroleum’s
present and planned future operations and
such information may not be appropriate for
other purposes and actual results may differ
Reserves and Resource
Advisory
materially from those anticipated in such
forward-looking information. In addition,
included herein is information that may be
considered financial outlook and/or futureoriented financial information. Its purpose
is to indicate the potential results of Oryx
Petroleum’s intentions and may not be
appropriate for other purposes.
Readers are strongly cautioned that the
above list of factors affecting forward-looking
information is not exhaustive. Although OPCL
believes that the expectations conveyed
by the forward-looking information are
reasonable based on information available
to it on the date such forward-looking
information was made, no assurances can
be given as to future results, levels of activity
and achievements. Readers should not place
undue importance or reliance on the forwardlooking information and should not rely on
the forward-looking information as of any
date other than the date hereof. Further,
statements
including
forward-looking
information are made as at the date they are
given and, except as required by applicable
law, Oryx Petroleum does not intend, and
does not assume any obligation, to update
any forward-looking information, whether as
a result of new information or otherwise. If
OPCL does update one or more statements
containing forward-looking information, it is
not obligated to, and no inference should be
drawn that it will make additional updates
with respect thereto or with respect to
other forward-looking information.
The
forward-looking information contained in
this MD&A is expressly qualified by this
cautionary statement.
Oryx Petroleum’s reserves and resource
estimates have been prepared and evaluated
in accordance with National Instrument 51101 - Standards of Disclosure for Oil and
Gas Activities and the Canadian Oil and Gas
Evaluation Handbook.
Proved oil reserves are those reserves which
are most certain to be recovered. There is at
least a 90% probability that the quantities
estimated proved oil reserves. Probable
oil reserves are those additional reserves
that are less certain to be recovered than
proved oil reserves. There is at least a 50%
probability that the quantities actually
recovered will equal or exceed the sum
of the estimated proved plus probable oil
reserves. Possible oil reserves are those
additional reserves that are less certain to
be recovered than probable oil reserves.
There is a 10% probability that the quantities
sum of proved plus probable plus possible
oil reserves.
Contingent oil resources are those quantities
of petroleum estimated, as of a given date,
to be potentially recoverable from known
accumulations using established technology
or technology under development, but
which are not currently considered to be
commercially recoverable due to one or
more contingencies. Contingencies may
include factors such as economic, legal,
environmental, political, and regulatory
matters, or a lack of markets. Contingent
oil resources entail additional commercial
risk than reserves and adjustments for
commercial risks have not been incorporated
in the summaries of contingent oil set forth
in this news release. There is no certainty
that it will be commercially viable to produce
any portion of the contingent oil resources.
Moreover, the volumes of contingent oil
resources reported herein are sensitive to
economic assumptions, including capital and
operating costs and commodity pricing.
Prospective oil resources are those quantities
of petroleum estimated, as of a given date, to
be potentially recoverable from undiscovered
accumulations by application of future
development projects. Prospective oil
resources have both a chance of discovery
and a chance of development. Prospective
oil resources entail more commercial and
exploration risks than those relating to oil
reserves and contingent resources. There
is no certainty that any portion of the
prospective resources will be discovered. If
discovered, there is no certainty that it will be
commercially viable to produce any portion of
the prospective resources.
Use of the word “gross” to qualify a reference
to reserves or resources means, in respect
of such reserves or resources, the total
reserves or resources prior to the deductions
specified in the production sharing contract,
risk exploration contract or fiscal regime
applicable to each license area.
47
48
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2013
Table of Contents
50
51
52
53
54
55
Independent auditor’s report to the members of Oryx Petroleum Corporation Limited
Consolidated statement of comprehensive income
Consolidated statement of financial position
Consolidated statement of changes in equity
Consolidated statement of cash flows
Notes to the consolidated financial statements
49
INDEPENDENT AUDITOR’S REPORT
To the Shareholders of Oryx Petroleum Corporation Limited
We have audited the accompanying consolidated financial statements of Oryx Petroleum Corporation Limited, which comprise the consolidated
statement of financial position as at December 31, 2013 and 2012, and the consolidated statement of comprehensive income, consolidated
statement of changes in equity and consolidated statement of cash flows for the years then ended, and a summary of significant accounting
policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International
Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated
financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance
with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform
the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements.
The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated
financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the
entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in
the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes
evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as
evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Oryx Petroleum Corporation
Limited as at December 31, 2013 and 2012, and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Signed by Deloitte SA
Chris Jones
Will Eversden
Geneva, Switzerland March 12, 2014
50
Consolidated Statement of Comprehensive Income
Note
Pre-licence costs
Depreciation and amortization expense
11
11, 12
32
Loss from operations
Interest (expense) / income - net
Foreign exchange gains / (losses)
7, 8
9
Finance income / (expense) - net
Income tax (expense) / benefit
Year ended
December 31
2013
$'000
Year ended
December 31
2012
$'000
(restated)
(40,131)
(6,383)
(82,948)
(728)
(56,887)
(22,612)
(6,608)
(29,017)
(361)
-
(187,077)
(58,598)
(60)
2,633
89
(231)
2,573
(142)
(184,504)
10
Net loss for the year
(1,319)
(58,740)
203
(185,823)
(58,537)
(1,424)
(2,542)
(187,247)
(61,079)
(185,564)
(259)
(58,359)
(178)
(185,823)
(58,537)
(186,988)
(259)
(60,901)
(178)
(187,247)
(61,079)
(2.04)
(2.10)
Other comprehensive loss, net of income tax
(items that will not be subsequently reclassified to profit and loss)
Remeasurement of the defined benefit obligation
27
Total comprehensive loss for the year
Net loss for the year attributable to:
Owners of the company
28
Total comprehensive loss attributable to:
Loss per share (basic and diluted)
28
23
51
Consolidated Statement of Financial Position
Note
December 31
2013
$'000
December 31
2012
$'000
(restated)
Non-current assets
Intangible assets
Property, plant and equipment
Deferred tax assets
11
12
17
200,720
443,824
911
479,162
575
870
645,455
480,607
12,465
6,606
5,652
306,034
5,601
12,361
4,971
72,725
330,757
95,658
976,212
576,265
138,608
463
-
83,121
870
7,781
139,071
91,772
66,271
3,492
1,346
37,687
2,469
-
71,109
40,156
210,180
131,928
1,009,684
5,186
(3,966)
(261,585)
499,311
771
5,846
(2,542)
(84,371)
749,319
419,015
16,713
25,322
Total equity
766,032
444,337
Total equity and liabilities
976,212
576,265
Current assets
Inventories
Trade and other receivables
Prepaid charges
Cash and cash equivalents
13
14
15
16
Total assets
Current liabilities
Current income tax liabilities
Borrowings
18
19
21
Non-current liabilities
Retirement benefit obligation
Decommissioning obligation
18
27
20
Total liabilities
Equity
Share capital
Share premium
Other reserves
Accumulated deficit
22
22
24
27
Equity attributable to owners of the company
28
The financial statements were approved by the Board of Directors and authorized for issue on March 12, 2014.
They were signed on behalf of the Board of Directors by
52
(signed)
(signed)
Jean Claude Gandur
Director
Peter Newman
Director
Consolidated Statement of Changes in Equity
Attributable to equity holders of the company
Note
Balance at January 1, 2012
Shares issued
Share based payment expense
Shares issued for long-term incentive plan
22
26
26
27
Balance at December 31, 2012 (restated)
Shares issued prior to initial public offering
Shares issued through initial public offering
Issuance costs
Warrants exercised
Shares issued for long-term incentive plan
Shares issued for Directors' compensation
Increase in participating interest in subsidiary(1)
Balance at December 31, 2013(2)
22
22
26
26
26
26
26
27
Remeasurement of
defined
Accumulated
benefit
deficit
obligation
$'000
$'000
Total
$'000
Noncontrolling
interests
$'000
Total
equity
$'000
-
81,726
25,500
107,226
(58,359)
-
(2,542)
(58,359)
394,929
11,729
(8,468)
(2,542)
(178)
-
(58,537)
394,929
11,729
(8,468)
(2,542)
5,846
(84,371)
(2,542)
419,015
25,322
444,337
4,531
(5,302)
-
25,047
(25,533)
(174)
-
(185,564)
8,350
-
(185,564)
265,137
247,344
(16,838)
10,515
25,047
(22,263)
8,350
(259)
(8,350)
(185,823)
265,137
247,344
(16,838)
10,515
25,047
(22,263)
-
-
-
-
-
(1,424)
(1,424)
-
(1,424)
1,009,684
-
5,186
(261,585)
(3,966)
749,319
16,713
766,032
Share
capital
$'000
Share
premium
$'000
Other
reserves
$'000
105,153
-
2,585
(26,012)
394,158
-
771
-
11,729
(8,468)
-
499,311
771
260,606
247,344
(11,536)
10,515
3,270
174
-
1. During the fourth quarter of 2013, Oryx Petroleum Middle East Ltd increased its participating interest in KPA Western Desert Energy Ltd to
66.67% from 50% (Note 28).
2. All outstanding shares of Oryx Petroleum Holdings PLC (“OPHP”) were acquired by Oryx Petroleum Corporation Limited (“OPCL”) immediately
prior to the closing date of the initial public offering in exchange for new shares in OPCL. All share capital balances prior to May 15, 2013 relate
to shares held by OPHP.
53
Consolidated Statement of Cash Flows
Year ended
December 31
2013
$'000
Year ended
December 31
2012
$'000
(restated)
(9,148)
(1,768)
2,184
(23,715)
(130)
89
(8,732)
(23,756)
Acquisition of property, plant and equipment
Acquisition of intangible assets
(10,710)
(223,369)
(633)
(92,267)
Net cash used in investing activities
(234,079)
(92,900)
Proceeds from issuance of ordinary shares
Proceeds from issuance of convertible loan notes
Proceeds from borrowings
Share issuance costs
492,959
(16,838)
251
284
163,565
-
Net cash generated from financing activities
476,121
164,100
Net increase in cash and cash equivalents
233,309
47,444
72,725
25,281
306,034
72,725
Note
Cash flows from operating activities
Net cash used in operations
Income tax paid
Interest received
25
Net cash used in operating activities
Cash flows from investing activities
Cash flows from financing activities
Cash and cash equivalents at beginning of the year
Cash and cash equivalents at end of the year
16
NOTES
TO THE FINANCIAL STATEMENTS
1. General information
Oryx Petroleum Corporation Limited (‘the Company’) is a public company incorporated in Canada under the Canada Business Corporation Act on
December 31, 2012, and is the holding company for the Oryx Petroleum Group of companies (together “the Group”). The address of the registered
office of Oryx Petroleum Corporation Limited is 3400 First Canadian Centre 350, 7th Avenue Southwest, Calgary, Alberta, Canada T2J 2M2. The
Group’s indirect majority shareholder is The Addax and Oryx Group Ltd (“AOG”) (incorporated in Malta). The majority of AOG’s outstanding shares
are owned by Samsufi Trust, an irrevocable discretionary charitable trust created at the suggestion of Jean Claude Gandur. Mr. Gandur is not one
of the beneficiaries of the Samsufi Trust. The Group’s principal activities are to acquire and develop exploration and production assets in order to
produce hydrocarbons and to increase oil and gas reserves.
On May 5, 2013, Oryx Petroleum Corporation Limited announced the filing of a supplemented PREP prospectus with the securities regulatory
authorities in each of the provinces of Canada, other than Quebec, in connection with its initial public offering of 16,700,000 common shares, at a
price of CAD$15.00 per common share (the “IPO”) for total gross proceeds of CAD$250.5 million ($249.4 million). The IPO closed on May 15, 2013.
Immediately prior to closing the IPO, a corporate restructuring occurred whereby Oryx Petroleum Corporation Limited became the parent company
of Oryx Petroleum Holdings PLC (OPHP) (formerly Oryx Petroleum Company PLC and Oryx Petroleum Company Limited). Although the consolidated
financial information has been released in the name of the parent, Oryx Petroleum Corporation Limited, it represents an in-substance continuation
of the pre-existing Group, headed by OPHP and the following accounting treatment has been applied to account for the restructuring:
•
the consolidated assets and liabilities of the subsidiary OPHP were recognised and measured at the pre-restructuring carrying amounts,
without restatement to fair value;
•
the retained earnings and other equity balances recognised in the consolidated statement of financial position reflect the consolidated
retained earnings and other equity balances of OPHP, as at May 9, immediately prior to the restructuring, and the results of the period from
January 1, 2013 to May 9, 2013, the date of the restructuring, are those of OPHP as the Company was not active prior to the restructuring.
Subsequent to the restructuring, the equity structure reflects the applicable movements in equity of Oryx Petroleum Corporation Limited.
•
Comparative numbers presented in the consolidated financial statements are those of OPHP, except for the per-share amounts, which have
been restated to reflect the change in the nominal value of the common shares resulting from the restructuring as if the Company had been
the parent company during such periods.
The consolidated financial statements were authorised for issue by the Board of Directors on March 12, 2014.
54
2. Summary of significant accounting policies
a.
Basis of preparation
The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the
International Accounting Standards Board (IASB) and the IFRS Interpretations Committee (IFRIC).
The consolidated financial statements have been prepared under the historical cost convention, as modified by the revaluation of financial assets
and liabilities (including derivative instruments) at fair value through profit and loss.
The preparation of financial statements in conformity with IFRS, requires the use of critical accounting estimates. It also requires management
to exercise its judgment in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgment or complexity,
or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in Note 4: Critical accounting
estimates and judgments. These estimates are based on management’s best knowledge of current events and actions; actual results ultimately
may differ from those estimates.
New and amended standards adopted by the Group
The Group has adopted all of the new and revised standards and interpretations issued by the IASB and IFRIC that are relevant to its operations
and effective for accounting periods beginning on or after January 1, 2013 as follows:
Amendments to Standards
IFRS 10
Consolidated financial statements
IFRS 11
Joint arrangements
IFRS 12
Disclosure of interests in other entities
IAS 1
Presentation of financial statements
IAS 27 (2011) Separate financial statements
IAS 28 (2011) Investments in associates and joint ventures
IFRS 13
Fair value measurement
IAS 19 (2011) Employee Benefits
IFRS 7 Financial Instruments: Disclosures
Effective for annual periods beginning on or after
January 1, 2013
January 1, 2013
January 1, 2013
January 1, 2013
January 1, 2013
January 1, 2013
January 1, 2013
January 1, 2013
January 1, 2013
The above new or amended standards and interpretations do not have a material impact for the Group, other than to enhance certain disclosures,
except for the adoption of IAS 19 (2011) Employee Benefits.
At the date of authorisation of these financial statements, the following new or further amended standards and interpretations applicable to the
Group were issued but not yet effective:
New and Amended Standards
Financial Instruments: Presentation (Offsetting)
IAS 32 IAS 36
Impairment of Assets (Disclosures re non-financial assets)
IFRS 10, IFRS 12 and IAS 27
Consolidated Financial Statements (Investment entities)
IFRS 9 Financial Instruments: classification and measurement
Additions to IFRS 9 for financial liability accounting
Effective for annual periods beginning on or after
January 1, 2014
January 1, 2014
January 1, 2014
January 1, 2015
January 1, 2015
Management has considered the impact of these additional new or further amended standards and interpretations but do not anticipate that their
adoption in future periods will have a material impact on the financial statements of the Group.
In the current year, the Group has applied IAS 19 Employee Benefits (as revised in 2011) and the related consequential amendments for the first
time. The impact on accumulated deficit at January 1, 2012 was an increase of $24 thousand and an increase of $3.6 million in restating the
previously reported total comprehensive loss for 2012. The elements of this application are detailed as follows:
55
Impact on total comprehensive loss for the year of the
application of IAS 19 (as revised in 2011)
Year ended
Year ended
December 31
December 31
2013
2012
$'000
$'000
(restated)
Impact on loss for the year
(411)
(1,482)
(72)
(75)
(168)
501
Increase in loss for the year
(651)
(1,056)
(1,424)
(2,542)
Foreign exchange losses
Impact on other comprehensive loss for the year
-
-
Increase in other comprehensive loss for the year
(1,424)
(2,542)
Increase in total comprehensive loss for the year
(2,075)
(3,598)
(651)
(1,056)
-
-
(2,075)
(3,598)
-
-
December 31
IAS 19
December 31
2012
adjustments
2012
$'000
$'000
$'000
Net loss attributable to:
Total comprehensive loss attributable to:
Impact on assets, liabilities and equity as at December 31 2012
for the application of IAS 19 (as revised in 2011)
(restated)
Retirement benefit asset / (obligation)
Prepaid charges
Deferred tax assets
67
(2,536)
(2,469)
6,534
(1,563)
4,971
369
Total effect on net assets
Accumulated deficit
Total effect on equity
56
501
870
(3,598)
(83,315)
(2,542)
(2,542)
(1,056)
(84,371)
(3,598)
Impact on assets, liabilities and equity as at December 31, 2013
for the application of IAS 19 (as revised in 2011)
IAS 19 Adjustments
$'000
Retirement benefit obligation
(1,995)
Prepaid charges
(4,011)
Deferred tax assets
333
Total effect on net assets
(5,673)
(3,966)
Accumulated deficit
(1,707)
Total effect on equity
(5,673)
b. Going concern
The Group presently meets its day to day
working capital requirements, and funds its
current and planned exploration projects
through the funding received from the IPO and
the balance of equity funding from AOG and
other investors that is remaining.
Prior to the IPO, the Group met its day to day
working capital requirements through $723
million in equity funding provided by AOG and
other investors.
The Group has no debt and a considerable
degree of control over both the extent and
timing of expenditure under its future capital
investment program.
The directors have a reasonable expectation
that the Company and the Group have
adequate resources to continue in operational
existence for the foreseeable future and,
therefore, continue to adopt the going
concern basis in preparing the consolidated
financial statements.
Notes 3.1 and 3.2 of the consolidated financial
statements set out the Group’s objectives,
policies and processes for managing its
capital; its financial risk management
objectives; and its exposure to credit risk and
liquidity risk.
c.Consolidation
i.Subsidiaries
Subsidiaries are all entities (including special
purpose entities) over which the Group has
obtained control. Control is achieved when
the Company has power over the investee,
is exposed, or has rights, to variable returns
from its involvement with the investee and
has the ability to use its power to affect its
returns. The Group also assesses existence of
control where it does not have more than one
half of the voting power but is able to govern
the financial and operating policies by virtue
of de-facto control. De-facto control may
arise in circumstances where the size of the
Group’s voting rights relative to the size and
dispersion of holdings of other shareholders
give the Group the power to govern the
financial and operating policies.
Subsidiaries are fully consolidated from the
date on which control is transferred to the
Group. They are deconsolidated from the date
that control ceases.
The Group applies the acquisition method
to account for business combinations. The
consideration transferred for the acquisition
of a subsidiary is the fair value of the assets
transferred, the liabilities incurred to the
former owners of the acquiree and the
equity interests issued by the Group. The
consideration transferred includes the fair
value of any asset or liability resulting from
a contingent consideration arrangement.
Identifiable assets acquired and liabilities
and contingent liabilities assumed in a
business combination are measured initially
at the fair values at the acquisition date.
The Group recognises any non-controlling
interest in the acquiree on an acquisition-byacquisition basis, either at fair value or at the
non-controlling interest’s proportionate share
of the recognised amounts of the acquiree’s
net assets.
If the business combination is achieved in
stages, the acquisition date fair value of the
acquirer’s previously held equity interest in
the acquiree is remeasured to fair value at the
acquisition date through profit or loss.
Any contingent consideration to be
transferred by the Group is recognised at fair
value at the acquisition date. Subsequent
changes to the fair value of the contingent
consideration that is deemed to be an asset
or liability is recognised in profit or loss.
Goodwill is initially measured as the excess
of the aggregate of the consideration
transferred and the fair value of the noncontrolling interest over the net identifiable
assets acquired and liabilities assumed. If
the consideration is lower than the fair value
of the net assets of the subsidiary acquired,
the difference is recognised in profit or loss.
Inter-company
transactions,
balances,
income and expenses on transactions
between Group companies are eliminated.
Profits and losses resulting from intercompany transactions that are recognised in
assets are also eliminated.
ii. Changes in ownership interests in
subsidiaries without loss of control
Changes in the Group’s interests in
subsidiaries that do not result in a loss
of control are accounted for as equity
transactions – that is, as transactions with
the owners in their capacity as owners. The
carrying amounts of the Group’s interests and
the non-controlling interests are adjusted to
reflect the changes in their relative interests
in the subsidiaries. Any difference between
the amount by which the non-controlling
interests are adjusted and the fair value of
any consideration paid or received is recorded
directly in equity.
iii. Disposal of subsidiaries
When the Group ceases to have control, any
retained interest in the entity is remeasured
to its fair value at the date when control is
lost, with the change in carrying amount
recognised in profit or loss. The fair value is
the initial carrying amount for the purposes
of subsequently accounting for the retained
interest as an associate, joint venture or
financial asset. In addition, any amounts
previously recognised in other comprehensive
income in respect of that entity are accounted
for as if the Group had directly disposed of the
related assets or liabilities. This may mean
that amounts previously recognised in other
comprehensive income are reclassified to
profit or loss.
iv. Interest in joint operations
A joint operation is a joint arrangement
whereby the Group has rights to assets, and
obligations for the liabilities relating to the
arrangement. Where the Group undertakes its
activities under joint operation arrangements
directly, the Group’s proportionate share of
jointly controlled assets and any liabilities
incurred jointly with others are recognised in
the financial statements.
Liabilities and expenses incurred directly in
respect of interests in joint operations are
accounted for on an accrual basis. Income
from the sale or use of the Company’s share of
the output of joint operations and its share of
the joint operation expenses are recognised
when it is probable that the economic benefit
associated with the transactions will flow to/
from the Company and the amount can be
reliably measured.
d. Foreign currency translation
i.
Functional and presentation currency
Items included in the financial statements
of each of the Group’s entities are measured
using the currency of the primary economic
environment in which the entity operates
(the functional currency). The consolidated
financial statements are presented in US
Dollars (USD), which is the functional and
presentation currency of the Company and
the presentation currency of the Group.
57
ii. Transactions and balances
Foreign currency transactions are translated
into the functional currency using the
exchange rates prevailing at the dates of the
transactions or valuation where these items
are remeasured. Foreign exchange gains
and losses resulting from the settlement of
such transactions and from the translation
at year-end exchange rates of monetary
assets and liabilities denominated in foreign
currencies are recognised in the statement
of comprehensive income, except when
deferred in other comprehensive income as
qualifying cash flow hedges and qualifying
net investment hedges.
Changes in the fair value of monetary
securities denominated in foreign currency
classified as available-for-sale are analysed
between translation differences resulting
from changes in the amortised cost of
the security, and other changes in the
carrying amount of the security. Translation
differences are recognised in profit or loss,
and other changes in carrying amount are
recognised in other comprehensive income.
Translation differences on non-monetary
financial assets and liabilities such as
equities held at fair value through profit or
loss are recognised in profit or loss as part
of the fair value gain or loss. Translation
differences on non-monetary financial assets
such as equities classified as available-forsale, are included in other comprehensive
income.
iii. Group companies
The results and financial position of all
the Group entities (none of which has the
currency of a hyper-inflationary economy)
that have a functional currency different from
the presentation currency are translated into
the presentation currency as follows:
•
assets and liabilities are translated
at the closing rate at the end of each
reporting period;
•
income and expenses 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); and
•
all resulting exchange differences are
recognised in other comprehensive
income.
Goodwill and fair value adjustments arising on
the acquisition of a foreign entity are treated
as assets and liabilities of the foreign entity
and translated at the closing exchange rate.
e. Exploration and evaluation assets and
property, plant and equipment
i.Cost
Oil and gas properties and other property,
plant and equipment are recorded at cost
including expenditures which are directly
attributable to the purchase or development
of an asset.
ii. Exploration and evaluation (“E&E”) costs
Exploration and evaluation costs incurred
following the acquisition of a license are
initially capitalised as intangible E&E assets.
Payments to acquire the legal rights to explore,
costs of technical work, seismic acquisition,
education and training fund, production
58
sharing contract costs, exploratory and
appraisal drilling, general technical support
and directly attributable administrative and
overhead costs are capitalised as E&E assets.
E&E costs are not amortised prior to the
conclusion of appraisal activities.
E&E assets related to each exploration
license/prospect are carried forward until
the existence (or otherwise) of commercial
reserves has been determined subject to
certain limitations including review for
impairment. If commercial reserves have
been discovered, the carrying value, less any
impairment loss, of the relevant E&E assets
is then reclassified to property, plant and
equipment. If, however, commercial reserves
have not been found, the related capitalised
costs are charged to expense after conclusion
of appraisal activities.
Costs incurred prior to having obtained the
legal rights to explore an area are expensed in
the period in which they are incurred.
iii. Development costs
Expenditures on the construction, installation
and completion of infrastructure facilities and
drilling of development wells are capitalised
as oil and gas properties. Costs incurred to
operate and maintain wells and equipment to
lift oil and gas to the surface are expensed as
production and operating expenses.
iv. Other property, plant and equipment
Property, plant and equipment (PP&E)
assets are stated at historical cost, less
any accumulated depreciation and any
provision for impairment. Cost includes
expenditures that are directly attributable
to the acquisition of the assets. Subsequent
costs are included in the asset’s carrying
amount or recognised as a separate asset,
as appropriate, only when it is probable that
future economic benefits associated with
the item will flow to the Group and the cost
of the item can be measured reliably. Where
such subsequent expenditure is to replace
previously capitalised equipment, the
remaining carrying amount of the replaced
part is derecognised.
Repairs and maintenance are charged to
expense as incurred.
v. Depreciation and amortisation
All expenditure within each license area
is depleted from the commencement of
production on a unit of production basis,
which is the ratio of oil and gas production
in the period to the estimated quantities
of commercial reserves at the end of the
period plus the production in the period,
generally on a license area-by-license area
basis. Costs used in the unit of production
calculation comprise the net book value of
capitalised costs plus the estimated future
field development costs. Changes in the
estimates of commercial reserves are dealt
with prospectively.
Depreciation on other assets is calculated
using the straight-line method to allocate the
cost of each asset to its residual value over its
estimated useful life, as follows:
•
Fixtures and equipment: 3 - 5 years
•
Computer equipment: 3 years
reporting period.
An asset’s carrying amount is written down
immediately to its recoverable amount if the
asset’s carrying amount is greater than its
estimated recoverable amount.
Gains and losses on disposals are determined
by comparing proceeds with the carrying
amount. These are included in the statement
of comprehensive income as ‘Other income’ or
‘Other expense’.
vi. Intangible assets other than oil and gas
assets
Intangible assets, other than oil and gas
assets, have finite useful lives and are
measured at cost and amortised over their
expected useful economic lives on a straight
line basis as follows:
•
Computer software: 3 years
f. Impairment of non-financial assets
Assets that have an indefinite useful life, such
as goodwill or intangible assets not ready to
use, are not subject to amortisation and are
tested annually for impairment. Assets that
are subject to amortisation are reviewed for
impairment whenever events or changes in
circumstances indicate that the carrying
value may not be recoverable.
E&E assets are assessed for impairment
when facts and circumstances suggest
that the carrying amount may exceed its
recoverable amount. Such indicators include
but are not limited to:
•
the period for which the Group has the
right to explore in the specific area has
expired during the period or will expire in
the near future, and is not expected to be
renewed;
•
substantive expenditure on further
exploration for and evaluation of mineral
resources in the specific area is neither
budgeted or planned;
•
exploration for and evaluation of
resources in the specific area have not led
to the discovery of commercially viable
quantities of mineral resources and a
decision has been taken to discontinue
such activities in the specific area;
•
sufficient data exists to indicate that,
although a development in the specific
area is likely to proceed, the carrying
amount of the E&E asset is unlikely to
be recovered in full from successful
development or sale;
•
extended decreases in prices or margins
for oil & gas commodities or products;
•
a significant downwards revision in
estimated volumes of reserves or
resources or an upward revision in future
development costs.
For the purpose of impairment testing the
assets are aggregated in cash-generating
unit (CGU) cost pools based on their ability to
generate largely independent cash flows. An
impairment loss is recognised for the amount
by which the asset’s carrying amount exceeds
its recoverable amount. The recoverable
amount of a CGU is the greater of its fair
value less costs to sell and its value in use.
Non-financial assets other than goodwill
that suffered impairment are reviewed for
possible reversal at each reporting date.
g. Financial assets
Residual values and useful lives are reviewed,
and adjusted if appropriate, at the end of each
The Group classifies its financial assets in
the following categories: at fair value through
profit or loss, loans and receivables, and
available-for-sale. The classification depends
on the purpose for which the financial assets
were acquired. Management determines the
classification of its financial assets at initial
recognition.
i. Financial assets at fair value through
profit or loss
Financial assets at fair value through profit
or loss are financial assets held for trading.
A financial asset is classified in this category
if acquired principally for the purpose of
selling in the short term. Derivatives are also
categorised as ‘held for trading’ unless they
are designated as hedges.
ii. Loans and receivables
Loans and receivables are non-derivative
financial assets with fixed or determinable
payments that are not quoted in an active
market. They are included in current assets,
except for maturities greater than twelve
months after the end of the reporting period.
These are classified as non-current assets.
Loans and receivables are included in ‘Trade
and other receivables’ in the statement of
financial position.
iii. Available-for-sale financial assets
Available-for-sale financial assets are nonderivatives that are either designated in this
category or not classified in any of the other
categories. They are included in non-current
assets unless the investment matures or
management intends to dispose of it within
twelve months of the end of the reporting
period.
Regular purchases and sales of investments
are recognised on the trade-date – the date
on which the Group commits to purchase
or sell the asset. Investments are initially
recognised at fair value plus transaction
costs for all financial assets not carried at
fair value through profit or loss. Financial
assets carried at fair value through profit or
loss are initially recognised at fair value, and
transaction costs are expensed. Financial
assets are derecognised when the rights to
receive cash flows from the investments have
expired or have been transferred and the
Group has transferred substantially all risks
and rewards of ownership. Available-for-sale
financial assets and financial assets at fair
value through profit or loss are subsequently
carried at fair value. Loans and receivables
are subsequently carried at amortised cost
using the effective interest method.
Gains and losses arising from changes in the
fair value of the ‘financial assets at fair value
through profit or loss’ category are included
in the statement of comprehensive income in
the period in which they arise.
Changes in the fair value of monetary and
non-monetary securities classified as
‘available-for-sale’ are recognised in other
comprehensive income.
When securities classified as ‘available-forsale’ are sold or impaired, the accumulated
fair value adjustments recognised in
equity are included in the statement of
comprehensive income as part of ‘Other
income’. Dividends on available-for-sale
equity instruments are recognised in the
statement of comprehensive income as part
of ‘Other income’ when the Group’s right to
receive payments is established.
h. Offsetting financial instruments
Financial assets and liabilities are offset and
the net amount reported in the statement
of financial position when there is a legally
enforceable right to offset the recognised
amounts and there is an intention to settle on
a net basis or realise the asset and settle the
liability simultaneously.
i.
Impairment of financial assets
i.
Assets carried at amortised cost
The Group assesses at the end of each
reporting period whether there is objective
evidence that a financial asset or group of
financial assets is impaired. A financial asset
or a group of financial assets is impaired and
impairment losses are incurred only if there is
objective evidence of impairment as a result
of one or more events that occurred after the
initial recognition of the asset (a ‘loss event’)
and that loss event (or events) has an impact
on the estimated future cash flows of the
financial asset or group of financial assets
that can be reliably estimated.
Evidence of impairment may include
indications that the debtors or a group of
debtors is experiencing significant financial
difficulty, default or delinquency in interest
or principal payments, the probability that
they will enter bankruptcy or other financial
reorganisation, and where observable data
indicate that there is a measurable decrease
in the estimated future cash flows, such as
changes in arrears or economic conditions
that correlate with defaults.
For loans and receivables category, the amount
of the loss is measured as the difference
between the asset’s carrying amount and the
present value of estimated future cash flows
(excluding future credit losses that have not
been incurred) discounted at the financial
asset’s original effective interest rate. The
carrying amount of the asset is reduced and
the amount of the loss is recognised in the
statement of comprehensive income. If a
loan or held-to-maturity investment has a
variable interest rate, the discount rate for
measuring any impairment loss is the current
effective interest rate determined under the
contract. As a practical expedient, the Group
may measure impairment on the basis of an
instrument’s fair value using an observable
market price.
If, in a subsequent period, the amount of the
impairment loss decreases and the decrease
can be related objectively to an event occurring
after the impairment was recognised (such as
an improvement in the debtor’s credit rating),
the reversal of the previously recognised
impairment loss is recognised in the
less any impairment loss on that financial
asset previously recognised in profit or loss,
is removed from equity and recognised in
profit or loss. Impairment losses recognised
on equity instruments in the statement of
comprehensive income are not reversed
through the statement of comprehensive
income. If, in a subsequent period, the fair
value of a debt instrument classified as
available-for-sale increases and the increase
can be objectively related to an event
occurring after the impairment loss was
recognised in profit or loss, the impairment
loss is reversed through the statement of
comprehensive income.
j.Inventories
Inventories relating to materials acquired
for use in exploration activities are stated
at the lower of cost and net realisable value.
Net realisable value is the estimated selling
price in the ordinary course of business, less
estimated costs of completion and estimated
costs necessary to make the sale. The cost of
inventories comprises all costs of purchase,
costs of conversion and other costs incurred
in bringing the inventories to their present
location and condition.
k. Trade and other receivables
Trade and other receivables are recognised
initially at fair value and subsequently
measured at amortised cost using the
effective interest method, less 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 the receivables.
l.
Cash and cash equivalents includes cash in
hand, deposits held at call with banks, and
other highly liquid investments with original
maturities of three months or less. Bank
overdrafts are shown within borrowings in
current liabilities.
m.Borrowings
Borrowings are recognised initially at fair
value, net of transaction costs incurred.
Borrowings are subsequently carried at
amortised cost; any difference between
the proceeds (net of transaction costs) and
the redemption value is recognised in the
statement of comprehensive income over the
period of the borrowings using the effective
interest method.
Borrowings are classified as current liabilities
unless the Group has an unconditional right
to defer settlement of the liability for at least
twelve months after the end of the reporting
period.
ii. Assets classified as available-for-sale
n. Compound financial instruments
The Group assesses at the end of each
reporting period whether there is objective
evidence that a financial asset or a group
of financial assets is impaired. For debt
securities, the Group uses the criteria
referred to in (i) above. In the case of equity
investments classified as available-for-sale,
a significant or prolonged decline in the fair
value of the security below its cost is also
evidence that the assets are impaired. If any
such evidence exists for available-for-sale
financial assets, the cumulative loss, which
is measured as the difference between the
acquisition cost and the current fair value,
Compound financial instruments issued by
the Group comprise convertible notes that
can be converted to share capital at the
option of the directors of the Company, and
the number of shares to be issued does not
vary with changes in their fair value.
The liability component of a compound
financial instrument is recognised initially at
the fair value of a similar liability that does
not have an equity conversion option. The
equity component is recognised initially at
the difference between the fair value of the
compound financial instrument as a whole
59
and the fair value of the liability component.
Any directly attributable transaction costs
are allocated to the liability and equity
components in proportion to their initial
carrying amounts.
Subsequent to initial recognition, the
liability component of a compound financial
instrument is measured at amortised cost
using the effective interest method. The
equity component of a compound financial
instrument is not re-measured subsequent
to initial recognition except on conversion or
expiry.
Compound
financial
instruments
are
classified as current liabilities unless the
Group has an unconditional right to defer
settlement of the liability for at least twelve
months after the end of the reporting period.
o.Taxation
The tax expense for the period represents
tax currently payable and deferred tax. Tax is
recognised in the statement of comprehensive
income, except to the extent that it relates
to items recognised in other comprehensive
income or directly in equity. In this case, the
tax is also recognised in other comprehensive
income or directly in equity, respectively.
The current income tax charge is calculated
on the basis of the tax laws enacted or
substantively enacted at the end of the
reporting period in the countries where the
Group’s subsidiaries operate and generate
taxable income. Management periodically
evaluates positions taken in tax returns with
respect to situations in which applicable tax
regulation is subject to interpretation and
establishes provisions where appropriate on
the basis of amounts expected to be paid to
the tax authorities.
Deferred income tax is the tax recognised in
respect of temporary differences between
the carrying amounts of assets and
liabilities in the financial statements and the
corresponding tax bases and is accounted
for using the balance sheet liability method.
Deferred income tax liabilities are generally
recognised for all taxable temporary
differences and deferred income tax assets
are recognised to the extent that it is probable
that taxable profits will be available against
which deductible temporary differences
can be utilised. Deferred income tax is not
recorded if it arises from the initial recognition
of an asset or liability in a transaction other
than a business combination that, at the
time of the transaction, affects neither the
accounting profit nor loss.
Deferred income tax liabilities are recognised
for taxable temporary differences arising on
investments in subsidiaries and associates
and interests in joint ventures except where
the Group is able to control the reversal of the
temporary difference and it is probable that
the temporary difference will not reverse in
the foreseeable future.
The carrying amount of deferred tax assets is
reviewed at the end of each reporting period
and reduced to the extent that it is no longer
probable that sufficient taxable profits will be
available to allow all or part of the asset to be
recovered.
Deferred income tax is calculated at the tax
rates that are expected to apply in the year
60
when the deferred tax liability is settled or the
asset is realised. Deferred tax is charged or
credited in the statement of comprehensive
income except when it relates to items
charged or credited directly to equity in which
case the deferred tax is also recognised
directly in equity. Deferred tax assets and
liabilities are offset when there is a legally
enforceable right to offset current tax assets
against current tax liabilities and when they
relate to income taxes levied by the same
taxation authority and the Group intends to
settle its current tax assets and liabilities on
a net basis.
p. Employee benefits
i.
Pension obligations
The Group operates two defined benefit
pension plans. Typically defined benefit plans
define an amount of pension benefit that an
employee will receive on retirement, usually
dependent on one or more factors such as
age, years of service and compensation. The
Group’s Swiss pension plans are accounted
for as defined benefit schemes in accordance
with the requirements of IFRS. The pension
assets within these Swiss plans consist
entirely of investments held by the insurance
company that fully reinsures the Group’s
pension liabilities.
The liability recognised in the statement
of financial position in respect of defined
benefit pension plans is the present value
of the defined benefit obligation at the end
of the reporting period less the fair value of
plan assets. The defined benefit obligation is
calculated annually by independent actuaries
using the projected unit credit method.
The present value of the defined benefit
obligation is determined by discounting the
estimated future cash outflows using interest
rates of high quality corporate bonds that are
denominated in the currency in which the
benefits will be paid, and that have terms to
maturity approximating to the terms of the
related pension obligation.
The retirement benefit obligation recognised
in the consolidated statement of financial
position represents the actual deficit or
surplus in the Group’s defined benefit plans.
Any surplus resulting from this calculation is
limited to the present value of any economic
benefits available in the form of refunds
from the plans or reductions in the future
contributions to the plans.
ii. Share-based compensation
The Group issues equity-settled sharebased payments to employees under a Long
Term Incentive Plan (LTIP). Such payments
are measured at the fair value of the equity
instruments at the grant date. The fair value
excludes the effect of any service and nonmarket performance vesting conditions.
The fair value of equity-settled share-based
payments determined at the grant date is
expensed on a straight-line basis over the
vesting period, based on the Group’s estimate
of equity instruments that will eventually vest.
At the end of each reporting period, the Group
revises its estimate of the number of equity
instruments expected to vest as a result of
the effect of non-market vesting conditions.
The impact of the revision of the original
estimates, if any, is recognised in profit or loss
such that the cumulative expense reflects
the revised estimate, with a corresponding
adjustment to equity.
q. Trade and other payables
Liabilities for trade and other amounts
payable are stated initially at their fair value
and subsequently at amortised cost using the
effective interest method.
r.Provisions
Provisions are recognised when the Group
has a present legal or constructive obligation
as a result of past events, it is probable that
an outflow of resources will be required to
settle the obligation and the amount can be
reliably estimated. Provisions are measured
at the present value of management’s best
estimate of the expenditure required to settle
the present obligation at the reporting date
and are discounted to present value where
the effect is material.
Provisions for decommissioning costs
represent management’s best estimate of
the Group’s liability for restoring the sites
of drilled wells to their original status,
discounted where the effect is material. A
decommissioning asset is also established,
since the future cost of decommissioning
is regarded as part of the total investment
to gain access to future economic benefits.
The amount recognised is reassessed each
reporting period in accordance with local
conditions and requirements. Changes in the
estimated timing or cost of decommissioning
are dealt with prospectively. The unwinding
of any discount on the decommissioning
provision is included as a finance cost.
s. Interest income
Interest income is recognised using the
effective interest method. When a loan or
receivable is impaired, the Group reduces
the carrying amount to its recoverable
amount, being the estimated future cash flow
discounted at original effective interest rate
of the instrument, and continues unwinding
the discount as interest income. Interest
income on impaired loans and receivables
is recognised using the original effective
interest rate.
t.Leases
Leases where the lessor retains substantially
all the risks and rewards of ownership are
classified as operating leases. Payments
made under operating leases (net of any
incentives received from the lessor) are
charged to the statement of comprehensive
income on a straight-line basis over the
period of the lease.
Assets held under finance leases are initially
recognised as assets of the Group at their
fair value at the inception of the lease or, if
lower, at the present value of the minimum
lease payments. The corresponding liability
to the lessor is included in the consolidated
statement of financial position as a finance
lease obligation.
3. Financial risk management
3.1 Financial risk factors
The Group’s activities expose it to a variety
of financial risks: market risk (including
currency risk, fair value interest rate risk, cash
flow interest rate risk and price risk), credit
risk and liquidity risk. The Group’s overall
risk management objective is to decrease
volatility in earnings, financial position
and cash flow while securing effective and
competitive financing. In order to address
the impact of these risks, the Group has
developed various risk management policies
and strategies.
a. Market risk
i.
Foreign exchange risk
The Group operates internationally and has
foreign exchange risk arising from various
currency exposures. Foreign exchange risk
arises when future commercial transactions
or recognised assets and liabilities are
denominated in a currency that is not the
entity’s functional currency.
The Group’s reporting currency is the US Dollar;
being the currency in which the majority of
the Group’s expenditure is transacted. The
US Dollar is also the functional currency of
all Group companies. Less material elements
of general and administrative expenses are
transacted in other currencies. The majority of
balances are held in US Dollars with transfers
to Swiss Francs and other local currencies as
required to meet local needs.
A forward exchange contract was signed in
December 2012 to purchase 1,500,000 Swiss
Francs per month for the subsequent twelve
months. The contract was a zero cost collar
hedging instrument. The collar rates included
in the contract were 0.8805 CHF : 1 USD and
0.9660 CHF : 1 USD. Any gains or losses arising
from the application of the collar have been
charged to the statement of comprehensive
income. There were no forward exchange rate
contracts in place at December 31, 2013.
During 2013, if the Swiss Franc had
strengthened/weakened by 10% against
the US Dollar throughout the year with all
other variables held constant, the total
comprehensive loss for the year would have
been $2.9 million lower/ higher, mainly as the
result of Swiss Franc-denominated general
and administrative expenses and foreign
exchange gains/losses on the translation of
Swiss Franc-denominated monetary assets
and liabilities.
ii. Commodity price risk
The market prices for crude oil and natural
gas are subject to significant fluctuations
resulting from a variety of factors affecting
demand and supply globally. As the Group’s
activities are currently at exploration and
development stage, there is no sales revenue
and consequently no income statement
exposure to commodity price risk.
iii. Interest rate risk
The Group’s income and operating cash flows
are substantially independent of changes
in market interest rates with the exception
of interest income from bank deposits, with
variable interest rates which are exposed
to cash flow interest rate risk as market
rates change. The interest expense on the
contingent consideration (note 8) is also
exposed to interest rate risk as market rates
change. The funding provided by AOG and
others, prior to 2013, was interest-free and
converted into equity in September 2012 and
January 2013. The objective of the Group’s
interest rate risk management is to balance
the returns received on interest bearing
assets with an acceptable level of access to
those assets.
Based on the exposure to the interest rates for
cash and cash equivalents, and the interest
expense on the contingent consideration, at
the reporting date, a 0.5% rate increase or
decrease would not have a material impact
on the Group’s loss for the year. A change
in rate of 0.5% is used as it represents
management’s assessment of the reasonably
possible changes in interest rates.
b. Credit risk
Credit risk is managed on a Group basis. Credit
risk arises from cash and cash equivalents
and deposits with banks and financial
institutions, as well as credit exposures to
oil and gas property license partners and
customers, including outstanding receivables
and committed transactions. For cash
and cash equivalents, the Group invests in
products that are rated investment grade
and above. The credit risk on liquid funds is
assessed as limited because the counterparties are banks with good credit-ratings
assigned by international credit-rating
agencies.
The Group does not have any significant trade
or other receivables outstanding from any one
debtor at the reporting date.
Management does not believe that there
is significant exposure to credit risk on
receivables from related parties.
Where a Group company undertakes its
activities under joint venture arrangements,
its joint venture partners are obligated to
make cash contributions to fund joint venture
operations and have historically done so. The
balance of joint venture receivables (Note
14) arises from timing differences between
cash calls and the expenditure incurred on
behalf of joint venture partners. While there
is no “due date” for these receivables, based
on historical experience of funding through
regular cash calls with a limited group of
joint venture partners, management does not
believe that there is significant exposure to
credit risk on these receivables.
c. Liquidity risk
Prudent liquidity risk management implies
maintaining sufficient cash and marketable
securities and being able to secure sufficient
funding on a timely basis to meet capital
and operating expenditure obligations.
Management uses budgets and cash flow
models, which are regularly updated, to
monitor liquidity risk. The Group manages
liquidity risk through its corporate treasury
function using sources of financing from
other entities and investing excess liquidity.
The table below details the remaining
contractual maturity for non-derivative
financial liabilities of the Group. The amounts
disclosed in the table are the contractual
undiscounted cash flows.
61
Less than 1
year
$'000
Between 1 and
2 years
$'000
Between 2 and
5 years
$'000
Over 5 years
$'000
Borrowings
83,121
7,781
37,687
-
-
-
138,608
66,271
-
-
3.2 Capital risk management
The Group’s objectives when managing
capital are to safeguard the Group’s ability
to continue as a going concern in order to
provide returns for shareholders and benefits
for the other stakeholders and to maintain an
optimal capital structure to reduce the cost of
capital.
The capital structure of the Group consists of
issued capital and reserves less accumulated
deficits. There is no indebtedness. A
substantial proportion of net equity at the
reporting date is held as cash and cash
equivalents.
4. Critical accounting
and judgments
estimates
In the process of applying the Group’s
accounting policies management makes
estimates and assumptions concerning
the future. The resulting accounting
estimates will, by definition, seldom equal
the related actual results. The estimates
and assumptions for which ultimate actual
outcomes have a significant risk of causing a
material adjustment to the carrying amounts
of assets and liabilities are discussed below.
a. Carrying value of intangible exploration
and evaluation assets
The outcome of ongoing exploration, and
therefore whether the carrying value of
intangible exploration and evaluation assets
will ultimately be recovered, is inherently
uncertain. Management makes the judgments
necessary to implement the Group’s policy
with respect to exploration and evaluation
assets and considers these assets for
impairment at least annually with reference
to the indicators set out in IFRS 6.
Assets are aggregated into Cash Generating
Units (“CGUs”) for the purpose of calculating
impairment based on their ability to generate
largely independent cash flows and giving
consideration to the geography, geology,
production profile and infrastructure of
its assets. The allocation of assets into
CGUs requires significant judgment and
interpretations with respect to the integration
between assets, the existence of active
markets, similar exposure to market risks,
shared infrastructures and the way in which
management monitors the operations.
b. Acquisition of subsidiaries
Due to the inherently uncertain nature of
the oil and gas industry, the assumptions
underlying the fair values of identifiable
assets and liabilities of OP Hawler Kurdistan
Limited (formerly Norbest Limited) and KPA
Western Desert Energy Limited, which were
acquired on August 10, 2011 and December
21, 2011 respectively, and the probability of
exploration success that could result in paying
contingent consideration, and quantification
thereof, are judgemental in nature. Further
details on the measurement of the contingent
consideration are disclosed in Note 32.
c. Fair value
An assessment of fair value of assets and
liabilities is required in accounting for
derivative instruments and other items,
principally
available-for-sale
financial
assets and disclosures related to fair values
of financial assets and liabilities. In such
instances, fair value measurements are
estimated based on the amounts for which
62
the assets and liabilities could be exchanged
at the relevant transaction date or reporting
period end, and are therefore not necessarily
reflective of the likely cash flow upon actual
settlements. Where fair value measurements
cannot be derived from publicly available
information, they are estimated using models
and other valuation methods. To the extent
possible, the assumptions and inputs used
take into account externally verifiable inputs.
However, such information is by nature
subject to uncertainty, particularly where
comparable market based transactions may
not exist.
d. Pension benefits
The present value of the pension obligations
depends on a number of factors that are
determined on an actuarial basis using a
number of assumptions, as disclosed in Note
27. The assumptions used in determining
the net cost (income) for pensions include
the discount rate. Any changes in these
assumptions will impact the carrying amount
of pension obligations and the charge to the
e. Decommissioning obligation
The
decommissioning
obligation
is
calculated using the current estimated
costs to decommission the asset. Liabilities
for decommissioning are adjusted every
reporting period for changes in estimates.
Estimating the decommissioning obligation
requires significant judgment as restoration
technologies and costs are constantly
changing, as are regulatory, political,
environmental and safety considerations.
Inherent in the calculation of the obligation
are
numerous
assumptions
including
the ultimate settlement amounts, future
third-party pricing, inflation factors, risk
free discount rates, credit risk, timing
of settlement and changes in the legal,
regulatory and environmental and political
environments. Future revisions to these
assumptions may result in material
changes to the decommissioning obligation.
Adjustments to the estimated amounts
and timing of future decommissioning cash
flows are a regular occurrence in light of the
significant estimates and judgments involved.
5. Segment information
The Group has a single class of business which is to acquire, explore, develop and produce oil from oil and gas assets. The Group operates
in a number of geographical areas based on the location of operations and assets. The Group’s reporting segments comprise each separate
geographical area in which it operates.
Middle East
West Africa
Corporate
Total
$'000
$'000
$'000
$'000
(501)
(239)
(39,391)
(40,131)
For the year ended December 31, 2013
Pre-license costs
(960)
(5,423)
-
(6,383)
(43,992)
(38,956)
-
(82,948)
Depreciation and amortization
Segment result
-
(29)
(56,887)
(102,340)
(699)
(44,647)
(40,090)
Interest expense (net)
(184,504)
Income tax expense
(1,319)
Segment liabilities
(187,077)
2,633
Segment assets
(56,887)
(60)
Foreign exchange gains
Capital additions
(728)
(185,823)
154,686
91,709
2,087
248,482
645,708
Middle
East
(188,624)
$'000
242,905
West
Africa
(6,290)
$'000
87,599
Corporate
(15,266)
$'000
976,212
Total
(210,180)
$'000
(570)
(50)
(21,992)
(22,612)
(1,526)
(5,082)
-
(6,608)
(29,017)
-
-
(29,017)
For the year ended December 31, 2012 (restated)
Pre-license costs
Segment result
(31,113)
(1)
(360)
(361)
(5,133)
(22,352)
(58,598)
Interest income
89
Foreign exchange losses
(231)
(58,740)
Income tax benefit
203
Capital additions
Segment assets
Segment liabilities
(58,537)
91,601
44,623
485,348
74,382
(111,086)
(6,079)
1,175
137,399
16,535
576,265
(14,763)
(131,928)
63
6. Staff Costs
Year ended
Year ended
December 31
December 31
2013
2012
$'000
$'000
(restated)
Wages and salaries
22,407
9,749
Social security costs
2,959
1,186
24,852
11,569
2,603
1,091
455
311
53,276
23,906
Employee share awards
Pension costs
Other costs
A portion of the Group’s staff costs and associated overheads are recharged to the joint venture partners, expensed as pre-license expenditure or
capitalised where they are directly attributable to on-going capital projects. Amounts are stated gross of recharges.
The average number of employees of the Group (including Executive Directors) was:
Year ended
Year ended
December 31
December 31
2013
2012
(restated)
West Africa
4
2
Middle East
14
6
Geneva office
53
31
71
39
7. Interest income
Year ended
Year ended
December 31
December 31
2013
2012
$'000
$'000
(restated)
Bank interest
2,202
89
2,202
89
8. Interest expense
Year ended
Year ended
December 31
December 31
2013
2012
$'000
$'000
(restated)
Interest expense
(2,262)
-
(2,262)
-
Interest expense relates to accrued interest on contingent consideration arising from the acquisition of OP Hawler Kurdistan Ltd. (Note 32). The
acquisition terms included the payment of interest on additional consideration contingent upon the outcome of future drilling activities. Interest
is calculated at the rate of LIBOR plus 0.25% per annum, compounded on an annual basis.
64
9. Foreign exchange gains/losses
Year ended
Year ended
December 31
December 31
2013
2012
$'000
$'000
(restated)
Realized foreign exchange gains / (losses)
Unrealized foreign exchange losses
2,924
(291)
2,633
(49)
(182)
(231)
On May 9, 2013, the Group sold CAD$150 million and purchased $149.4 million at the forward rate of CAD$1.0043 per $1, with delivery on May 21,
2013. A foreign exchange gain of $3.1 million was realised on this transaction.
10. Income tax expense
Year ended
Year ended
December 31
December 31
2013
2012
$'000
$'000
(restated)
Current tax:
Current income tax expense
Adjustments in respect of prior years
Total current income tax
(1,321)
(40)
(1,361)
(797)
130
(667)
Deferred tax:
Deferred tax on long-term incentive plan
(91)
369
Deferred tax on defined benefit obligation
133
501
42
870
Total deferred tax
(1,319)
203
The Group is subject to income taxes in certain territories in which it owns licenses or has taxable operations. The current income tax expense
relates to tax on profit from operations of the Group’s Swiss and Maltese subsidiaries.
The deferred tax represents tax on unvested shares issued for the long-term incentive plan and on defined benefit obligations following the
adoption of the amendments to IAS 19 – Employee Benefits.
65
10. Income tax expense (continued)
The charge for the year can be reconciled to the loss per the statement of comprehensive income as follows:
Year ended
Year ended
December 31
December 31
2013
2012
$'000
$'000
(restated)
Combined Canadian federal and provincial
income tax credit at the statutory rate / Maltese rate*
Effect of income exempt from taxation
Effect of unused tax losses unrecognized
in deferred tax assets
(184,504)
(58,740)
50,817
20,559
4,761
5,527
(11,111)
Utlization of previously unrecognized tax losses
-
Effect of tax rates of subsidiaries operating
in other jurisdictions
Effect of non-deductible expenses
(378)
4,457
(117)
(229)
(45,669)
(29,733)
(1,319)
203
* The tax expense for the nine months ended December 31, 2013 was calculated using the combined Canadian federal and provincial tax rates,
being 25%. The tax expense for the three months ended March 31, 2013 and the year ended December 31, 2012 was calculated using the Maltese
tax rate, being 35%.
Deferred tax assets have been recognised for unvested amounts relating to the long-term incentive plan of the Group’s Maltese subsidiary and
defined benefit obligations relating to the Group’s Swiss subsidiary. No other deferred tax assets have been recognised for the benefit of tax
deductions and tax losses because realisation of the deferred tax assets in the foreseeable future is not sufficiently probable.
Cumulative unused tax losses unrecognised in deferred tax assets amount to $50.1 million at December 31, 2013 (December 31, 2012: $5.4 million
(restated)).
11. Intangible assets
Note
Explor at ion &
Evaluat ion costs
$'000
Com pute r
Soft war e
$'000
Total
$'000
371,122
645
371,767
136,124
73
642
-
136,766
73
507,319
1,287
508,606
211,266
(406,720)
397
-
211,663
(406,720)
311,865
1,684
313,549
156
156
Cost
At January 1, 2012
Additions
Transfers and reclassifications
12
At December 31, 2012 (restated)
Additions
Transfers and reclassifications (1)(2)
12
Accumulated amortization and impairment
At January 1, 2012
-
Amortization
Impairment charge(3)
29,017
271
-
271
29,017
29,017
427
29,444
Amortization
82,948
437
-
437
82,948
111,965
864
112,829
478,302
199,900
860
820
479,162
200,720
(4)(5)(6)
Impairment charge
Net book value
66
1. In March 2013, a portion of the Hawler license area E&E costs in Kurdistan was transferred from intangible assets to property, plant and
equipment (PP&E) following a reserve report, effective March 31, 2013, from Netherland, Sewell & Associates, Inc. (NSAI) confirming the
discovery of reserves at Demir Dagh within the license area. As a result, $373.2 million of costs associated with the license area were
transferred from intangible E&E assets to Oil and Gas assets classified as PP&E.
2. Following a further reserve report from NSAI, effective December 31, 2013, confirming the discovery of reserves at Zey Gawra within the
Hawler license area, $33.5 million of costs associated with Zey Gawra were transferred from intangible E&E assets to Oil and Gas assets
classified as PP&E. Please refer to Note 33 for further information.
3. Mateen-1 was drilled by the operator of the Sindi Amedi block, with technical support provided by Oryx Petroleum. The understanding of the
structure did not support a working petroleum system on Mateen. The impairment charge of $29.0 million recorded in 2012 was reviewed and
adjusted downwards by $1.2 million in the second quarter of 2013, based on new information received from the operator.
4. Drilling on the Dila prospect, one of several identified prospects in the OML 141 license area offshore Nigeria was completed in the second
quarter of 2013. Oil was encountered during the drilling, but the estimated quantities of oil were not sufficient to be considered commercial.
The Group considered the well unsuccessful and an impairment charge of $21.7 million was recorded during the second quarter of 2013.
5. On April 25, 2013, in conjunction with the operator, Oryx Petroleum relinquished 34% of the Sindi Amedi license area to the Kurdistan Regional
Government in exchange for the replacement of an exploration well commitment with the acquisition of 180km of seismic data in the retained
license area. Following acquisition of this seismic data, during the third quarter of 2013, the Company decided to relinquish its remaining
interest in the Sindi Amedi license area upon expiry of the initial exploration period on October 2, 2013. An impairment charge of $45.2 million
was recorded during the second half of 2013.
6. In conjunction with the operator, drilling on the Horse prospect (formerly Ma) in the western portion of the Haute Mer A license area offshore
Congo (Brazzaville) was completed in the fourth quarter of 2013. Although the H-1 well encountered both Tertiary and Cretaceous reservoirs
with good porosity, the reservoirs were water bearing. The Company considers the well unsuccessful. An impairment charge of $17.3 million
was recorded during the fourth quarter of 2013.
The carrying amounts of intangible E&E assets relate to:
December 31
December 31
2013
2012
$'000
$'000
(restated)
Middle East
West Africa
95,930
103,970
427,003
51,299
199,900
478,302
The net reduction to intangible E&E assets during the year ended December 31, 2013 reflects the transfer to PP&E of $406.7 million due to the
successful drilling at Demir Dagh and Zey Gawra in the Hawler license area and the impairment charges of $82.9 million relating to the Sindi Amedi
license area, the Dila-1 well in OML 141 and the H-1 well in the Haute Mer A license area. These amounts are offset by additions of $211.3 million.
The amounts for intangible assets represent costs incurred on active exploration projects. These amounts remain capitalised, provided there are
no indications of impairment, until the process is completed to determine whether reserves are established. At that stage the relevant costs are
either transferred to PP&E or written-off to the statement of comprehensive income as exploration expense.
The National Assembly of Congo (Brazzaville) announced on July 25, 2013 that it had approved a one year extension to the initial exploration period
of the Haute Mer A license area to September 2014. One of the two subsequent three year extension periods will be shortened to two years.
67
12. Property, plant and equipment
Note
Cost
At January 1, 2012
Additions
Transfers and reclassifications
11
Transfers and reclassifications (1)(2)
Additions
11
Oil and Gas
Assets
$'000
Fixtures and
Equipment
$'000
Total
$'000
-
111
111
-
633
(73)
633
(73)
-
671
671
406,720
-
406,720
35,047
1,773
36,820
441,767
2,444
444,211
Accumulated depreciation
At January 1, 2012
-
6
6
Depreciation
-
90
90
-
96
96
Depreciation
-
291
291
-
387
387
441,767
575
2,057
575
443,824
Net book value
1. In March 2013 a portion of the Hawler costs in Kurdistan was transferred from intangible E&E assets to PP&E following a reserve report from
NSAI, effective March 31, 2013, confirming the discovery of reserves at Demir Dagh within the license area. As a result, $373.2 million of E&E
costs associated with the license area were transferred from intangible E&E assets to Oil and Gas assets classified as PP&E.
2. Following a further reserve report from NSAI, effective December 31, 2013, confirming the discovery of reserves at Zey Gawra within the
Hawler license area, $33.5 million of costs associated with Zey Gawra were transferred from intangible E&E assets to Oil and Gas assets
classified as PP&E. Please refer to Note 33 for further information.
During the third quarter of 2013, the Kurdistan Regional Government gave its consent to lease an Early Production Facility for the Demir Dagh
area of the Hawler license. Refer to Note 31 for further information on the increase in capital commitments due to the finalisation of the Early
Production Facility lease contract.
No assets have been pledged as security.
13. Inventories
December 31
December 31
2013
2012
$'000
$'000
(restated)
Exploration materials
No inventories have been recognised as an expense during the year (2012: $nil).
No inventories have been pledged as security.
68
12,465
5,601
12,465
5,601
14. Trade and other receivables
December 31
December 31
2013
2012
$'000
$'000
(restated)
Advances paid on contracts
5,500
4,000
Receivables from joint venture partners
717
7,197
Receivables from related parties
116
-
Other receivables
273
1,164
6,606
12,361
Trade and other receivables are denominated in the following currencies:
December 31
December 31
2013
2012
$'000
$'000
(restated)
US Dollar
6,239
11,752
306
362
Euro
28
241
Central African Franc
33
6
6,606
12,361
Swiss Franc
The carrying amounts of trade and other receivables presented above are reasonable approximations of the fair value and not past due or impaired
as of the date of issuance of these financial statements.
The balance of joint venture receivables arises from timing differences between cash calls and the expenditure incurred on behalf of joint venture
partners. Cash calls are normally due within 15 days.
15. Prepaid charges
December 31
December 31
2013
2012
$'000
$'000
(restated)
Prepaid charges
5,652
4,971
5,652
4,971
16. Cash and cash equivalents
December 31
December 31
2013
2012
$'000
$'000
(restated)
Cash at bank and in hand
306,034
72,725
306,034
72,725
69
16. Cash and cash equivalents (continued)
Cash and cash equivalents are denominated in the following currencies:
December 31
December 31
2013
2012
$'000
$'000
(restated)
US Dollar
304,848
72,256
Swiss Franc
736
408
Euro
242
13
49
47
Canadian Dollar
28
-
116
-
15
1
306,034
72,725
Nigerian Naira
Iraqi Dinar
Cash and cash equivalents comprise cash and short-term deposits with an original maturity of three months or less, substantially held in interestbearing accounts. The carrying amounts presented above are reasonable approximations of the fair value.
AOG provided additional equity funding to the Group amounting to $234.8 million in January 2013.
As a result of the initial public offering, the Group received a total of $236.0 million (CAD$238.9 million) which represents the total offering of
$249.4 million (CAD$250.5 million), net of underwriters’ fees.
17. Deferred tax assets
The analysis of deferred tax assets is as follows:
December 31
December 31
2013
2012
$'000
$'000
(restated)
Deferred tax assets to be recovered after twelve months
911
870
Deferred tax assets
911
870
The movement in deferred tax assets during the year is as follows:
70
Defined benefit
Long-term
plan
incentive plan
Total
$'000
$'000
$'000
501
369
870
Credited / (debited) to the income statement
132
(91)
41
633
278
911
18.Trade and other payables
December 31
December 31
2013
2012
$'000
$'000
(restated)
Trade accounts payable
14,033
8,381
Payables to joint venture partners
12,213
6,349
1,120
2,608
136,807
60,087
40,706
43,383
204,879
120,808
Less : Non-current portion
(66,271)
(37,687)
Current portion
138,608
Payables to related parties
Contingent costs
Other payables and accrued liabilities
83,121
Included in Other payables and accrued liabilities is $0.7 million due by way of a direct contribution towards the construction of a hospital for
children in Erbil in Kurdistan (December 31, 2012: $40.0 million).
Trade and other payables are denominated in the following currencies:
December 31
December 31
2013
2012
$'000
$'000
(restated)
192,811
117,680
Swiss Franc
9,734
2,358
Euro
1,790
272
349
152
26
22
166
284
3
40
204,879
120,808
US Dollar
UK Pound
Canadian Dollar
Nigerian Naira
Trade and other payables comprise current amounts outstanding for trade purchases and ongoing costs. Contingent costs relate to the acquisition
of OP Hawler Kurdistan Ltd (Note 32). The carrying amounts of trade and other payables presented above are reasonable approximations of their
fair value.
19.Current income tax liabilities
December 31
December 31
2013
2012
$'000
$'000
(restated)
Corporation tax payable
463
870
463
870
71
20. Decommissioning obligation
The Group has an obligation to decommission the drilled wells upon ultimate future cessation of operations. The estimated net present value of
the decommissioning obligation at December 31, 2013 is $1.3 million (December 31, 2012 – nil), based on a total undiscounted liability of $22.9
million. The decommissioning obligation was discounted using a rate of 12.0% at December 31, 2013.
Year ended
December 31
2013
$'000
Year ended
December 31
2012
$'000
(restated)
-
Decommissioning obligation, beginning of the year
-
Property acquisition and development activity
1,346
-
Decommissioning obligation, end of the year
1,346
-
21. Borrowings
December 31
December 31
2013
2012
$'000
$'000
(restated)
Convertible loan notes - unsecured
-
7,781
Current portion
-
7,781
The fair value of borrowings equalled their carrying amount, as the impact of discounting was not significant. All borrowings were denominated
in US Dollars.
At December 31, 2012, the Group had 7,681 loan notes convertible at par value of $1,000 and 80 loan notes convertible at $1,250 being $7,781
convertible loan notes in total. During the first quarter of 2013, the loan notes were fully converted into equity.
Furthermore, the Group entered into an uncommitted bond facility agreement on March 26, 2013 whereby up to a maximum of US$15 million may
be used by OPHP for bank guarantees. As of December 31, 2013, no guarantees were issued under this agreement.
22. Share capital and share premium
Issued and fully paid
Number
Share
Share
of shares
capital
premium
$'000
$'000
At January 1, 2012
105,153
105,153
-
Issue of shares
394,158
394,158
771
499,311
499,311
771
Issue of shares
260,606
260,606
4,531
At May 15, 2013
759,917
759,917
5,302
OPCL share capital upon incorporation
Issue of shares
1
99,854,917
1,009,684
-
99,854,918
1,009,684
-
The Company has unlimited authorised share capital outstanding as at December 31, 2013.
Prior to the Company’s initial public offering, OPHP had authorised two classes of ordinary shares which carried no right to fixed income. The
holders of ordinary ‘A’ shares were entitled to appoint all the directors of the Company. Otherwise, both classes of shares ranked pari passu. Prior
to the IPO, AOG International Holdings Ltd held 699,900 ordinary ‘A’ shares and its parent, AOG, which was the ultimate parent company of the
Company, held 100 ordinary ‘B’ shares. Additionally, 42,540 ordinary ‘B’ shares were held by directors of AOG, persons connected to AOG, Group
management and employees of the Group via the Long Term Incentive Plan and investments in the Company.
Immediately prior to the closing of the initial public offering, the Group, AOG and its affiliates, as well as other shareholders of the Company,
engaged in certain transactions whereby the Company acquired all of the issued and outstanding shares of OPHP in exchange for 81,762,377
common shares of the Company. These shares acquired include 10,920 shares of OPHP issued prior to closing to the employees and executive
officers of OPHP, as well as 6,457 shares of OPHP issued to employees and executive officers of OPHP under previously issued awards pursuant
to the OPHP long term incentive plan.
72
On May 5, 2013, the Company announced the filing of a supplemented PREP prospectus with the securities regulatory authorities in each of the
provinces of Canada, other than Quebec, in connection with its initial public offering of 16,700,000 common shares, at a price of CAD$15.00 per
common share for total gross proceeds of CAD$250.5 million ($249.4 million). The IPO closed on May 15, 2013.
Immediately prior to closing, a corporate restructuring occurred whereby the Company became the parent company of OPHP. Although the
consolidated financial information has been released in the name of the Company it represents in-substance continuation of the pre-existing
Group, headed by OPHP.
Holders of 21,155 ordinary ‘B’ shares of OPHP had the right to purchase an additional half share at par value for every share held (warrants).
Warrant holders could exercise the right to purchase shares at any time once completing three years’ service, or on the occurrence of an exit event,
such as an offering of the Company’s shares to the public. Accordingly, prior to closing of the IPO, the warrants, which represented an entitlement
to acquire 10,515 shares of OPHP, were cancelled in exchange for 1,131,349 warrants issued by the Company that entitled the holder to acquire,
for each warrant held, one common share of the Company at $9.29 per share for a period of 10 business days following the closing. All warrants
were exercised on or before June 13, 2013 resulting in an issuance of 1,131,349 common shares for net proceeds to the Company of $10,515,000.
Subsequent to the IPO, during 2013, the Group issued 239,703 shares to employees and executive offers under the Group’s long term incentive
plan and 8,607 shares to employees and executive officers as a share gift. In addition, 12,881 shares were issued to Directors of the company as
remuneration.
Common shares outstanding at January 1, 2013
1
OPHP shares acquired by the Company immediately prior to the IPO
81,762,377
Initial public offering
16,700,000
First stage investors options exercised
1,131,349
Share gift
8,607
Long term incentive plan
239,703
Directors' compensation
12,881
99,854,918
Common shares outstanding at December 31, 2013
23. Basic and diluted loss per share
The loss and weighted average number of ordinary shares used in the calculation of the basic and diluted loss per share are as follows:
December 31
December 31
2013
2012
$'000
$'000
(restated)
Loss for the year attributable to equity holders
Weighted average number of ordinary shares for basic
and diluted loss per share*
Basic and diluted loss per share
(185,564)
(58,359)
90,797,365
27,832,823
$
$
(2.04)
(2.10)
* For 2012, warrants, convertible loan notes, treasury shares and unvested LTIP shares were excluded as they were then anti-dilutive. For 2013,
the unvested LTIP shares are excluded as they are anti-dilutive. There were no warrants, convertible loan notes or treasury shares at December 31,
2013. The weighted average number of shares of OPHP for the year ended December 31, 2012 is presented as if they were shares of the Company
(refer to Note 22).
73
24. Other reserves
Treasury
shares
$'000
Share based
payments
$'000
Total
$'000
(864)
3,449
2,585
(8,468)
9,332
11,729
(9,332)
11,729
(8,468)
-
-
5,846
5,846
Share based payment transactions*
Issue of shares for long-term incentive plan
Issue of shares for Directors' compensation
-
25,047
(25,533)
(174)
25,047
(25,533)
(174)
-
5,186
5,186
At January 1, 2012
Share based payment transactions
Issue of shares for long-term incentive plan
Release of shares for long-term incentive plan
*Share based payments for the year ended December 31, 2013 include a share grant to employees and executive officers of $13.7 million
immediately prior to the Company’s initial public offering.
25. Net cash used in operations
December 31
December 31
(184,504)
(58,740)
728
(4)
60
25,047
82,948
(1,964)
361
10
(89)
11,729
29,017
(97)
Operating cash flows before movements in working capital
(77,689)
(17,809)
Increase in inventories
(Increase)/decrease in trade and other receivables
Increase in trade and other payables
(6,864)
8,555
66,850
(5,528)
(6,541)
6,163
Net cash used in operations
(9,148)
(23,715)
2013
$'000
Net loss before income tax
2012
$'000
(restated)
Adjustments for:
Foreign exchange (gains) / losses
Interest expense / (income) - net
Impairment of intangible assets
Decrease in retirement benefit obligation, net of remeasurement
26. Share based payments
Initial share gift
An initial share gift comprising common shares of Oryx Petroleum Company PLC was granted to officers and employees who commenced
employment before the end of January 2011. An initial share gift of 50 common shares of OPHP was granted to each non-executive director of the
Company on their appointment in 2012, totalling 300 shares of OPHP. These shares vested immediately.
Long term incentive plan
The long term incentive plan (LTIP) was introduced in 2010 to provide a long-term incentive scheme which motivates all employees and provides a
longer-term perspective to the total remuneration package. Annual awards under the LTIP comprised common shares, originally of Oryx Petroleum
Company PLC and now of the Company. These shares vest in three equal tranches with one-third vesting immediately on date of grant, one-third
on July 1 the following year and the balance vesting on July 1 the year after.
2,628 shares of OPHP relating to the 2011 LTIP, 3,705 shares of OPHP relating to the 2012 LTIP and 232,387 shares of the Company relating to the
2013 LTIP vested during the year ended December 31, 2013. (2012: 2,150 shares of OPHP relating to the 2010 LTIP, 2,831 shares of OPHP relating
to the 2011 LTIP and 3,620 shares of OPHP relating to the 2012 LTIP vested). Immediately prior to the initial public offering 6,457 shares of OPHP
were issued to employees and executive officers of OPHP under previously issued awards pursuant to the OPHP long term incentive plan (Note 22).
74
The following shares have been awarded under the 2011, 2012 and 2013 schemes:
LTIP
Number
of shares
Share gift
Number
of shares
Total
Number
of shares
772,631
-
772,631
46,050
1,159,108
(231,327)
(304,598)
(389,490)
32,278
-
46,050
32,278
1,159,108
(231,327)
(304,598)
(389,490)
1,052,374
32,278
1,084,652
Shares
Shares
Shares
Shares
Shares
Shares
5,100
711,998
(282,756)
(419,292)
(240,994)
1,174,923
-
5,100
1,174,923
711,998
(282,756)
(419,292)
(240,994)
826,430
1,207,201
2,033,631
At January 1, 2012
Shares
Shares
Shares
Shares
Shares
Shares
granted for 2011 LTIP
granted for 2012 share gift
issued for 2010 LTIP
granted for 2013 share gift
The number of shares granted and issued of OPHP prior to the initial public offering are presented as if they were shares of the Company (see
Note 22)
The amount of share based payments in respect of officers and employees charged to the statement of comprehensive income for the year ended
December 31, 2013 was $24.9 million (2012: $11.6 million). Prior to the initial public offering, the fair value of the shares granted under the long
term incentive plan was determined by management in the absence of readily available market value and was calculated based on asset values
of the Group. The fair value of the shares of OPHP granted in 2011 was $1.00 thousand per OPHP share and $1.25 thousand per OPHP share for
2012. For the 2013 LTIP plan, the shares have been granted at a range between $12.33 and $14.01 per share (CAD $13.22 and CAD $14.49 per
share). Subsequent to the initial public offering, the fair value of the shares of the Company granted under the long term incentive plan has been
determined based on the volume weighted average price of the shares issued for the five days prior to the grant date.
27. Retirement benefit obligation
The Group operates a defined benefit pension plan for all employees of Oryx Petroleum Holdings PLC and its subsidiary, Oryx Petroleum Services
SA. The plan is funded by the payment of contributions to separately administered pension funds.
The disclosures set out below are based on calculations carried out as at December 31, 2013 by a qualified independent actuary and have been
prepared in accordance with IAS 19 – Employee Benefits.
The principal actuarial assumptions used at the reporting date were:
Discount rate
Expected return on plan assets
Expected rate of salary increases
Future pension increases
Inflation
December 31
2013
December 31
2012
(restated)
2.20%
2.20%
2.00% - 2.50%
0.00%
1.00%
2.00%
2.00%
2.00% - 2.50%
0.00%
1.00%
The following table reconciles the funded status of defined benefit plans to the amounts recognised in the consolidated statement of financial
position:
December 31
2013
$'000
December 31
2012
$'000
(restated)
Fair value of plan assets
Present value of defined benefit obligation
20,605
24,097
15,553
18,022
Defined benefit obligation
(3,492)
(2,469)
75
The change in the defined benefit obligation is as follows:
December 31
2013
$'000
December 31
2012
$'000
(restated)
Opening defined benefit obligation
Current service cost
Interest cost
Remeasurement losses
Translation difference
Other
(2,469)
(2,607)
(397)
(1,424)
(72)
3,477
Defined benefit obligation
(3,492)
(739)
(1,169)
(309)
(2,542)
(74)
2,364
115
(2,469)
The change in the fair value of plan assets is as follows:
December 31
2013
$'000s
December 31
2012
$'000s
(restated)
Opening fair value of plan assets
Interest income
Return on plan assets
Employer contributions
Benefits deposited
Translation difference
15,553
353
(468)
2,929
1,611
627
11,720
337
(304)
2,085
809
906
Fair value of plan assets
20,605
15,553
The fair value of the plan assets are comprised of investments held by the insurance company that fully reinsures the Group’s pension liabilities.
The amounts recognised in comprehensive income are determined as follows:
December 31
2013
$'000s
December 31
2012
$'000s
(restated)
Current service cost
Net interest expense / (income)
Other
2,607
45
9
1,169
(28)
40
Defined benefit cost recognized in profit or loss
2,661
1,181
The following table summarises the present value of the defined benefit obligation with certain changes in the actuarial assumptions used:
Decrease in discount rate of 0.25%
Increase in discount rate of 0.25%
Decrease in salary increases of 0.25%
Increase in salary increases of 0.25%
Decrease in life expectancy of one year
Increase in life expectancy of one year
December 31
2013
$'000s
December 31
2012
$'000s
(restated)
25,444
23,271
24,047
24,581
24,144
24,499
18,753
17,281
17,815
18,172
17,817
18,164
Defined benefit costs of $2.7 million recognised in the statement of comprehensive income have been included in general and administrative
expenses.
The Group expects to make contributions of $1.9 million to the defined benefit plan during the next financial year. The actual contributions for
2013 amounted to $2.9 million (2012: $2.1 million).
76
28. Subsidiaries
Details of the Company’s subsidiaries at December 31, 2013 are as follows:
Country of Principal
Proportion of Name of subsidiary
incorporation
activity
interest/voting rights
Oryx Petroleum Holdings PLC(1)
Malta
Intermediate holding company
100%
Oryx Petroleum Services SA
Switzerland
Administrative/technical services 100%
Oryx Petroleum Middle East Ltd BVI
100%
Oryx Petroleum Africa Ltd BVI
100%
OP OML 141 Nigeria Ltd
Nigeria
Exploration for oil and gas
100%
OP AGC Shallow Ltd
BVI
100%
OP Sindi Amedi Kurdistan Ltd
BVI
100%
OP Hawler Kurdistan Ltd(2)
BVI
100%
Oryx Petroleum Congo SA
Congo
100%
BVI
100%
OP (TBA) Ltd(4)
OP Iraq Ltd
BVI
100%
KPA Western Desert Energy Ltd(3)
Cyprus
66.67%
AmiraKPO Ltd(3)
Cyprus
Exploration for oil and gas /
66.67%
Mining of bitumen
Cyprus
66.67%
AmiraKPO Exploration Ltd(3)
AmiraKPO Petroleum Company Ltd(3)
Cyprus
Mining of bitumen
66.67%
AmiraKPO Middle East Ltd
Malta
60%
Sandhill Petroleum Operations Ltd
Anguilla
60%
Desert Hill Petroleum Operations Ltd
Anguilla
60%
Damsel Petroleum Operations Ltd
Anguilla
60%
Black Hills Petroleum Operations Ltd
Anguilla
60%
Raval Petroleum Operations Ltd
Anguilla
60%
1. Held directly by Oryx Petroleum Corporation Limited. All others are held through subsidiary undertakings.
2. OP Hawler Kurdistan Ltd was formerly known as Norbest Ltd.
3. In the fourth quarter of 2013, Oryx Petroleum Middle East Ltd increased its participating interest in KPA Western Desert Energy Ltd., and its
subsidiary undertakings, from 50% to 66.67%. 50 million additional shares of KPA Western Desert Energy Ltd. were purchased for $0.001 per
share.
4. OP (TBA) Ltd was formerly known as OP Taoudeni Mauritania Ltd
A material non-controlling interest in the Group’s activities is held through the following subsidiary:
Subsidiary
Ownership
Interest
AmiraKPO Ltd
66.67%
Loss allocated to
non-controlling interests
during 2013
$'000s
Accumulated
non-controlling interests
at December 31, 2013
$'000s
-
16,954
Summarised financial information for AmiraKPO Ltd is provided below
Total assets
Total liabilities
December 31
2013
$'000s
December 31
2012
$'000s
(restated)
45,293
3,788
-
40,369
14,937
(661)
77
29. Related party transactions
The Group’s indirect majority shareholder is AOG (incorporated in Malta). The majority of AOG’s outstanding shares are owned by Samsufi Trust,
an irrevocable discretionary charitable trust created at the suggestion of Jean Claude Gandur, a director and the Chairman of the Company. Mr.
Gandur is not one of the beneficiaries of the Samsufi Trust.
The following transactions were carried out with related parties, which are all subsidiaries of AOG.
(a) Purchases of goods and services
Year ended
Year ended
December 31
December 31
2013
2012
$000
$000
(restated)
32
51
AOG Advisory Services SA
AOG International Holdings Ltd
1,692
1,368
Addax and Oryx Group Ltd
2,178
2,636
-
21
20
188
4
4
Addax Bioenergy Management
Addax Energy SA
Addax Immobilier SA
Addax Nigeria Ltd.
160
-
AOG Advisory Services Ltd
105
344
-
1
4,191
4,613
Oryx Supply & Storage SA
Purchases of goods and services have been acquired on normal commercial terms and conditions. In addition $0.5 million (2012: $nil) has been
donated to The Addax and Oryx Foundation, a Swiss-registered charity.
(b) Payables to related parties
Year ended
Year ended
December 31
December 31
2013
2012
$000
$000
(restated)
AOG Advisory Services SA
1,105
533
Addax and Oryx Group Ltd
14
2,001
AOG International Holdings Ltd
1
-
Addax Energy SA
-
70
Addax Immobilier SA
-
4
1,120
2,608
The amounts outstanding are unsecured. No guarantees have been given. Amounts owing to related parties relate to purchases of goods and
services which were acquired on normal commercial terms and will be settled in cash.
(c) Receivables from related parties
December 31
December 31
2013
2012
$000
$000
(restated)
AOG Advisory Services Ltd
39
38
39
38
The amounts outstanding were acquired by related parties on normal commercial terms and will be settled in cash. The receivables are unsecured
and bear no interest. No provisions are held against receivables from related parties.
(d) AOG guarantee
Certain contingent payments (Note 32) are supported by a guarantee provided by AOG.
78
(e) Key management compensation
The remuneration of the directors and senior officers, the key management personnel of the Group, in aggregate is set out below.
Year ended
Year ended
December 31
December 31
2013
2012
$000
$000
(restated)
Wages, salaries and other short term benefits
Post employment benefits
Share-based compensation
6,640
2,988
438
383
10,125
5,504
17,203
8,875
30. Financial instruments by category
Financial assets
December 31
December 31
2013
2012
$000
$000
$000
(restated)
Loans and receivables
Trade and other receivables
Financial liabilities
6,606
12,361
306,034
72,725
312,640
85,086
December 31
December 31
2013
2012
$000
$000
$000
(restated)
Amortized cost
Borrowings
204,879
120,808
-
7,781
204,879
128,589
The fair value of the financial assets and liabilities approximates the carrying amounts.
31. Commitments
(a) Capital commitments
It will be necessary to incur expenditure in order to maintain existing exploration and appraisal rights, therefore as at December 31, 2013, the
Group had capital commitments totalling $177.9 million (December 2012: $177.4 million) which includes minimum work obligations on production
sharing contracts of $63.6 million (December 2012: $58.5 million).
The Group signed a lease agreement during the third quarter of 2013 for an Early Production Facility relating to the Demir Dagh development in the
Hawler license area. The commitment related to this lease agreement is $35.2 million.
During the second quarter of 2013, the Group resolved to donate a total of $1.5 million over a period of 3 years to The Addax & Oryx Foundation.
The first payment of $0.5 million was made in July 2013.
(b) Operating lease commitments – Group company as lessee
The Group leases buildings and equipment under non-cancellable operating lease agreements with varying terms and renewal rights. The
corresponding lease expenditure charged to the statement of comprehensive income during the year ended December 31, 2013 was $1.2 million
(December 2012: $0.9 million).
The future aggregate minimum lease payments under non-cancellable operating leases are as follows:
Leases which expire
December 31
December 31
2013
2012
$000
$000
(restated)
No later than one year
677
13
One to five years
139
-
816
13
79
32. Contingent liabilities
During 2011, the Group acquired interests in
various exploration licenses. The acquisition
terms included additional consideration and
other liabilities, contingent upon the outcome
of future drilling activities and, in some
cases, the quantities of reserves discovered.
At December 31, 2013 these amounted in
aggregate to a maximum of $193.5 million
(December 31, 2012 – $197.5 million). In
accordance with the terms of the agreements
for the acquisition of interests in these license
areas, the Group is contractually obliged
to make the payments upon a declaration
of commercial discovery. If quantities of
hydrocarbons discovered are not determined
to be commercial, no payments will be due.
The aggregate fair value of the contingent
consideration, based on the estimated
probability of success, was initially evaluated
by the directors at $46.3 million, of which
$27.7 million was first recognised in the
Group’s statement of financial position at
December 31, 2011 in relation to the
Hawler license area acquired as part of the
business combination with Norbest Limited
(subsequently renamed OP Hawler Kurdistan
Limited). The determination of fair value
was principally based on an assessment
of the available geological data, historical
success rates in the region and other related
assumptions on the likelihood of commercial
success.
In addition, the net assets and liabilities
acquired with OP Hawler Kurdistan Limited
include a contingent payment to the
Kurdistan Regional Government in relation
to the declaration of a first commercial
discovery. The total potential amount payable
is $50 million of which the fair value, based
on the estimated probability of success, was
initially evaluated by the directors at $32.4
million and recognised in the fair values of the
identifiable assets and liabilities acquired.
During 2013, the fair values of the contingent
consideration and the contingent payment
have been re-evaluated following the
discovery of reserves in the Hawler license
area. The fair value of the payments increased
by $74.5 million to an estimated fair value
of $134.6 million, of which $70.0 million is
expected to be paid within one year. The
increase in fair value of the payments resulted
in $56.9 million recognised in the statement
of comprehensive income for the year
ended December 31, 2013 and $17.6 million
capitalised to property, plant and equipment.
Consequent upon the relinquishment of the
Sindi Amedi exploration license in the third
quarter of 2013 the aggregate fair value of the
contingent consideration was decreased by
$3.9 million.
80
33. Events after the balance sheet
date
In January 2014, the Group determined that
the Demir Dagh 2 (DD-2) well discovery is a
Commercial Discovery pursuant to the terms
of the Hawler Production Sharing Contract
(PSC). In accordance with the terms of the
Hawler PSC, Oryx Petroleum is obliged to
provide an additional payment to the KRG of
$50 million which was paid by the Group in
February 2014. In accordance with the terms
of the agreement of the acquisition of OP
Hawler Kurdistan Ltd, Oryx Petroleum is also
obliged to provide additional consideration of
$20 million to the vendor, of which $10 million
was paid in February 2014 with the balance to
be paid prior to the end of 2014.
In February 2014, the Group updated its
reserves and resource volumes based upon
a report issued by NSAI effective December
31, 2013. Total gross (working interest) proved
and probable oil reserves in the Hawler
license area in Kurdistan increased to 213
MMbbl from 164 MMbbl included in the
NSAI report effective March 31, 2013. The
increase in reserves booked relate primarily
to the discovery at Zey Gawra announced
in the fourth quarter of 2013. An increase of
23 MMbbl of best estimate gross (working
interest) contingent resources was also
included in the report effective December 31,
2013 citing a total of 217 MMbbl in the Hawler
license area (NSAI report effective March 31,
2013 – 200 MMbbl) and 6 MMbbl in the Haute
Mer A license area (NSAI report effective
March 31, 2013 - nil). This increase is due to
the discoveries at Banan and Ain-Al-Safra
in the Hawler license area, and the Elephant
discovery in the Haute Mer A license area.
Finally, the report effective December 31, 2013
updated the best estimate unrisked gross
(working interest) prospective oil resources to
1,167 MMbbl (risked: 209 MMbbl).
In February 2014, OPCL extended the
uncommitted bond facility agreement for an
additional twelve months, whereby up to a
maximum of $15 million may be used by Oryx
Petroleum for bank guarantees. As at the date
of this document, no guarantees were issued
under this agreement.
In March 2014, the Group announced that the
testing of the E-1 exploration well targeting
the Elephant prospect in the Haute Mer
A license area confirmed the discovery of
natural gas and crude oil. The discovery of
natural gas and crude oil was previously
announced in September 2013. Together with
the operator of the license area, the Group
will further analyse the test results and other
data accumulated during the drilling of the
well and determine the next steps.
Effective February 25, 2014 OP (TBA) Limited
has changed its name to OP AGC Central
Limited.
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81
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82
CONTACT
info@oryxpetroleum.com
Oryx Petroleum Corporation Limited
Registered Office
3400 First Canadian Centre 350
7 Avenue Southwest
Calgary, Alberta T2P 3N9
Canada
Iraq
OP Hawler Kurdistan Limited
Gulan Str., English Village No. 275
Erbil, Kurdistan Region
Iraq
Tel +41 58 702 94 00
Geneva
Oryx Petroleum Services SA
35 rue de la Synagogue
1204 Geneva
Switzerland
Tel +41 58 702 93 00
Fax +41 58 702 93 40
Congo
Oryx Petroleum Congo SA
Residence Gabriella
Avenue Jean-Marie Concko
Centre Ville Pointe Noire
Republique du Congo
Tel +242 05 708 44 44
Nigeria
OP OML 141 Nigeria Limited
Maersk House,Third Floor
121 Louis Solomon Close
Victoria Island, Lagos
Nigeria
Tel +234 1 277 8332 or 8333
83
oryxpetroleum.com
84

2013 Annual Report

Transcription

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