Delivering results across our
North African portfolio
SDX Energy Inc.
2017 Annual Report
Our Highlights
2017 Annual Report
Corporate and Financial
Operational Highlights
Reserves
• As at December 31, 2017 the Company’s working interest share of audited 2P reserves
was 13.5 mmboe(1). This represents a 45% increase on the combined 2P reserves of the
Company and the Egyptian and Moroccan businesses of Circle Oil PLC (“Circle Oil”) as at
December 31, 2016. The Company’s audited 2P reserves estimate has been audited in
accordance with the COGE Handbook by ERC Equipoise Limited an independent
qualified reserves evaluator and auditor.
SDX’s key financial metrics for the 3 and 12 months ended December 31, 2017
and 2016 are;
Three months Twelve months
ended ended
December 31 December 31
US$ million except per unit amounts 2017 2016 2017 2016
Net Revenues 11.0 5.4 39.2 12.9
Netback(2) 8.5 3.6 28.9 7.6
Net realized average oil/service fees - US$/barrel 54.39 36.60 46.70 31.51
Net realized average Morocco gas price - US$/mcf 9.72 - 9.51 -
Depletion, depreciation and amortization(3) (4.8) (0.8) (17.8) (3.3)
Non-cash exploration & eval’n write down - - - (28.4)
Non-cash impairment expense - (4.3) - (4.3)
Gain on acquisition (4.7) - 29.6 -
Total comprehensive income/ (loss) (2.6) 0.1 28.3 (28.0)
Net cash generated from operating activities 15.1 (1.7) 21.6 (1.9)
Cash and cash equivalents 25.8 4.7 25.8 4.7
(1) Using a conversion ratio of 5.8 Mcf:1 boe.
(2) Refer to “Non-IFRS Measures” section of this release below for details of Netback.
(3) Increased DD&A reflects the impact of the acquisition of Circle Oil’s producing assets in Egypt and
Morocco and the 8” Pipeline in Morocco.
• The above financial metrics for the three and twelve months ended December 31, 2017
reflect the impact of the acquisition of the Egyptian and Moroccan businesses of Circle
Oil (the “Circle Acquisition”) from January 27, 2017.
• The main components of SDX’s comprehensive income of US$28.3 million for twelve
months ended December 31, 2017 are;
- US$28.9 million netback for the period;
- US$29.6 million gain on acquisition of the Egyptian and Moroccan businesses of Circle Oil;
- US$17.8 million of DD&A – (increased as a result of the Circle Acquisition from
US$3.3 million in twelve months ended December 31, 2016); and
- US$2.4 million of transaction and restructuring costs relating to the above acquisition.
• Netback for the twelve months December 31, 2017 was US$28.9 million, up from
US$7.6 million for the twelve months to December 31, 2016, as the Company benefited
from the high margin Moroccan business acquired from Circle Oil and a recovery in oil
prices over the year.
• Cash position of US$25.8 million as at December 31, 2017 reflects strong netbacks and
a reduction in receivables of US$4.9 million, which primarily came from Egyptian
receivables inherited with the Circle Acquisition.
• Since December 31, 2017, a further US$6.0 million has been received from backdated
receivables which has helped the cash position to grow to US$30.6m as at February 28,
2018. As economic conditions continue to improve in Egypt, the Company is hopeful
that further meaningful reductions will be made to the Egyptian receivables position
during 2018.
• US$21.1 million of capital expenditure has been invested into the business during the
12 months ended December 31, 2017;
- US$13.9 million in Morocco, US$12.8 million of which related to the ongoing nine
well drilling programme and customer connection projects;
- US$3.2 million on the SD-1X discovery well and the 3D seismic programme at South Disouq;
- US$2.0 million in Meseda on the two successful Rabul exploration wells and a nine
well workover programme covering pump and tubing maintenance and the Meseda
facility upgrade; and
- US$2.0 million on the twelve well workover programme at North West Gemsa.
Production
• The Company’s share of production from its operations for the twelve months ended
December 31, 2017 was 3,237 barrels of oil equivalent per day (boepd) analysed as
follows, and which includes production from the Circle Acquisition with effect from
January 27, 2017;
- North West Gemsa 2,046 boepd
- Meseda 595 boepd
- Morocco 596 boepd
• On a pro forma basis, assuming that the Circle Oil Acquisition had completed on January
1, 2017, the Company’s share of production from its operations for the twelve months
ended December 31, 2017 would have been 3,457 boepd analysed as follows;
- North West Gemsa 2,220 boepd
- Meseda 595 boepd
- Morocco 642 boepd
Egypt
• In North West Gemsa, twelve successful well workovers were completed and the impact
of these is now being realised as gross production in the concession is stabilising at
approximately 4,400 boepd. Drilling has recommenced in 2018 with a two well program.
The first of these wells is expected to complete in early Q2 with operations on the second
well commencing immediately thereafter. The aim of these wells is to stabilise H2 2018
production at current rates.
• In Meseda, two successful exploration wells, Rabul-1 and Rabul-2 were drilled in 2017
and this has been followed in Q1 2018 with the successful appraisal well, Rabul-5. Rabul-
1 encountered 14.5 feet of net heavy oil pay with an average porosity of 21.2% in the
Yusr sand. Rabul-2 encountered 101.5 feet of net heavy oil pay, with an average porosity
of 20%, across the Yusr and Bakr sands. Rabul-5 encountered 151 feet of net heavy oil
pay, with an average porosity of 18% across the Yusr and Bakr formations. One further
appraisal/development well will be drilled in 2018 to develop the Rabul discovery.
During the year nine workovers, consisting of tubing and pump maintenance in existing
wells aimed at ensuring future production uptime, were completed. Finally, the Company
installed a new two-phase separator at the central processing facility, upgrading
processing capacity from 10,000 bfpd to 20,000 bfpd. Additional pump capacity was
also added to the facility to ensure that sufficient water volumes could be injected into
the waterflood project.
• In South Disouq, the Company successfully drilled the SD-1X exploration well which
found gas-bearing sands in the Abu Madi horizons, the well’s primary target. The well
flow tested at a surface constrained rate of 25.8 MMscfd of conventional natural gas and
was subsequently completed. After the successful test, the Company and its partners
completed a development plan for the area which was submitted to the Egyptian State
Gas authority, EGAS, for approval. The plan consists of the drilling of two additional
appraisal wells, the installation of a rented central processing facility and the laying
of a 10-kilometre pipeline to the main export line. The Company plans to commence
production, from the SD-1X discovery, at a gross plateau production rate of
approximately 50 MMscfd of conventional natural gas.
• The SD-1X well also drilled into deeper, potentially oil-bearing intervals beneath the main
objective where it encountered hydrocarbon shows. This deeper interval could not be logged
and an additional well, currently planned for 2019, will be required to test this interval.
• At South Ramadan during the year, and in relation to the last remaining commitment on
this concession, the final sub-surface technical work was completed in conjunction with
a commercial evaluation of development options. The result of this work was the
selection of an option that involves the drilling of a development well which is up-dip
of one of the previous producing wells in the field. Depending on rig availability, the well
will be drilled either early in Q2 2018 or late in Q3 2018. Upon the results of this well,
the Company will determine how best to optimise its position in this concession.
Morocco
• The Company’s Moroccan acreage consists of three concessions; Sebou, Lalla Mimouna
and Gharb Centre, all of which are located in the Gharb Basin in northern Morocco.
Sebou and Lalla Mimouna were obtained as part of the acquisition of Circle Oil and
Gharb Centre was acquired directly from the Moroccan State on June 1, 2017.
• In September 2017, the Company commenced a nine well drilling programme covering
six appraisal/development wells in Sebou, one appraisal/development well in Gharb
Centre and two exploration wells in Lalla Mimouna.
Operational Highlights continued
Outlook continued
Morocco continued
• The results of the well program to date are as follows with the Company achieving five
successful wells from the seven that have been drilled, a better than 71% success rate;
Permit Well Name Result Net Pay Test Rate
Sebou KSR-14 Gas Well 20.0m 6.40 MMscf/d
Sebou KSR-15 Gas Well 17.2m 7.52 MMscf/d
Sebou KSR-16 Gas Well 14.2m 8.43 MMscf/d
Gharb Centre ELQ-1* Uncommercial 2.0m Not Tested
Discovery
Sebou ONZ-7** Gas Well 5.0m 15.34 MMscf/d
Sebou KSS-2*** Dry Hole Nil Not Tested
Sebou SAH-2**** Gas Well 5.2m 13.45 MMscf/d
Well results announced *January 4, **January 15, ***February 21 and ****March 9, 2018
Disclosure clarification
Reference is made to the SDX December 31, 2017 Year End Reserves and Resources Audit
Report (“the 2017 Reserves and Resources Audit Report”), prepared and audited in
accordance with the COGE Handbook by ERC Equipoise Limited an independent, qualified
reserves auditor, which shows that 38.7 bcf of gas and 0.201 million barrels of condensate
have been classed as gross 2P Reserves in SDX’s South Disouq Concession (SDX 55%
Working Interest: 21.3 bcf of gas and 0.111 million barrels of condensate). Reference is
also made to the SDX Press Release dated July 5, 2017 whereby, amongst other things, it
was announced that SDX’s South Disouq Concession had Gross Contingent Resources of
47.1 bcf of gas and 2.2 million barrels of condensate (SDX 55% Working Interest: 25.9 bcf
of gas and 1.21 million barrels of condensate).
Notwithstanding that the 2017 Reserves and Resources Audit Report is now re-classifying
the originally reported Contingent Resources as 2P Reserves, albeit with a lower recoverable
volume, the Press Release of July 5, 2017 should have included some additional disclosure
describing possible uncertainties as at that date that may have resulted in the Contingent
Resources ultimately not being recovered/classed as 2P reserves. As at July 5, 2017, these
uncertainties would have been focused on potential recoverable volumes, gas price, the cost
to develop the required infrastructure (evacuation pipeline and gas processing facility) and
operating costs. These issues have subsequently been considered and addressed in the
2017 Reserves and Resources Audit Report as part of the process of reclassifying the
South Disouq Contingent Resources to 2P Reserves.
Outlook
Egypt
North West Gemsa (50% Working Interest)
• Targeting gross 2018 production of c.4,400 boepd, broadly similar to 2017. To achieve
this, two wells will be drilled and seven worked over.
• The expected gross cost of the two wells, including processing facility tie-ins is
US$6.6 million with the seven workovers expected to cost gross US$1.7 million.
Meseda (50% Working Interest)
• Targeting gross production of 3,800 bopd, a c.700 bopd increase on 2017’s level.
The increase will come from drilling four new wells in 2018, two of which will develop
the Rabul discovery and two infill producers in the wider Meseda area.
• The Company also aims to replace up to five ESPs in the wider Meseda area.
• Gross Meseda capex in 2018 is expected to be approximately US$6.0 million.
South Disouq (55% Working Interest)
• Up to four wells planned in 2018, two exploration wells (Ibn Yunus-1X and Kelvin-1X)
and two development wells (SD-4X and SD-3X). These wells have an estimated gross
capex cost of approximately US$12.0 million.
• Upon success of SD-4X and SD-3X, SDX expects to construct the SD-1X processing
facility together with a 10-kilometer pipeline connecting the processing facilities to the
main export line. Gross capex is estimated at approximately US$15.0 million, subject to
completion of final tenders and contracts.
• Ibn Yunus-1X and Kelvin-1X are targeting up to 150bcf of conventional natural gas
in separate structures from the SD-1X discovery. If successful, volumes will be tied back
to the SD-1X processing facility.
• Given the above, and assuming all necessary approvals are obtained, first gas is targeted
in the second half of 2018, at an initial gross plateau production rate of approximately
50 MMscf/d of conventional natural gas expected from the three development wells in
the SD-1X discovery structure. The gas price is still under negotiation.
• Annual opex, including processing facility rental cost, is predominantly fixed and estimated
at approximately US$6.0 million gross, subject to completion of final tenders and contracts.
South Ramadan (12.75% Working Interest)
• At South Ramadan, a development well which is up-dip from one of the previous
producing wells in the field, will be drilled either early in Q2 2018 or late Q3 2018.
The actual spud date of the well is dependent on rig availability. Total cost for the South
Ramadan work programme in 2018 will be approximately US$23.5 million, which includes
some platform remediation work and a well work over, both of which are dependent
on the success of the development well.
Morocco
Morocco (75% Working Interest)
• Given the recent drilling success, 2018 gross production is targeted to increase in line
with new customer tie-ins. Depending on timing of tie-ins, SDX is targeting gross
production of 8-10 MMscf/d of conventional natural gas by the end of 2018.
• SDX’s nine well Moroccan drilling programme continues in 2018, with the tie-in of the most
recent discovery, SAH-2 and the drilling of two exploration wells: LNB-1, which commenced
drilling operations on March 20, 2018 and LMS-1 which will be drilled early in Q2 2018.
• Including SAH-2, the gross cost for the 2018 wells (six total), inclusive of customer tie-
ins, and the payment of 2017 outstanding drilling payables is expected to be
approximately US$13.0 million.
• In addition, SDX plans to shoot 240km2 of 3D seismic in its Rharb Centre concession
at an estimated cost of US$6.5 million.
Corporate
• Continue to minimise costs and crystallise synergies from the Circle Oil Acquisition; and
• As part of the Company’s strategy it continues to review and explore opportunities to
expand the asset base in the North Africa region, including through new licencing rounds
and acquisitions.
Paul Welch, President & CEO of
SDX Energy commented:
“2017 was an exceptional year for SDX, with the acquisition of Circle Oil’s assets, enabling
us to substantially increase production, and cash flow, over the course of the year.
We continued to see strong operational performance throughout the year across our portfolio.
In North West Gemsa we are seeing the results of our twelve successful workovers, and in Meseda
we successfully drilled two exploration wells in 2017 followed by the successful Rabul-5 appraisal
well earlier this month. The remainder of 2018 will see a second appraisal well, Rabul-4, followed
by two development wells on the Meseda area of the concession. Our nine well drilling
programme in Morocco has seen five discoveries from seven wells drilled to date and
we look forward to continuing this drilling success throughout the rest of 2018.
As a company, we continue to focus on low cost, high margin production, thereby creating
further value for our shareholders. Our strong funding position means we are well placed to
capitalise on any suitable, value enhancing asset opportunities that may arise going forward.”
Contents
02 Key Financial & Operating Highlights
03 Review of Operations
21 Management’s Discussion & Analysis
44 Independent Auditor’s Report
45 Financial Statements
49 Notes to the Consolidated Financial Statements
IBC Corporate Information
SDX Energy Inc.
2017 Annual Report 01
Key Financial & Operating Highlights
Financial Statements
Three months ended December 31 Twelve months ended December 31
US$000’s except per unit amounts Prior Quarter 2017 2016 2017 2016
Financial
Gross Revenues(1) 13,902 13,972 8,436 52,493 18,362
Royalties (3,778) (2,968) (3,082) (13,327) (5,448)
Net Revenues 10,124 11,004 5,354 39,166 12,914
Operating costs (2,672) (2,526) (1,752) (10,254) (5,282)
Netback 7,452 8,478 3,602 28,912 7,632
Total comprehensive (loss)/income 4,408 (2,621) (2,059) 28,307 (27,963)
Net income/(loss) per share - basic 0.022 (0.010) (0.03) 0.156 (0.39)
Cash, end of period 30,469 25,844 4,725 25,844 4,725
Working capital (excluding cash) 27,928 20,881 7,098 20,881 7,098
Capital expenditures 3,423 15,302 856 21,040 13,339
Total assets 138,898 141,057 41,617 141,057 41,617
Shareholders' equity 116,981 114,619 37,264 114,619 37,264
Common shares outstanding (000's) 204,459 204,493 79,844 204,493 79,844
Operational
NW Gemsa oil sales (bbl/d) 1,893 1,710 468 1,733 534
Block-H Meseda production service fee (bbl/d) 551 561 679 595 662
Morocco gas sales (boe/d) 611 680 - 596 -
Other products sales (boe/d)(2) 384 310 3,166 313 796
Total sales volumes (boe/d) 3,439 3,261 4,313 3,237 1,192
Realized oil price (US$/bbl) 48.28 57.77 44.56 50.02 38.00
Realized service fee (US$/bbl) 36.41 44.11 31.12 37.05 26.26
Realized oil sales price and service fees ($/bbl) 45.61 54.39 36.60 46.70 31.51
Realized Morocco gas price (US$/mcf) 9.53 9.72 - 9.51 -
Royalties ($/bbl) 11.94 9.89 6.33 11.28 7.47
Operating costs ($/bbl) 8.44 8.42 4.41 8.68 7.25
Netback ($/bbl) 23.54 28.26 9.08 24.47 10.47
(1) Net Revenues for the 3 and 12 months ended 31 December 2016 includes US$2.3 MM relating to gas and natural gas liquids revenue relating to the period October 1, 2013 to December 31, 2016. This revenue had previously
not been recognised due to uncertainties relating to entitlement and pricing which have now been resolved. US$1.8 MM relates to the period October 1, 2013 to December 31, 2015 and US$0.5MM relates to the 12 months
ended December 31, 2016.
(2) Average daily natural gas and natural gas liquids sales relating to the period October 1, 2013 to December 31, 2016 and recognised in the 3 months to December 31, 2016 equated to 796 and 3,166 barrels of oil equivalent
(“BOEP/D”) for the 12 and 3 months to December 31, 2016 respectively. Out of the 796 BOEP/D, 130 BOE/D was actually generated in the 12 months to December 31, 2016.
02
SDX Energy Inc.
2017 Annual Report
Onshore expertise
South Disouq: completed 3D seismic acquisition
ahead of schedule and under budget.
Given exploration drilling success, we anticipate
a rapid increase in our high margin production.
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Production
8,387
boe/d
Combined Egyptian daily average gross production
for the twelve months to December 31, 2017
Reserves
25.7
mmboe
Asset reserves (gross) - North West Gemsa, Meseda, South Disouq
and Morocco at December 31, 2017
SDX Energy Inc.
2017 Annual Report 03
Where We Operate
Egypt
SDX Energy is actively involved in
exploration and development activities
in Egypt’s Eastern Desert, Nile Delta,
and Gulf of Suez basins.
The Eastern Desert and Gulf of Suez areas account for the
bulk of Egypt’s historical oil production. These two areas are
geologically related and expertise acquired in one translates
across to the other. The Nile Delta area offers exciting exploration
opportunities in a prolific and proven hydrocarbon system with
multiple productive horizons.
Combined asset area
1,405km2
4
Concessions
Alexandria
South Disouq
55% working interest
Cairo
EGYPT
Nile
Port Said
Suez
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Block-H Meseda
50% working interest
South Ramadan
12.75% working interest
North West Gemsa
50% working interest
Red Sea
04
SDX Energy Inc.
2017 Annual Report
Where We Operate
Morocco
Sebou, a 135km2 concession and
Lalla Mimouna, a 2,211km2 concession
are both located in the Gharb Basin of
northern Morocco. These concessions
were acquired by SDX in January 2017
from Circle Oil plc.
A further concession, Gharb Centre
(1,362 km2), was awarded to SDX
during Q2 2017.
Combined asset area
3,708km2
3
Concessions
75% working interest in each
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Algeria
Lalla Mimouna Nord
Mauritania
Mali
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Gharb Centre
Lalla Mimouna Sud
O u ed Seb o u
Oued Baht
Mechra Bel Ksiri
Exploration Licence
(Gharb Centre)
Exploration Licence
Exploitation Licence
3D Seismic Outline
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SDX Energy Inc.
2017 Annual Report 05
Chairman’s Statement
2017 was a
transformational year for
SDX as we continued to
deliver on our strategy
of creating value through
high margin production
growth across our
expanding portfolio.
We have a solid financial position and were
pleased to be able to access an additional
$10 million by way of a placing in September.
This has allowed us to commit more resources
towards capturing the opportunities presented
by our drilling campaigns, and their ability to
rapidly create value. We have a portfolio which
allows us to deliver upon our high margin
growth strategy, and we have the team in
place to deliver.
On behalf of the board I would like to thank
all of our shareholders for their support
throughout the year. In addition, our staff
have shown the highest levels of dedication
and commitment throughout a very active
twelve months. I thank them sincerely for
their indefatigable spirit. We are grateful to the
governments of Egypt and Morocco for their
partnership and support, and we are proud to
make a meaningful contribution to the energy
supply of both countries, as well as making a
positive economic and social impact. We look
forward to continuing to work for the benefit
of all of our stakeholders over the course of
2018 and beyond.
Michael Doyle
Non-Executive Chairman
Having stated our ambitions to grow, not only
through the development of our original assets,
but also via acquisition, we were pleased to
begin 2017 with the completion of the acquisition
of Circle Oil plc’s assets in Egypt and Morocco.
The Egyptian asset was highly complementary
to our existing asset base in country and
Morocco was a very attractive new country
entry, in a region that the team knew well and
had enjoyed success in previously. Most
importantly, the acquisition demonstrated our
ability to identify and transact highly value
accretive opportunities.
Over the course of 2017 your Company
has been moving at a fast pace. SDX is a highly
ambitious business and the breadth and depth
of our operational progress over the course
of the year clearly shows our intent.
I am pleased to report that our operations
remained safe throughout the year with zero
Lost Time Incidents (“LTIs”) reported.
The welfare of our people and those working
with us and living around our areas of
operations is of the highest importance and
we know that there is no room for complacency
in this regard.
As you will read throughout the report,
the operational achievements throughout 2017
have been numerous. The successful drilling
campaign with the SD-1X well at South Disouq
in our Egyptian portfolio was a clear highlight of
2017. This Egypt workstream, and the progress
in meeting the strong local gas demand, was
only one part of our determined operational
activity. The subsequent development and
appraisal drilling in Morocco towards the end
of the reporting period served as a fitting close
to a very significant year in the development of
our Company. Whilst the campaign in Morocco
is ongoing, the track record to date of success
with the drill bit is very encouraging indeed and
bodes well for the future. The progress that we
have made has been highly pleasing and it is
our clear intention to maintain this momentum
through 2018 and beyond.
06
SDX Energy Inc.
2017 Annual Report
Chief Executive’s Statement
2017 was a pivotal year for SDX Energy,
which saw the Company execute a highly value
accretive acquisition of a portfolio of oil and gas
production and exploration assets in Egypt and
Morocco, from Circle Oil plc. This was funded
by an oversubscribed $40 million share placing
with new and existing investors. The transaction
increased SDX’s total net working interest
production by over 200 percent to
approximately 4,705 barrels of oil per day
(“boep/d”), and its net working interest
2P reserves by 64 percent to 12.03 million
barrels of oil equivalent (“MMboe”).
We also enjoyed significant exploration success
throughout 2017 and finished the year with
a 100 percent success rate with the drill bit.
Our most significant discovery, during the
period, was at our SD-1X prospect at the
South Disouq concession in the Nile Delta area
of Egypt. In addition to a significant natural gas
discovery we also encountered a working
petroleum system within the deeper sections
of the target. Much of our focus for the
remainder of 2017 was on optimising the
development plan, putting together the
appraisal plan and tendering for all the
necessary surface equipment. The last part
of the activity, which is still ongoing, is getting
the development plan and gas sales contract
approved by the authority which we anticipate
will conclude in the first half of 2018. We plan
to drill two development wells in the SD-1X
discovery during 2018 together with two
exploration wells, Ibn Yunus-1X and Kelvin-1X,
which are targeting up to 150bcf and, if
successful, will be tied back to the SD-1X
processing facility. Success in these upcoming
wells will allow us to double our planned plateau
gas production rate from the SD-1x discovery
area from 50-100MMscfd.
In September, we successfully raised
US$10 million in an oversubscribed placing,
done at the closing mid-market price. The
placing enabled us to accelerate the exploration
and appraisal programme at South Disouq and
the development programme across our
Moroccan acreage, whilst retaining a prudent
level of liquidity.
I’m pleased to report that the Company remains
in strong financial standing and as at February
28, 2018 has a robust liquidity position of
US$30.6 million, with no debt. The acquisition
of Circle Oil’s assets began to bear fruit in the
second half of 2017, with net revenue
increasing by 204% by December 31, 2017.
By focusing on high margin low cost production,
we generated US$21.6 million of cash from
operating activities as at December 31, 2017
which was used to finance our development
and exploration activities across the portfolio.
We commenced our nine well drilling
programme in Morocco in September 2017,
which has yielded five discoveries from seven
wells drilled to date. The programme is on track
to allow us to deliver on our target of significantly
increasing local gas sales volumes in Morocco.
As a result we anticipate increasing our gross
production of conventional natural gas in
Morocco to 8-10mmscf/d, by the end of 2018.
In summary, 2017 was a year of successful
operational delivery combined with strong
capital discipline and a strict focus on costs.
We maintained our low operating costs of sub
US$10 per barrel production, whilst increasing
the Company’s net production profile from
1,196 boep/d to 3,237 boep/d (3,457 boep/d
had the acquisition of the Egyptian and
Moroccan businesses of Circle Oil completed on
January 1, 2017). We remain firmly committed
to our growth strategy and will continue to grow
our production profile via portfolio development
and acquisitions, if value accretive for shareholders.
I would like to finish by thanking our
shareholders, the staff, Board of Directors’ and
the wider SDX stakeholders for all their help and
assistance during what was a transformational
period for the Company.
Paul Welch
Chief Executive Officer
Strategy overview
SDX Energy’s strategy is simple:
“Create value through low cost
production growth”.
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Deliver increased
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Increase value
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Growth through
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acquisition
SDX Energy Inc.
2017 Annual Report 07
Review of Operations
North West Gemsa concession
Egypt Eastern Desert
The North West Gemsa concession
is located in the Eastern Desert,
300km southeast of Cairo.
Gulf of Suez
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AL OLA
Eastern
Desert
10KM
The concession is 83 km2 in area and includes three fields; Geyad,
Al Amir SE, and Al Ola (the southern extension of Al Amir SE).
All the fields are covered by development leases.
The fields are operated by PetroAmir, a joint operating company between
the partners and Ganoub El Wadi (a subsidiary of the Egyptian General
Petroleum Corporation). On January 27, 2017 SDX Energy acquired
Circle Oil plc’s interests in the North West Gemsa Concession, increasing
SDX Energy’s interest in the concession from 10% to 50% at present.
Zenhua Oil, the operator has the remaining 50%. The Al Amir SE and
Geyad fields produce light oil (40-42o API oil; sold at Brent less c10%)
from two reservoir intervals; the Miocene-aged Shagar and Rahmi
sandstones of the Kareem Formation. Production for the twelve months
ended December 31, 2017 averaged 4,440 boep/d (2,220 boep/d net to
SDX at a 50% interest level and assuming that the Circle Oil acquisition
completed on January 1, 2016) from the Al Amir SE and Geyad fields.
83km2
Concession area
2017 Activity
In North West Gemsa, the operator completed a 12 well workover
program only, with no new wells being drilled in 2017. The objective
of the workover program was to try and maintain production at 4,500
boep/d. The workover program was completed and after which
the work-over rig was released.
08
SDX Energy Inc.
2017 Annual Report
For more information please visit our website:
www.sdxenergy.com
Review of Operations
Block-H Meseda concession
Egypt Eastern Desert
Block-H is located in the Eastern Desert,
230km southeast of Cairo.
Trans Globe
open
HOSHIA
Trans Globe
open
open
H
Eastern Desert
HANA
South Hania
West Gharib
open
Trans Globe
Meseda
MESEDA
FADI
Trans Globe
5KM
Trans Globe
Trans Globe
open
K
Suez
Sinai
G
u
l
f
o
f
S
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M
open
Eastern
Desert
open
Trans Globe
Red Sea
The block is 22 km2 in area and is currently producing from the Meseda
field (which is covered by the Meseda-H development lease). The field
is covered by a production service agreement, which allows for lower cost
operations than the traditional joint venture structure. SDX Energy has
a 50% working interest, with Dublin International Petroleum,
the operator, holding the remaining 50% working interest.
The Meseda field produces from the high-quality Miocene-aged
Asl sands of the Rudeis Formation. Production for 2017 from
Meseda field averaged 3,091 bopd (595 bopd net to SDX Energy)
of 16-18o API oil.
22km2
Concession area
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2017 Activity
In 2017, significant activity was undertaken in the field on both the
surface and the sub-surface. The surface activity consisted of upgrading
the treatment capacity at the central processing facility from 10,000
barrels of fluid per day (“bfpd”) to 20,000 bfpd with the installation
of a new two-phase separator. Additional pump capacity was also added
to ensure that sufficient water volumes could be injected into the
waterflood. Throughout the year the operator completed nine workovers
which consisted of tubing and pump maintenance in the existing wells
aimed at ensuring future production uptime.
During 2017 the Company also participated in the drilling of two
exploration wells, Rabul 1 and 2 which were the final commitment wells
on the concession. Rabul 1 encountered 14.5 feet of net heavy oil pay
with an average porosity of 21.2% in the Yusr and was completed as an
oil producer in the Yusr. Rabul 2, encountered approximately 101.5 feet
of net heavy oil pay across the Yusr and Bakr sand formations, with an
average porosity of 20%. It was subsequently completed as an oil
producer in the Bakr. The company then participated with the operator
in completing a development plan for the newly discovered area that was
submitted and approved by the authority. The development plan consists
of two additional development well locations, surface facilities and a
short flowline to connect the Rabul area to the main Meseda Central
Processing Facility (“CPF”). The surface facility has been completed and
the two development locations will be drilled beginning in Q1 2018 with
Rabul 5 followed immediately by Rabul 4. All wells are expected to be
completed as oil producers in both the Yusr and Bakr formations
For more information please visit our website:
www.sdxenergy.com
SDX Energy Inc.
2017 Annual Report 09
Review of Operations
South Disouq concession
Egypt Nile Delta
South Disouq is a 1,275km2 concession
located 65km north of Cairo in the Nile
Delta region.
1,275km2
Concession area
Mediterranean Sea
Alexandria
South Disouq
Port Said
S
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a
l
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Desert
EGYPT
Red Sea
Cairo
Nile
Eastern
Desert
100KM
The concession is on trend with numerous, prolific gas fields in the
Abu Madi Formation. SDX Energy holds a 55% interest and operates
the concession, with its partner, IPR, holding the remaining 45% interest.
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SDX Energy Inc.
2017 Annual Report
2017 Activity
During the year the Company drilled a successful exploration well,
SD-1X, in the concession. The well found gas bearing sands in the
Abu Madi horizons, the primary target. The well also drilled into deeper
potentially oil bearing intervals beneath the main objective where it
encountered hydrocarbon shows. The deeper intervals could not be
logged and the results were considered inconclusive and an additional
well will be required to test this interval.
The SD-1X well was subsequently completed in the Abu Madi and flow
tested at a surface constrained rate of 25.8 MMscfd. After the successful
test the Company and its partners completed a development plan for the
area which was submitted to the authority, EGAS, for approval. The plan
consists of the drilling of two additional appraisal wells, the installation
of a rented central processing facility and the laying of a 10km pipeline
to the main export line out of the area. Concurrent with the development
plan, the Company also went to market with tenders for a drilling rig,
the construction of the 10km pipeline and the procurement of a rented
central processing facility. The Company plans to start up production,
from the SD-1X discovery, at a plateau production rate of approximately
50 MMscfd.
The tenders were evaluated and the rig tender awarded to Sin-Tharwa
for a 4 well program beginning in Q1 2018. The program consists of
two appraisal wells in the SD-1X structure and two additional exploration
wells in structures that offset the initial discovery. The other tenders are
still being evaluated and are expected to be awarded at the end of Q1
or early Q2 2018.
For more information please visit our website:
www.sdxenergy.com
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Review of Operations
South Ramadan concession
Egypt Gulf of Suez
The 26km2 South Ramadan development
concession is located in the offshore Gulf
of Suez, between the prolific Ramadan
and Morgan fields.
26km2
Concession area
Gulf of Suez
RAMADAN
South Ramadan
Eastern
Desert
JULY
Suez
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Red Sea
RAMADAN
MARINE
SOUTH
BADRI
MORGAN
Eastern
Desert
NESSIM
5KM
SDX Energy holds a 12.75% working interest, with Pico holding 37.25%,
and GPC holding the remaining 50%. The concession is considered
prospective for the Lower Cretaceous-aged Nubia sandstone and
has historical production from the Eocene-aged Thebes and Upper
Cretaceous-aged Matulla formations.
2017 Activity
During the year, the partners sought and obtained an extension
to the drilling commitment until October of 2018. The final sub-surface
technical work was completed along with a commercial evaluation.
The commercial evaluation looked at various options for development
and the partners selected an option that involved the drilling of a
development well up-dip of one the previous producers in the field.
This option was then submitted and approved by the authority.
The operator, Pico, then undertook a tendering exercise for all the related
drilling activities and services which is currently being evaluated. The well
will be drilled either early in the 2nd quarter or late in the 3rd quarter
of 2018 dependent upon rig availability.
For more information please visit our website:
www.sdxenergy.com
SDX Energy Inc.
2017 Annual Report 11
Review of Operations
Sebou, Lalla Mimouna & Gharb Centre concessions
Morocco Gharb basin
The Company’s Moroccan acreage
consists of three concessions all of which
are located in the Gharb Basin in
northern Morocco. The initial Moroccan
acreage was obtained as part of the
acquisition of Circle Oil’s assets in late
January of 2017. At the time of the
acquisition the acreage consisted of the
Sebou and Lalla Mimouna concessions
with the Gharb Centre concession being
acquired directly from the State in
June 2017.
Sebou
The Sebou concession is a 135km2 production concession with several smaller
producing leases contained within it:
•
•
•
•
Gueddari NW expiry: February 2, 2019
Gueddari Sud expiry: January 18, 2020
Sidi Al Harati SW expiry: September 20, 2023
Ksiri Central expiry: January 18, 2025
In April of 2017, SDX renewed the exploration area within the Sebou permit
for a period of eight years, with SDX committing to drill three exploration wells
within the first four-year period.
Lalla Mimouna
The Lalla Mimouna concession is a 2,211km2 permit that has had a very limited
amount of exploration activity undertaken on it. Circle Oil had previously acquired
approximately 140 km2 of 3D seismic on the concession and drilled two
unsuccessful wells. The Company is planning to drill two additional exploration
wells in late Q1/early Q2 2018. In Q1 2018 the permit expiry date was extended
to July 2018.
Larache
Atlantic
Ocean
MOROCCO
Algeria
Lalla Mimouna Nord
Mauritania
Mali
Lalla Mimouna
Atlantic
Ocean
Gharb Centre
Lalla Mimouna Sud
O u ed Seb o u
Oued Baht
Mechra Bel Ksiri
Exploration Licence
(Gharb Centre)
Exploration Licence
Exploitation Licence
3D Seismic Outline
Kenitra
e
e li n
P i p
Sebou
20 KM
135km2
2,211km2
Sebou concession area
Lalla Mimouna concession area
1,362km2
Gharb Centre concession area
Gharb Centre
The permit was acquired on June 1, 2017 for a period of eight years. It covers an
area of over 1362 km2, with a firm commitment to acquire 200km2 of 3D seismic
and to drill two exploration wells within the first four-year period.
2017 Activity to date
During the year the Company commenced its exploration and development
program in Morocco. The KSR-14 well was spud on the 18th of September which
was the first well of a nine well drilling programme on the Company’s Sebou,
Gharb Centre and Lalla Mimouna permits. From the commencement of the drilling
programme the Company was involved in the drilling of seven wells, the results
of which are as follows:
Permit Well Name Result Net Pay Test Rate
Sebou KSR-14 Gas Well 20.0m 6.40 MMscf/d
Sebou KSR-15 Gas Well 17.2m 7.52 MMscf/d
Sebou KSR-16 Gas Well 14.2m 8.43 MMscf/d
Gharb Centre ELQ-1* Uncommercial 2.0m Not Tested
Discovery
Sebou ONZ-7** Gas Well 5.0m 15.34 MMscf/d
Sebou KSS-2*** Dry Hole Nil Not Tested
Sebou SAH-2**** Gas Well 5.2m 13.45 MMscf/d
Well results announced *January 4, **January 15, ***February 21 and ****March 9, 2018
The drilling program will conclude in early Q2 2018 with the drilling of two
exploration wells in the Lalla Mimouna permit. In addition to the drilling activity
the Company completed a tendering exercise for a 240 km2 3D seismic survey
in its Gharb Centre permit. The 3D seismic survey acquisition was awarded
in November 2017 with the survey start-up planned for late Q2 2018.
12
SDX Energy Inc.
2017 Annual Report
For more information please visit our website:
www.sdxenergy.com
Reserves Summary
Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of Disclosure (“NI 51-101”). Under NI 51-101,
proved reserves are defined as reserves that can be estimated with a high degree of certainty to be recoverable with a target of a 90 percent probability
that the actual reserves recovered over time will equal or exceed proved reserve estimates, while probable reserves are defined as having an equal (50%)
probability that the actual reserves recovered will equal or exceed the proved and probable reserve estimates. In accordance with NI 51-101, proved
undeveloped reserves have been recognized in cases where plans are in place to bring the reserves on production within a short, well defined time frame.
Proved undeveloped reserves often involve infill drilling into existing pools. Of the net present value of the Company’s reserves, 100 percent were
evaluated by an independent third party engineer, ERC Equipoise, London UK (“ERCE”) in their report dated 20 March 2018.
Reserve Definitions:
• Proved reserves are those that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities
recovered will exceed the estimated Proved reserves.
• Proved Undeveloped reserves have been recognized in cases where plans are in place to bring the reserves on production within a short, well defined
time frame. Proved Undeveloped reserves often involve infill drilling into existing pools.
• Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of estimated proved plus probable.
• Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining
quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
The disclosures required in accordance with National Instrument 51-101 of the Canadian Securities Administrators are available within ERCE’s report dated
20 March 2018 filed on the SEDAR website at www.sedar.com.
Reconciliation of gross reserves as at December 31, 2017
Forecast prices and costs
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Light and Medium Oil Heavy Oil Conv. Natural Gas Natural Gas Liquids
(Mbbl) (Mbbl) (MMcf) (Mbbl)
Total Total Total Total
Gross(2) Gross(2) Gross(2) Gross(2) Gross(2) Gross(2) Gross(2) Gross(2) Gross(2) Gross(2) Gross(2) Gross(2)
Proved Proved Proved Proved
Proved Probable plus Proved Probable plus Proved Probable plus Proved plus
Probable Probable Probable Probable
Opening Balance(1)
December 31, 2016 331 172 504 4,125 1,325 5,450 303 162 465 6 5 11
Plus:
Extensions - - - - - - - - - - - -
Improved recovery - - - - - - - - - - - -
Technical revisions 779 613 1,391 (98) (261) (359) 1,156 (1,355) (199) 28 10 38
Discoveries - - - 438 367 805 15,171 8,130 23,300 56 54 111
Acquisitions 1,271 692 1,963 - - - 3,409 3,043 6,452 24 20 44
Less:
Dispositions - - - - - - - - - - - -
Economic factors - - - - - - - - - - - -
Production 666 - 666 682 - 682 1,800 - 1,800 18 - 18
Ending Balance
December 31, 2017 1,716 1,477 3,193 3,783 1,431 5,214 18,239 9,980 28,219 97 89 185
(1) Opening balances are from the Gaffney Cline & Associates reserve report as of December 31, 2016.
(2) Gross reserves are based on the Company working interest share of the property gross reserves.
The technical revisions in the Light and Medium Oil category reflect the impact of technical studies carried out by the field operator and SDX on the
recoverability potential of North West Gemsa. In the Heavy Oil category, the technical revision reflects a minor reduction on the impact of the waterflood
program in Meseda. The technical revision in the Conventional Natural Gas category is the normal reclassification between probable and proved categories
in the producing North West Gemsa and Morocco assets.
SDX Energy Inc.
2017 Annual Report 13
Reserves Summary
Summary of oil and gas reserves at December 31, 2017
Company’s Interest in Reserves(1)
Light & Medium Oil Heavy Oil Conv.Natural gas Natural Gas Liquids
(Mbbl) (Mbbl) (MMcf) (Mbbl)
Gross(3) Net(4) Gross(3) Net(4) Gross(3) Net(4) Gross(3) Net(4)
Egypt
Proved developed producing 830 427 3,530 1,352 581 315 19 10
Proved developed non–producing 587 302 - - 411 223 14 7
Proved undeveloped 299 154 254 96 14,163 7,991 63 37
Total Proved Reserves 1,716 883 3,783 1,448 15,154 8,529 97 54
Probable 1,477 760 1,431 546 8,362 4,698 89 50
Total Proved Plus Probable Reserves 3,193 1,643 5,214 1,994 23,516 13,226 185 104
Possible 2,000 1,029 2,237 850 11,547 6,488 129 72
Total Proved Plus Probable Plus Possible Reserves 5,193 2,673 7,451 2,844 35,063 19,714 314 176
Morocco
Proved developed producing - - - - 1,892 1,803 - -
Proved developed non–producing - - - - 1,192 1,130 - -
Proved undeveloped - - - - - - - -
Total Proved Reserves - - - - 3,084 2,933 - -
Probable - - - - 1,618 1,537 - -
Total Proved Plus Probable Reserves - - - - 4,703 4,469 - -
Possible - - - - 2,613 2,479 - -
Total Proved Plus Probable Plus Possible Reserves - - - - 7,316 6,948 - -
Total
Proved developed producing 830 427 3,530 1,352 2,473 2,118 19 10
Proved developed non–producing 587 302 - - 1,603 1,352 14 7
Proved undeveloped 299 154 254 96 14,163 7,991 63 37
Total Proved Reserves 1,716 883 3,783 1,448 18,239 11,461 97 54
Probable 1,477 760 1,431 546 9,980 6,234 89 50
Total Proved Plus Probable Reserves 3,193 1,643 5,214 1,994 28,219 17,696 185 104
Possible 2,000 1,029 2,237 850 14,160 8,967 129 72
Total Proved Plus Probable Plus Possible Reserves 5,193 2,673 7,451 2,844 42,378 26,662 314 176
(1) Totals may not add due to rounding.
(2) The definitions of the various categories of reserves and expenditures are those set out in NI 51-101.
(3) “Gross” reserves refer to SDX’s working interest share before deducting royalties and are based on their working interest share of the property gross resources.
(4) “Net” reserves refer to the gross reserves less royalties in Morocco and either the service fee or total cost and profit revenues in Egypt. Note, as the Egyptian government pays income taxes on behalf of SDX out of the
government's profit revenue share, the net reserves were based on the effective pre-tax profit revenues by adjusting for the tax rate.
14
SDX Energy Inc.
2017 Annual Report
Reserves Summary
Summary of net present values of future net revenues as of December 31, 2017
Forecast prices and costs (in US$ millions)
Net Present Values of Future Net Revenue(1)(2)(3)(4)(5)(6)(7)(8)
After Income Taxes Discounted at
0% 5% 10% 15%
(US MM$)
(US MM$) (US MM$) (US MM$)
20%
(US MM$)
Egypt
Proved developed producing 53 44 38 34 30
Proved developed non–producing 5 5 5 4 4
Proved undeveloped 6 5 5 4 3
Total Proved Reserves 65 55 47 42 37
Probable 53 42 35 30 26
Total Proved Plus Probable Reserves 118 97 82 71 63
Possible 85 67 54 45 38
Total Proved Plus Probable Plus Possible Reserves 203 164 136 116 101
Morocco
Proved developed producing 14 13 13 13 12
Proved developed non–producing 10 9 8 7 7
Proved undeveloped - - - - -
Total Proved Reserves 23 22 21 20 19
Probable 9 8 7 7 6
Total Proved Plus Probable Reserves 38 35 33 30 29
Possible 8 7 6 5 4
Total Proved Plus Probable Plus Possible Reserves 57 51 47 42 39
Total
Proved developed producing 67 58 51 46 43
Proved developed non-producing 15 14 13 12 11
Proved undeveloped 6 5 5 4 3
Total proved reserves 88 77 68 62 56
Probable 62 50 42 36 31
Total Proved Plus Probable Reserves 156 132 115 102 91
Possible 94 74 60 50 42
Total Proved Plus Probable Plus Possible Reserves 261 215 183 158 140
(1) Based on the Company working interest.
(2) Totals may not add due to rounding
(3) The definitions of the various categories of reserves and expenditures are thos set out in NI 51-101. Based n forecast prices and costs at January 1, 2018.
(4) Interest expenses and corporate overhead, etc. were not included.
(5) The net present values may not necessarily represent the fair market value for reserves.
(6) In Egypt the government pay income taxes on behalf of SDX out of the government’s profit revenue share and as such the before and after tax are identical.
(7) Unit values are calculated using estimated net present value of future net revenue before income taxes using a discount rate of 10% and the Company net reserves.
(8) Assumes 6 Mcf are equivalent to 1 bbl.
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SDX Energy Inc.
2017 Annual Report 15
Board of Directors
Michael Doyle
Non-Executive Chairman
Mr Doyle is a Professional Geophysicist and a Certified Corporate Director
with more than 35 years industry experience. Mr Doyle is a principal of
privately held CanPetro International Ltd and its affiliates. He has been
a director of Equal Energy Ltd since 1997.
David Richards
Non-Executive Director
Mr. Richards is a Fellow of the Institute of Chartered Accountants of
Alberta. He founded Network Capital Inc., a successful Calgary based
investment management company focused on private equity, in 1997
and served as President and Managing Director until June 30, 2016.
Mr Doyle was previously a principal and Chief Executive Officer of Petrel
Robertson Ltd where he was responsible for providing advice and project
management to clients throughout the world. Prior to that, he held a
variety of exploration positions at Dome Petroleum and Amoco Canada.
Mr Doyle holds a Bachelor of Science (Maths and Physics) from University
of Victoria.
Mr Richards formerly served as a senior tax partner with both
PricewaterhouseCoopers and Arthur Andersen and Co. He is a Past
President of the Alberta Chamber of Commerce and a past Vice President
of the Calgary Chamber of Commerce. Mr Richards is currently a director
of Standard Exploration Ltd. Previous public board experience includes
Boardwalk Equities, Forte Energy and Bonnetts Energy Services Trust.
Mr Doyle was a founding director and Chairman of Madison PetroGas
from its inception in 2003.
Paul Welch
President, Chief Executive Officer and Director
Mr Welch is an international energy executive with over 25 years of
industry experience having worked for Shell Oil Company and several large
independents including Hunt Oil Company, Pioneer Natural Resources and
most recently as CEO of AIM listed explorer Chariot Oil and Gas.
Mr Welch graduated from the Colorado School of Mines with both a
Bachelor and Master's degrees in Petroleum Engineering. He also holds an
MBA in Finance from the Southern Methodist University in Dallas, Texas.
Mr Welch was appointed CEO of Sea Dragon Energy in April 2013 and
became a CEO of SDX Energy following the merger with Madison
PetroGas in October 2015.
Mark Reid
Chief Financial Officer and Director
Mr Reid has over 20 years' experience in numerous sectors including the
Financial Services, Investment Banking and Oil and Gas industries. He has
had significant exposure to M&A transactions and the equity and debt
capital markets. Most recently, between 2009 and 2015 he was Finance
Director at AIM listed Aurelian Oil and Gas plc and Chariot Oil and Gas
Limited. Prior to this, he spent seven years as an Emerging Markets E&P
banker and was Head of Oil and Gas in the London office of BNP Paribas
Fortis. He has also spent seven years with Ernst & Young Corporate
Finance advising on M&A, IPO and other fundraising transactions.
Mr Reid has an MBA (Distinction) from Strathclyde University, is a
Member of the Institute of Chartered Accountants of Scotland, a Fellow
of the Chartered Association of Certified Accountants and a Member
of the Chartered Institute for Securities and Investment.
David Mitchell
Non-Executive Director
Mr Mitchell is a successful oil and gas executive with more than 35 years
proven track record in the international arena, including with BP and
Nexen.
During this time, Mr Mitchell discovered and built projects with his teams
in the Middle East, West Africa, Latin America and the North Sea. He has
lived and worked in a number of countries including a year with BP Egypt.
Mr Mitchell received his BSc Honours, Geology from the University of
London and his MPhil Mining Engineering from the University of
Nottingham, UK.
Michael Raynes
Non-Executive Director
Mr Raynes is the Managing Partner of MEA Energy Advisory UK LLP,
an Energy focussed investment advisory partnership, and a Director of
MEA Energy Investment Company Limited. MEA Energy Investment
Company Limited is a significant shareholder in SDX Energy Inc.
Previously Mr Raynes was the Chief Operating Officer of Waha Capital
with responsibility for all investing activity including Sales & Trading,
Private Equity, Infrastructure, Real Estate and Energy. He brings with him
an intricate understanding of investing in the Middle East and North Africa
and has established a strong track record of adding value to businesses
and generating strong returns for investors.
Mr Mitchell was appointed CEO of Madison PetroGas on joining in 2008,
building the company prior to the merger with Sea Dragon Energy.
Prior to Mr Raynes’ role at Waha Capital, he was a Senior Investment
Banker with Barclays Capital in London.
16
SDX Energy Inc.
2017 Annual Report
Remuneration Report
The remuneration of the directors for the year ended December 31, 2017 was as follows:
Note 3 (i)
Fees/ Cash bonus Cash bonus Benefits Restated Remuneration
basic salary 2016 (3) 2017 (3) Pension in kind Total 2017 Total 2016 Total 2017 Total 2016
US$ US$ US$ US$ US$ US$ US$ US$ US$
Paul Welch (1) 450,000 350,000 315,000 - 76,676 1,191,676 515,386 841,676 865,386
Mark Reid (2) 318,106 200,000 245,373 15,905 - 779,384 284,950 579,384 484,950
Michael Doyle (4) 59,849 - - - - 59,849 35,000
David Mitchell (4) 40,655 - - - - 40,655 30,000
David Richards (4) 42,318 - - - - 42,318 35,000
Michael Raynes (5) 30,030 - - - - 30,030 -
Barrie Wright (4) (6) - - - - - - 18,750
Paul Moase (6) - - - - - - 18,750
(1) Paul Welch was appointed President and Chief Executive Officer on April 12, 2013
(2) Mark Reid was appointed Chief Financial Officer on November 13, 2015 and was appointed as a director on September 26, 2016
(3) Up until 2017, given the early stage of the Company’s development, cash bonuses paid to the CEO and CFO were recognised only when paid as it was unclear whether bonuses would be awarded.
(3i) Note 3 (i) reflects the 2017 and 2016 remuneration with the impact of the 2017 and 2016 bonuses reflected in the years that they were accrued.
(4) Messrs. Doyle, Mitchell, Richards and Wright were appointed directors effective October 1, 2015 upon completion of the business combination between the Corporation and Madison Petrogas Ltd.
(5) Mr. Raynes was appointed as a director on September 26, 2016.
(6) Messrs Moase and Wright retired as directors on September 26, 2016.
Stock-based compensation
In 2017 the Company incurred share-based payment charges of US$417k in respect of the above named directors.
In 2016, it was determined that one of the inputs to the Black-Scholes option pricing model, specifically volatility of returns, required to be updated
following the business combination between Sea Dragon and Madison, with a US$0.1 million non-cash stock based compensation credit being recognized
for the twelve months ended December 31, 2016. As a result, for this period the Company did not incur any share-based payment charges in respect
of the above named directors.
Share options and LTIP units granted for directors who served during the year are as follows:
Options held at Granted Lapsed/forfeited
Options held at
January 1, 2017 during the year during the year December 31,2017
Executive directors
Paul Welch 800,000 770,0001
Mark Reid 400,000 555,5551
-
-
1,570,500
955,555
Non-executive directors
Michael Doyle 160,000 160,000 -
David Mitchell 160,000 160,000 -
David Richards 160,000 160,000 -
Michael Raynes - 160,000 -
320,000
320,000
320,000
160,000
(1) The units granted to Messrs. Welch and Reid were under the Corporation's Long Term Incentive Plan (“LTIP”).
See note 17 to the Consolidated Financial Statements for the year ended December 31, 2017 for further details.
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SDX Energy Inc.
2017 Annual Report 17
Corporate Governance Statement
General
The board of directors (the “Board”) of SDX Energy Inc.
(the “Corporation”) recognizes that good corporate governance
is of fundamental importance to the success of the Corporation.
The Corporation’s governance practices are the responsibility of the Board.
This Statement of Corporate Governance Practices sets out the Board’s
assessment of the Corporation’s governance practices in accordance with
National Instrument 58-101 – Disclosure of Corporate Governance
Practices (“NI 58-101”) and National Policy 58-201 – Corporate
Governance Guidelines (“NP 58-201”). The Corporation’s governance
practices are generally consistent with the practices and guidelines set
out in NI 58-101 and NP 58-201.
Board of Directors
The Corporation’s board of directors consists of six members namely
Michael Doyle, Paul Welch, David Mitchell, David Richards, Mark Reid
and Michael Raynes. The Board of Directors has reviewed the status of
each director to determine whether such director is “independent” as
defined in NI 58-101. As a result of such review, and after consideration
of all business, family and other relationships among the directors and the
Corporation, the Board of Directors has determined that Messrs. Doyle,
Mitchell, Richards and Raynes are each independent within the meaning
of NI 58-101. Messrs. Welch and Reid are not independent under
NI 58-101 as they continue to be officers of the Corporation.
Directorships
Directorships held by directors of the Corporation in other reporting issuers
are set forth below:
Director Directorships held
Michael Doyle Richmond Road Capital Corp.
David Richards Standard Exploration Ltd.
Orientation and continuing education
The Board of Directors is responsible for the orientation and education
of new members of the board of directors and all new directors are
provided with copies of the Corporation’s board and committee mandates
and policies, the Corporation’s by-laws, documents from recent Board
meetings and other reference materials relating to the duties and
obligations of directors, the business and operations of the Corporation.
New directors are also provided with opportunities for meeting and
discussions with senior management and other directors. Prior to joining
the board, each new director will meet with the Chief Executive Officer
of the Corporation. Such officer is responsible for outlining the business
and prospects of the Corporation, both positive and negative, with a view
to ensuring that the new director is properly informed to commence his
duties as a director. Each new director is also given the opportunity to
meet with the auditors and legal counsel to the Corporation. As part of
the annual Board of Directors’ assessment process, the Board of Directors
determines whether any additional education and training is required
for its members.
Ethical business conduct
The directors encourage and promote a culture of ethical business
conduct through communication and supervision as part of their overall
stewardship responsibility. In addition, the Corporation has adopted a
Code of Conduct which addresses the Corporation’s continuing
commitment to integrity and ethical behaviour. The Code of Conduct
establishes procedures that allow directors, officers and employees of the
Corporation to confidentially submit their concerns to the Chief Executive
Officer or the Chairman of the Board regarding questionable ethical, moral,
accounting or auditing matters, without fear of retaliation. To the
Corporation’s knowledge there have been no departures from this Code
of Conduct that would necessitate the filing of a material change report.
A copy of the Code of Conduct is available to review at the head office
of the Corporation during business hours.
Nomination of Directors
The Board of Directors as a whole is responsible for identifying suitable
candidates to be recommended for election to the Board by the
shareholders of the Corporation, with the goal of ensuring that the board
consists of an appropriate number of directors who collectively possess the
competencies identified as being appropriate to the effectiveness of the
board as a whole.
Compensation
The Compensation Committee is responsible for reviewing the
Corporation’s overall compensation strategy, and is responsible for
reviewing and recommending for approval the salaries and compensation
of the Corporation’s executive officers.
The Compensation Committee also reviews the compensation of the
non-executive directors on an annual basis, taking into account such
matters as time commitment, responsibility and compensation provided
by comparable organizations.
See page 15 for details of compensation paid to Directors during 2017.
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SDX Energy Inc.
2017 Annual Report
Reserves Committee
The board of directors has adopted a mandate for the Reserves
Committee, which is currently comprised of David Mitchell (Chair) and
Michael Doyle. The Reserves Committee is responsible for meeting with
the independent engineering firm commissioned to conduct the reserves
evaluation on the Corporation’s oil and gas assets and to discuss the results
of such evaluation with such independent evaluators and management.
The Reserves Committee’s responsibilities include reviewing management’s
recommendations for the appointment or proposed changes
of independent evaluators, reviewing the Corporation’s procedures
for providing information to the independent evaluators, meeting with
management and the independent evaluator to review the reserves
data and report, including any restrictions imposed by management
or significant issues on which there was a disagreement with management
and reviewing reserve additions and revisions which occur from one report
to the next, recommending to the board of directors whether to approve
the content of the independent evaluators’ report, reviewing the
Corporation’s procedures for reporting on other information associated
with oil and gas producing activities and generally reviewing all public
disclosure of estimates of the Corporation’s reserves. The Reserves
Committee meets at least once annually or otherwise as
circumstances warrant.
Assessments
The Compensation Committee is responsible for developing an annual
assessment of the overall performance of the Board and its committees.
The objective of this review is to contribute to a process of continuous
improvement in the Board’s execution of its responsibilities. To date, the
Compensation Committee and the Board have not put into place a formal
process for assessing the effectiveness of the board as a whole,
its committees or individual directors, but will consider implementing
one in the future should circumstances warrant. Based on the
Corporation’s size, its stage of development and the number of individuals
on the board of directors, the Compensation Committee and the Board
consider a formal assessment process to be inappropriate at this time.
The Compensation Committee and the Board plan to continue
evaluating the Board’s effectiveness on an ad hoc basis.
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Board Committees
The Corporation’s Board of Directors has three committees, the Audit
Committee, the Compensation Committee and the Reserves Committee.
Audit Committee
The Audit Committee consists of David Richards (Chair), Michael Doyle
and Michael Raynes. All members of the Audit Committee have been
determined to be independent, and all members are considered to be
financially literate, as such terms are defined in National Instrument
52 110 – Audit Committees (“NI 52 110”).
The Audit Committee of the Corporation is a committee of the Board
established for the purpose of overseeing the accounting and financial
reporting process of the Corporation. The Audit Committee has set out
its responsibilities and composition requirements in fulfilling its oversight
in relation to the Corporation’s internal accounting standards and practices,
financial information, accounting systems and procedures. See the
Company website, www.sdxenergy.com, for a copy of the Audit Committee
Terms of Reference.
The Corporation has not adopted specific policies and procedures for
the engagement of non-audit services, however, the duties of the Audit
Committee include the review and pre-approval of all non-audit services
to be provided by the external auditor’s firm or its affiliates (including
estimated fees) and the consideration of the effect of such services
on the independence of the external audit.
Compensation Committee
The Compensation Committee is comprised of Michael Raynes (Chair)
and David Mitchell. The Compensation Committee is comprised of non-
management members of the board of directors and is required to
convene at least annually.
The Compensation Committee exercises general responsibility regarding
the overall compensation policy for the senior employees and executive
officers of the Corporation. Subject to the approval of the Board, it is
responsible for: (i) recommending the salary and benefits of the Chief
Executive Officer, subject to terms of any existing contractual
arrangements; (ii) recommending the general compensation structure
and policies and programs for the Corporation and the salary and benefit
levels for the senior officers and management; (iii) reviewing the
Corporation’s stock option plan and Long Term Incentive Plan (“LTIP”)
and authorizing their use, determining the number of options/units,
and the terms thereof, that may be issued under the stock option plan and
LTIP plan of the Corporation during any particular period and issuing
or authorizing the award of such options/LTIPs in accordance with the
plan; (iv) reviewing and making recommendations to the Board on issues
that arise in relation to any employment contracts in force from time
to time; (v) reviewing annually all other benefit programs for salaried
personnel; (vi) reviewing and approving severance arrangements for senior
officers and management; (vii) reviewing the executive compensation
disclosure required to be included in the information circular for the
shareholders’ annual meeting; (viii) recommending the compensation
for members of the Board, as well as for committee members, including
the compensation of the Chairman of the Board and any chairman of a
Board committee; (ix) reviewing and making recommendations on the
succession plan for the Chief Executive Officer and for key employees
of the Corporation; and (x) reviewing and making recommendations
on any material changes in human resources policy, procedure,
remuneration and benefits.
SDX Energy Inc.
2017 Annual Report 19
Focused on North Africa
Egypt:
Morocco:
1. Multiple world class hydrocarbon basins
2. Excellent business environment
3. Low operating costs
1. Most competitive fiscal terms in the industry
2. High local gas prices
3. Dominant commercial position
Production
8,387
boe/d
Combined Egyptian daily average gross production
for the twelve months to December 31, 2017
Reserves
25.7
mmboe
Asset reserves (gross) - North West Gemsa, Meseda, South Disouq
and Morocco at December 31, 2017
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SDX Energy Inc.
2017 Annual Report 20
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Basis of Presentation
The following Management’s Discussion and Analysis (the “MD&A”) dated March 23, 2018 is a review of results of operations and the liquidity and capital
resources of SDX Energy Inc. (the “Company” or “SDX”), for the three and twelve months ended December 31, 2017. This MD&A should be read in
conjunction with the accompanying Consolidated Financial Statements for the year ended December 31, 2017.
For the purpose of calculating unit information, the Company's production and reserves are reported in barrels of oil equivalent (“boe”). Boe may be
misleading, particularly if used in isolation. A boe conversion ratio for natural gas of 6 Mcf (6 Thousand cubic feet): 1 boe has been used, which is based
on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead.
As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy
equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
As discussed in this MD&A, and in note 4 to the Consolidated Financial Statements, on January 27, 2017, the Company acquired the Egyptian and
Moroccan assets of Circle Oil plc. In order to provide the reader with a better understanding on the enlarged business, this MD&A contains certain
explanations where the performance of the Company has been analysed as if the acquisition had taken place on January 1, 2016 by using pro forma
figures. These are clearly denoted as being pro forma.
Certain information contained herein is forward-looking and based upon assumptions and anticipated results that are subject to risks, uncertainties
and other factors. Should one or more of these uncertainties materialize or should the underlying assumptions prove incorrect, actual results may
vary materially from those expected. See “Forward-looking statements”, below.
All financial references in this MD&A are in thousands of United States Dollars unless otherwise noted.
Additional information related to the Company can be found on SEDAR at www.sedar.com.
Forward-looking statements
Certain statements included or incorporated by reference in this MD&A constitute forward-looking statements or forward-looking information under
applicable securities legislation. Such forward-looking statements or information are for the purpose of providing information about Management’s current
expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as
making investment decisions. Forward-looking statements or information typically contain statements with words such as “anticipate”, “believe”, “expect”,
“plan”, “intend”, “estimate”, “propose”, “project” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking
statements or information in this MD&A include, but are not limited to, statements or information with respect to: business strategy and objectives;
development plans; exploration plans; acquisition and disposition plans and the timing thereof; reserve quantities and the discounted present value of
future net cash flows from such reserves; future production levels; capital expenditures; net revenue; operating and other costs; royalty rates and taxes.
Forward-looking statements or information are based on a number of factors and assumptions that have been used to develop such statements and
information but may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or
information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such
expectations will prove to be correct. In addition to other factors and assumptions that may be identified in this MD&A, assumptions have been made
regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the
Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in
a timely and cost-efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient
and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace
and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction
and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and
interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the countries in which the Company operates; and the
ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors
and assumptions that may have been used.
Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties
that could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information.
The risks and uncertainties that may cause actual results to differ materially from the forward-looking statements or information include, among other
things: the ability of Management to execute its business plan; general economic and business conditions; the risk of war or instability affecting countries
or states in which the Company operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing
crude oil and natural gas; market demand; the possibility that government policies or laws may change or governmental approvals may be delayed or
withheld; risks and uncertainties involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of
the Company to add production and reserves through acquisition, development and exploration activities; the Company’s ability to enter into or renew
production sharing concession; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the
uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and natural gas prices,
foreign currency exchange, and interest rates; risks inherent in the Company’s marketing operations, including credit risk; uncertainty in amounts and
timing of oil revenue payments; health, safety and environmental risks; risks associated with existing and potential future law suits and regulatory actions
against the Company; uncertainties as to the availability and cost of financing; and financial risks affecting the value of the Company’s investments.
Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties.
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SDX Energy Inc.
2017 Annual Report
Use of Estimates
The preparation of Consolidated Financial Statements in conformity with IFRS requires management to make estimates and assumptions based on
information available at the time. These estimates and assumptions affect the reported amounts of assets, particularly the recoverability of accounts
receivable and acquisition costs of property, plant and equipment. Estimates and assumptions also affect the recording of liabilities and contingent
liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.
Due to various factors affecting future costs and operations, actual results could differ from management’s best estimates.
Business Combination
On January 27, 2017 the Company acquired the Egyptian and Moroccan assets of Circle Oil plc.
In preparing the Consolidated Financial Statements the Company must conform with IFRS 3 – Business Combinations. This means that in the Consolidated
Financial Statements for the year ended December 31, 2017, the 2017 figures in the Consolidated Statement of Comprehensive Income relate to the
enlarged entity, whereas the 2016 comparatives contain twelve months of revenue and costs for the legacy SDX business only.
Non-IFRS measures
The MD&A contains the term “netback” which is not a recognized measure under IFRS. The Company uses this measure to help evaluate its performance.
Netback
Netback is a non-IFRS measure that represents sales net of all operating expenses and government royalties. Management believes that netback is a
useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business
activities prior to the consideration of other income and expenses. Management considers netback an important measure as it demonstrates the
Company’s profitability relative to current commodity prices. Netback may not be comparable to similar measures used by other companies. See netback
reconciliation to operating income in note 21 to the Consolidated Financial Statements.
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SDX Energy Inc.
2017 Annual Report 22
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
SDX’s business strategy and work program
SDX’s Business
SDX is engaged in the exploration, development and production of oil and gas. Current activities are concentrated in Egypt and Morocco, where the
Company has interests in seven concessions with short and long-term potential. The Company exited its operation in Cameroon on July 31, 2016. The
Company’s strategy is to develop the potential of its existing concessions while seeking growth opportunities within its North Africa region of focus. The
Company intends to create shareholder value by enhancing the value of its assets and through significant growth in production volumes, cash flow and
earnings.
Strategy
The Company’s strategy is to create value through organic and inorganic low cost production growth and, low cost, high impact exploration success. The
Company is underpinned by a portfolio of low cost onshore producing assets combined with onshore exploration prospects in Egypt and Morocco.
SDX intends to organically increase production and cash flow generation through an active work program consisting of workover, exploration and
development wells in its existing portfolio in Egypt and Morocco, combined with high impact exploration drilling in both countries. In pursuing this
strategy, SDX also intends to leverage its balance sheet, its early mover advantage and its regional network to grow through the acquisition of undervalued
and/or underperforming producing assets principally in onshore North Africa, while maintaining a strict financial discipline to ensure an efficient use of
funds. In January 2017, the Company acquired the Egyptian and Moroccan assets of Circle Oil plc for US$28.1 million after working capital adjustments
and raised US$40.0 million (before expenses) to fund this acquisition and to provide additional capital for investment into the enlarged group portfolio.
Further detail on this transaction can be found in note 4 to the Consolidated Financial Statements.
On June 1, 2017, the Company announced that it had been awarded the Gharb Centre exploration concession in Morocco with a 75% working interest.
The Company currently holds working interests (“W.I.”) in three development/producing concessions and one exploration concession in Egypt, and one
development/producing concession and two exploration concession in Morocco, being:
Egypt (development/producing) - The NW Gemsa Concession (“NW Gemsa”) – (10% W.I. up to January 27, 2017, 50% W.I. thereafter);
•
Egypt (development/producing) - The Block-H Meseda production service agreement (“Meseda”) – (50% W.I.);
•
Egypt (development) - The South Ramadan Concession (“South Ramadan”) – (12.75% W.I.);
•
•
Egypt (exploration) - The South Disouq Concession (“South Disouq”) – (55% W.I.);
• Morocco (development/producing) - The Sebou Concession (“Sebou”) – (75% W.I.);
• Morocco (exploration) - The Lalla Mimouna Concession (“Lalla Mimouna”) – (75% W.I.); and
• Morocco (exploration) - The Gharb Centre Concession (“Gharb Centre”) – (75% W.I.);
The Company assigned its interest in the Bakassi West Concession (“Bakassi West”) – (35% W.I.). to one of the partners in the concession effective July
31, 2016 and withdrew from the concession.
2018 Work program
The Company’s capital expenditure program for 2018 is expected to be approximately US$44.6 million, including the estimated costs of developing the
SD-1X discovery, which are still under review and subject to completion of tenders.
In North West Gemsa, the Company will be investing c.US$3.3 million and US$0.9 million respectively for its share of a two well drilling program and a
seven well workover program. This investment is targeting a 2018 production rate of 4,400 boep/d which is broadly in line with 2017 production levels. .
In Meseda, up to c.US$3.0 million be contributed for the Company’s share of the cost of drilling two wells to develop the Rabul discoveries and two wells
to maintain production in the wider Meseda area. In addition the Company is also planning to replace up to five ESPs. Overall this activity is hoped to
increase production to c 3,800 bopd in 2018 which is approximately 700 bopd higher than 2017 levels.
In South Disouq the Company plans to invest up to US$6.6 million for its share of a four well program to be carried out during 2018. The well program will
cover two exploration wells, Ibn Yunus and Kelvin, targeting up to 150 bcf in two separate structures and two development wells, SD-4X and SD-3X on
the existing SD-1X discovery. Upon success of SD-4X and SD-3X, the Company expects to complete a 10km pipeline, together with the establishment of
the SD-1X processing facility and is targeting first production in the second half of 2018. Depending on the results of the final tendering processes, SDX’s
share of the associated capex for the pipeline and processing facility will be cUS$8.25 million.
In South Ramadan in 2018, SDX expects to invest approximately US$3m for its share of one development well, some platform remediation work and a
potential work over on an adjacent well if the proposed development well is successful.
In Morocco, during 2018, the Company will complete the remaining two exploration wells, LNB-1 and LMS-1, of its nine well drilling program. Including
the costs of the outstanding 2017 drilling payables and associated customer connections projects, the Company expects to spend approximately US$13
million to complete the drilling program. In addition the Company plans to acquire 240km2 of 3D seismic on its Gharb Centre permit during 2018 at a cost
of cUS$6.5 million.
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SDX Energy Inc.
2017 Annual Report
Operational and financial highlights
In accordance with Canadian industry practice, production volumes and revenues are reported on a Company interest basis, before deduction of royalties.
Three months ended December 31 Twelve months ended December 31
$000’s unless stated Prior quarter (1) 2017 2016 2017 2016
NW Gemsa oil sales revenue 8,411 9,087 1,920 31,641 7,432
Royalties (3,610) (3,900) (824) (13,580) (3,190)
Net oil revenue 4,801 5,187 1,096 18,061 4,242
Block H Meseda production service fee revenues 1,845 2,276 1,945 8,045 6,359
Morocco gas sales revenue 3,214 3,646 - 12,425 -
Net other products revenue 264 (105) 2,313 635 2,313
Total net revenue 10,124 11,004 5,354 39,166 12,914
Operating costs (2,672) (2,526) (1,752) (10,254) (5,282)
Netback: NW Gemsa oil (2) 3,000 3,648 82 11,563 2,046
Netback: Block-H Meseda 1,233 1,619 1,207 5,377 3,273
Netback: Morocco gas 2,955 3,316 - 11,337 -
Netback: Other products (2) 264 (105) 2,313 635 2,313
Netback (pre-tax) 7,452 8,478 3,602 28,912 7,632
NW Gemsa oil sales (bbl/d) 1,893 1,710 468 1,733 534
Block-H Meseda production service fee (bbl/d) 551 561 679 595 662
Morocco gas sales (boe/d) 611 680 - 596 -
Other products sales (boe/d) 384 310 3,166 313 796
Total sales volumes (boe/d) 3,439 3,261 4,313 3,237 1,992
NW Gemsa oil sales volumes (bbls) 174,202 157,302 43,087 632,592 195,588
Block-H Meseda production service fee volumes (bbls) 50,674 51,599 62,504 217,135 242,146
Morocco gas sales volumes (boe) 56,219 62,543 - 217,655 -
Other products sales volumes (boe) 35,404 28,550 291,261 114,200 291,261
Total sales volumes (boe) 316,499 299,994 396,852 1,181,582 728,995
Brent oil price (US$/bbl) $52.07 $61.52 $49.23 $54.25 $41.70
West Gharib oil price ($US/bbl) $44.48 $53.59 $34.86 $45.37 $32.43
Realized NW Gemsa oil price (US$/bbl) $48.28 $57.77 $44.56 $50.02 $38.00
Realized Block-H Meseda service fee (US$/bbl) $36.41 $44.11 $31.12 $37.05 $26.26
Realized oil sales price and service fees (US$/bbl) $45.61 $54.39 $36.60 $46.70 $31.51
Realized Morocco gas price (US$/mcf) $9.53 $9.72 - $9.51 -
Total royalties (US$/boe) $11.94 $9.89 $6.33 $11.28 $7.47
Operating costs (US$/boe) $8.44 $8.42 $4.41 $8.68 $7.25
Netback (US$/boe) $23.54 $28.26 $9.08 $24.47 $10.47
Capital expenditures 3,423 15,302 856 21,040 13,339
(1) Three months ended September 30, 2017
(2) When calculating netback for NW Gemsa oil and Other products (NW Gemsa natural gas and NGLs), all NW Gemsa operating costs are allocated to oil, as natural gas and NGLs are associated products with assumed nil
incremental operating costs.
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SDX Energy Inc.
2017 Annual Report 24
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Operational and financial highlights (continued)
Net revenue overview
The overall US$26.3 million increase in Net revenues in the twelve months ended December 31, 2017 compared to the prior period in 2016 can be
explained as follows:
• US$27.1 million of the US$26.3 million increase relates to revenues of the acquired Circle Oil assets recognized from January 27, 2017 to
December 31, 2017 (US$14.7 million NW Gemsa (acquired 40% share); US$12.4 million Morocco);
• A US$1.7 million increase in SDX’s unchanged working interest in Block-H Meseda; partly offset by
• A decrease of US$2.5 million at SDX’s existing 10% share of NW Gemsa.
This movement is summarized below:
$000’s
Total net revenue nine months ended December 31, 2017 39,166
Total net revenue nine months ended December 31, 2016 12,914
Increase period on period 26,252
Attributable to:
Decrease in SDX’s 10% share of NW Gemsa (2,516)
Increase in SDX’s share of Block-H Meseda 1,686
Acquired 40% share of NW Gemsa 14,657
Acquired Moroccan gas business 12,425
Total increase period on period 26,252
Oil sales and production service fee revenues
Three months ended December 31 Twelve months ended December 31
$000’s
Prior quarter 2017 2016 2017 2016
Oil sales revenue 8,411 9,087 1,920 31,641 7,432
Production service fee revenues 1,845 2,276 1,945 8,045 6,359
Total oil sales and production service fees revenue 10,256 11,363 3,865 39,686 13,791
Oil sales revenues for the three and twelve months ended December 31, 2017 of US$9.1 million and US$31.6 million include US$7.8 million and US$24.8
million respectively relating to the acquisition from Circle Oil Plc which completed on January 27, 2017.
Oil sales revenue (relates to NW Gemsa only)
Oil sales volumes
Total oil sales volumes for the three and twelve months ended December 31, 2017 averaged 1,710 bbl/d and 1,733 bbl/d compared to 468 bbl/d and
534 bbl/d for the comparative periods of the prior year. Of these, 1,368 bbl/d and 1,358 bbl/d are due to the additional 40% share in the concession that
was acquired from Circle Oil plc.
Total sales volumes increased by 437,004 barrels, 223%, to 632,592 barrels in the twelve months ended December 31, 2017 compared to 195,588 barrels
in the comparative period of 2016. This net increase of 437,004 barrels can be explained by the 495,558 barrels from the additional 40% share of the
Concession that was acquired from Circle Oil and a like-for-like (i.e. 10% share) decrease of 58,554 barrels, 30%, due to natural reservoir decline. The NW
Gemsa concession reached peak production rate in Q4 2014 and volumes have now started to decline.
On a pro forma basis, assuming that the Circle Oil acquisition had occurred on January 1, 2016, sales volumes of 685,169 barrels (1,877 bbl/d) for the
twelve months ended December 31, 2017 compare to sales volumes of 977,940 (2,671 bbl/d) for the same period in 2016, a 30% reduction again due to
natural reservoir decline.
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SDX Energy Inc.
2017 Annual Report
Oil sales pricing
The Company is exposed to the volatility in commodity price markets for all of its oil sales and service fee volumes and changes in the foreign exchange
rate between the Egyptian pound and the US dollar for capital and operational expenditure. The Operational and Financial Highlights table in this MD&A
outlines the changes in various benchmark commodity prices and economic parameters which affect the prices received for the Company’s oil sales and
service fee volumes.
During the three and twelve months ended December 31, 2017 the Brent price ranged from a high of US$66.80 per barrel on December 28, 2017 to a low
of US$43.98 per barrel on June 20, 2017. The current oil price environment is due to the rebalancing of over-supply in the market particularly from OPEC
countries and US shale producers, the lifting of trade sanctions on Iran, and lower demand as a result of slower growth in large ‘consuming economies’
such as China. At this time, the Company does not hedge any of its production.
For the three and twelve months ended December 31, 2017, oil sales made by the Company achieved an average realized price per barrel of oil of
US$57.77 and US$50.02 respectively compared to the average Brent Oil price (“Brent”) for the periods of US$61.52 and $54.25; a discount of US$3.75,
6% per barrel and a discount of US$4.23, 8% per barrel respectively. The Company receives a discount to Brent due to the quality of the oil produced and
a further deduction is reflected in the realized price as a result of marketing fees. For the three and twelve months ended December 31, 2016, the
Company achieved average realized prices of US$44.56 and US$38.00 respectively.
Three months ended December 31 Twelve months ended December 31
$000’s
Prior quarter 2017 2016 2017 2016
Oil sales revenue ($'000s) 8,411 9,087 1,920 31,641 7,432
Per bbl ($/bbl) 48.28 57.77 44.56 50.02 38.00
Oil sales revenue variance from prior year
For the twelve months ended December 31, 2017 (compared to the twelve months ending December 31, 2016) oil sales revenue increased due to an
increase in sales price of US$7.6 million, 102%, and an increase in sales volume of US$16.6 million, 223%, due to the acquired additional 40% of the
concession, partly offset by natural reservoir decline.
$000’s
Twelve months ended December 31, 2016 7,432
Price variance 7,603
Production variance 16,606
Twelve months ended December 31, 2017 31,641
On a pro forma basis, assuming that the Circle Oil acquisition had occurred on January 1, 2016, the variance is as follows:
$000’s
Twelve months ended December 31, 2016 37,160
Price variance 8,235
Production variance (11,125)
Twelve months ended December 31, 2017 34,270
On this basis, a 30% reduction in sales volumes, driven by natural reservoir decline, is partly offset by improved pricing (22%), resulting in an overall 8%
reduction in oil sales revenue.
Oil sales revenue variance from prior quarter
For the three months ended December 31, 2017 (compared to the three months ended September 30, 2017) oil sales revenue increased by US$0.7
million, 8%, due to an increase in sales pricing of US$1.5 million, 18%, partly offset by reduced sales volume (US$0.8 million, 10%) due to natural
reservoir decline partly mitigated by well work overs.
$000’s
Three months ended September 30, 2017 8,411
Price variance 1,492
Production variance (816)
Three months ended December 31, 2017 9,087
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SDX Energy Inc.
2017 Annual Report 26
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Operational and financial highlights (continued)
Production service fees (relates to Meseda only)
Production service fee volumes
The Company began oil production from the Meseda area of Block H in late 2011, and records service fee revenue relating to the oil production that is
delivered to the State Oil Company (“GPC”). The Company is entitled to a service fee of between 19.0% and 19.25% of the delivered volumes and has a
50% working/paying interest. The service fee revenue is based on the current market price of West Gharib crude oil, adjusted for a quality differential.
Total production service fee volumes decreased by 10,905 barrels, 17%, to 51,599 barrels compared to the three months ended December 31, 2016.
Barrels produced per day decreased period on period by 118bbl/d to 561bbl/d, as during the current quarter several wells were taken off production due
to work-over program requirements. For the twelve months ended December 31, 2017 production service fee volumes decreased by 25,011 barrels
compared to the prior year, again due to the impact of work-overs.
Production service fee pricing
For the three and twelve months ended December 31, 2017 the Company received an average service fee per barrel of oil of US$44.11 and $37.05
respectively, compared to the average West Gharib prices for the period of US$53.59; a discount of US$9.48, 18%, per barrel and $45.37; a discount of
US$8.32, 18%, per barrel. The Company receives a discount to West Gharib due to the quality of the oil produced. For the three and twelve months ended
December 31, 2016, the Company received average service fees per barrel of oil of US$31.12 and US$26.26 respectively.
Three months ended December 31 Twelve months ended December 31
$000’s unless stated Prior quarter 2017 2016 2017 2016
Production service fee revenues ($'000s) 1,845 2,276 1,945 8,045 6,359
Per bbl ($/bbl) 36.41 44.11 31.12 37.05 26.26
Production service fee variance from prior year
For the twelve months ended December 31, 2017 (compared to the twelve months ended December 31, 2016) the increase in production service fee
revenue of US$1.7 million, 27%, to US$8.0 million is due to an increase in realized sales price, US$2.3 million, 37%, partially offset by lower production,
US$0.6 million, 10%.
$000’s
Twelve months ended December 31, 2016 6,359
Price variance 2,343
Production variance (657)
Twelve months ended December 31, 2017 8,045
Production service fee variance from prior quarter
For the three months ended December 31, 2017 (compared to the three months ended September 30, 2017) the increase in production service fee
revenue of US$0.4 million, 23%, is predominantly due to an increase in realized sales price (US$0.4 million, 22%).
$000’s
Three months ended September 30, 2017 1,845
Price variance 397
Production variance 34
Three months ended December 31, 2017 2,276
27
SDX Energy Inc.
2017 Annual Report
Morocco gas sales revenue
Three months ended December 31 Twelve months ended December 31
$000’s
Prior quarter 2017 2016 2017 2016
Morocco - Sebou 3,214 3,646 - 12,425 -
Per mcf ($/mcf) 9.53 9.72 - 9.51 -
Following the acquisition of the Moroccan assets of Circle Oil plc in January 2017, the Company sells natural gas to two industrial customers in Kenitra,
northern Morocco. During the period January 27, 2017 to December 31, 2017, the realized natural gas price was $9.51/mcf on sales volumes net to SDX
of 3.91mcf/d.
On a pro forma basis for the twelve months ended December 31, 2017, the natural gas sales price was $9.46/mcf on net sales volumes of 3.85mcf/d,
compared to $8.58/mcf on net sales volumes of 3.87mcf/d for the twelve months ended December 31, 2016. The period on period variance is due to
fluctuations in customer demand, and a pipeline outage in September 2016 which impacted sales to one customer.
Other products sales revenue
The Company sells associated gas and Natural Gas Liquids (“NGLs”) from its NW Gemsa concession to the Egyptian state. These sales commenced in
February 2013, with revenue recognized from February 2013 to September 2013 of that year. Subsequent to September 2013, the Company ceased
recognizing revenue due to a dispute with EGPC over entitlement volumes and pricing. During Q4 2016 this dispute was resolved such that outstanding
sales for the period October 1, 2013 and December 31, 2016 were recognized. These sales have continued to be recognized for the three and twelve
months ended December 31, 2017. In December 2017, the operator of the NW Gemsa concession advised that the invoices that it had issued were based
on erroneous volumes and prices and that the actuals were lower. The adjustment has been made during Q4 2017, with the portion relating to the
acquired Circle Oil receivables adjusted through the gain on acquisition (US$1.3 million), and the remainder through net revenue (US$0.3 million).
Royalties
Royalties fluctuate in Egypt from quarter to quarter due to changes in production and commodity prices impacting the amount of cost oil allocated to the
contractors and thereby impacting the calculation of profit oil from which royalties are calculated.
Royalties for crude oil sales per boe by concession are as follows:
Three months ended December 31 Twelve months ended December 31
per unit amounts Prior quarter 2017 2016 2017 2016
NW Gemsa 3,610 3,900 824 13,580 3,190
Total royalties (US$/boe) by concession 20.72 24.79 19.12 21.47 16.31
The Concession agreements allow for the recovery of operating and capital costs through a cost oil allocation which has an impact on the government
share of production as highlighted below (as at December 31, 2017 and December 31, 2016):
SDX’s Cost oil to Capital cost Operating cost Excess oil to Profit oil to
Concession WI (1) Contractors (2) recovered (2) recovered (2) Contractor (3) Contractor (4)
NW Gemsa (up to 10,000 BOPD Gross) 10% 30% 5 years Immediate Nil 16.1%
NW Gemsa (10,000 BOPD to 25,000 BOPD Gross) 10% 30% 5 years Immediate Nil 15.4%
NW Gemsa – Gas and LPG 10% 30% 5 years Immediate Nil 18.2%
(1) WI denotes the Company’s Working interest
(2) Cost oil is the amount of oil revenue that is attributable to SDX and its joint venture partners (the “Contractor”) subject to the limitation of the cost recovery pool. Oil revenue up to a specified percentage is available for recovery
by the Contractor for costs incurred in exploring and developing the concession. Operating costs and capital costs are added to a cost recovery pool (the “Cost Pool”). Capital costs for exploration and development expenditures
are amortized into the Cost Pool over a specified number of years with operating costs being added to the Cost Pool as incurred.
(3) If the costs in the Cost Pool are less than the cost oil attributable to the Contractor, the shortfall, referred to as excess cost oil (“Excess Oil”), reverts 100 percent to the State in NW Gemsa.
(4) Profit oil is the amount of oil revenue that is attributable to the Contractor.
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SDX Energy Inc.
2017 Annual Report 28
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Operational and financial highlights (continued)
Direct operating costs
The direct operating costs per concession were:
Three months ended December 31 Twelve months ended December 31
Prior quarter 2017 2016 2017 2016
$000’s
NW Gemsa 1,801 1,539 1,014 6,498 2,170
Block-H Meseda 612 657 737 2,668 3,086
Morocco - Sebou 259 330 - 1,088 -
Other
- - 1 - 26
Total direct operating costs 2,672 2,526 1,752 10,254 5,282
The direct operating costs per boe per concession were:
Three months ended December 31 Twelve months ended December 31
per unit amounts Prior quarter 2017 2016 2017 2016
NW Gemsa 8.48 8.28 3.03 8.70 4.46
Block-H Meseda 10.79 12.74 11.79 12.29 11.79
Morocco - Sebou 4.38 5.28 - 5.00 -
Total direct operating costs (US$/boe) per concession 8.44 8.42 4.41 8.68 7.25
Direct operating costs for the three and twelve months ended December 31, 2017 were US$2.5 million and US$10.3 million compared to US$1.8 million
and US$5.3 million for the comparative periods of the prior year. Prior quarter direct operating costs are US$0.2 million higher at US$2.7 million compared
to US$2.5 million for the three months to December 31, 2017.
NW Gemsa
NW Gemsa direct operating costs for the three and twelve months to December 31, 2017 were US$1.5 million and US$6.5 million, US$0.5 million and
US$4.3 million higher respectively than the comparative periods of the prior year. This variance is predominantly attributable to the additional 40% interest
in the concession acquired during the current year, partly offset by headcount reductions in the operation. Direct operating costs are $US0.3 million lower
than the prior quarter.
Block H-Meseda
Direct operating costs for the twelve months to December 31, 2017 for Block H-Meseda were US$0.4 million lower than the comparative period of the
prior year and were US$0.1 million higher than the prior quarter, in both instances due to production variances.
Morocco - Sebou
Direct operating costs for the period January 27, 2017 to December 31, 2017, for the Sebou concession, Morocco, were US$0.83/mcf, or US$5.00/bbl.
On a pro forma basis, assuming that the Circle Oil acquisition had occurred on January 1, 2016, direct operating costs for the twelve months ended
December 31, 2017 were US$0.87/mcf, versus US$0.45/mcf for the corresponding period in 2016. The primary driver for the increase period on period is
production bonuses (US$0.2 million) that have been incurred in 2017 but were not recognized in 2016.
Depletion, depreciation and amortization (“DD&A”)
For the twelve months ended December 31, 2017, depletion, depreciation and amortization (“DD&A”) was US$17.8 million compared to US$3.3 million in
the comparative period.
Twelve months ended December 31
$000’s except per unit amounts 2017 2016
Depletion, depreciation and amortization 17,824 3,266
15.08 4.48
Per bbl
The DD&A per concession was:
Twelve months ended December 31
$000’s
2017 2016
NW Gemsa 6,758 2,216
Block-H Meseda 1,094 1,010
Morocco - Sebou 9,885 -
Other
87 40
Total DD&A 17,824 3,266
29
SDX Energy Inc.
2017 Annual Report
General and administrative expenses
Twelve months ended December 31
$000’s
2017 2016
Wages and employee costs 6,513 2,532
Consultants - inc. PR/IR 699 479
Legal fees 332 237
Audit, tax and accounting services 641 246
Public company fees 365 332
Travel
382 166
Office expenses 1,092 668
IT expenses 303 322
Service recharges (3,907) (1,303)
Ongoing general and administrative expenses 6,420 3,679
Transaction costs 2,373 -
Total net G&A 8,793 3,679
General and administrative (“G&A”) costs for the twelve months ended December 31, 2017 were US$8.8 million compared to US$3.7 million for the
comparative period of the prior year; an increase of US$5.1 million, or 138%.
The increase of US$5.1 million is primarily due to the following:
•
higher wages and employee costs (US$4.0 million) due to payments and accruals made under the SDX employee bonus scheme of US$2.0 million,
including tax, which reflects the impact of both the 2017 and 2016 bonuses (which were determined and awarded in 2017), the Egyptian severance
costs (US$0.5 million), increased technical personnel headcount in London and Cairo (US$0.8 million), higher Egyptian salary taxes (US$0.1 million)
and staff costs at the acquired Rabat office (US$0.6 million);
higher consultancy fees (US$0.2 million) due to increased levels of corporate activity;
higher legal fees (US$0.1 million), higher audit (US$0.1 million) and tax fees (US$0.3 million) and higher travel costs (US$0.2 million) due
to the increased size of the group;
higher office expenses (US$0.4 million) due to the acquired Rabat office;
transaction costs from the Circle acquisition (US$2.4 million) associated with investment banking fees, legal and financial due diligence fees,
staff redundancy and public company filing requirements; and
greater service recharges ((US$2.6 million)) relating to the increase in cross charging of technical and administrative time spent by the Company
on its operating assets, in particular the drilling campaign in Morocco and drilling/development activity at South Disouq and the recovery of indirect
overhead recharges from concession partners.
•
•
•
•
•
Current taxes
Pursuant to the terms of the Company’s concession agreements for NW Gemsa, the 40.4% corporate tax liability of the joint venture partners is paid by
the government of Egypt controlled corporations (“Corporations”) out of the profit oil attributable to the Corporations, and not by the Company. For
accounting purposes, the corporate taxes paid by the Corporations are “grossed up in the financial statements” and included in net oil revenues and in
income tax expense thereby having a net neutral impact on Net Income.
The Company has a corporate tax liability in relation to its production service agreement for Block H-Meseda. The Company’s Egyptian subsidiary, Madison
Egypt Limited, is subject to corporate tax.
The current taxes per concession were:
Twelve months ended December 31
$000’s
2017 2016
NW Gemsa 3,551 1,272
Block-H Meseda 1,017 227
Morocco - Sebou - -
(27) -
Other
Total current taxes 4,541 1,499
Current taxes for the twelve months ended December 31, 2017 were US$4.5 million compared to US$1.5 million for the comparative period. The variance
is due to the acquisition of an additional 40% share in the NW Gemsa concession and improved profitability at both NW Gemsa and Block-H Meseda due
to the increase in sales realizations (pricing), as well as production variances.
SDX Energy Inc.
2017 Annual Report 30
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Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Operational and financial highlights (continued)
Net earnings
As per the Consolidated Financial Statements for the twelve months ended December 31, 2017, the Company recorded a Total Comprehensive Income of
US$28.3 million, compared to a Total Comprehensive Loss of US$28.0 million for the twelve months ended December 31, 2016; a difference of US$56.3 million.
The main components of this difference are:
•
an increase in net revenues of US$26.3 million as a result of the acquired Circle Oil assets and higher oil prices, offset by lower like-for-like production
at NW Gemsa and Block-H Meseda;
a US$29.6 million gain on acquisition of the Circle Oil assets;
a US$24.6 million reduction in exploration and evaluation expenditure. In the twelve months ended December 31, 2016 the Company wrote off its
capitalized expenditure on Bakassi West in Cameroon and withdrew from the Concession;
the absence of a US$4.3 million impairment expense recorded in respect of NW Gemsa in the twelve months ended December 31, 2016, offset by;
higher stock based compensation of US$0.6 million;
greater operating expenses (US$(5.0) million) and DD&A charge (US$(14.5) million) incurred by the enlarged business;
higher G&A expenses (US$(5.1) million) due to transaction costs, staff bonuses and the increased size of the Group; and
higher taxation expense (US$(3.0) million) mainly due to the introduction of the 40% of NW Gemsa from the acquisition from Circle Oil plc
and the increased profitability of the Group.
•
•
•
•
•
•
•
Capital expenditures
The following table shows the capital expenditure for the Company and agrees to the notes 9 and 10 to the Consolidated Financial Statements for the
period ended December 31, 2017, which include discussion therein.
Three months ended December 31 Twelve months ended December 31
$000’s
Prior quarter 2017 2016 2017 2016
Property, plant and equipment expenditures ("PP&E") 2,524 12,697 136 15,975 1,113
Exploration and evaluation expenditures ("E&E") 884 2,237 52 4,608 11,354
Office furniture and fixtures 15 368 - 457 15
Total capital expenditures 3,423 15,302 188 21,040 12,482
Decommissioning liability
December 31 December 31
$000’s
2017 2016
Decommissioning liability, beginning of period - -
Changes in estimate 625 -
Liabilities acquired through business combination 3,968 -
Payments for decommissioning (137)
Accretion 86 -
Decommissioning liability, end of period 4,542 -
Of which:
Current 1,063 -
Non-current 3,479 -
Carrying amount
For discussion of the Company’s decommissioning liability, see note 14 to the Consolidated Financial Statements for the year ended December 31, 2017.
31
SDX Energy Inc.
2017 Annual Report
Liquidity and capital resources
Share capital
The Company’s authorized share capital consists of an unlimited number of common shares and an unlimited number of preferred shares, issuable in one or
more series. The common shares of SDX trade on the TSX Venture Exchange and the AIM market of the London Stock Exchange under the symbol SDX.
Three months Twelve months
ended ended
December 31 December 31
$000’s
Prior quarter 2017 2017
High (CDN) $0.95 $0.99 $1.16
Low (CDN) $0.70 $0.80 $0.50
Average volume 101,245 105,327 87,030
The following table summarizes the outstanding common shares and options as at March 23, 2018, December 31, 2017 and December 31, 2016.
March 23 December 31 December 31
Outstanding as at: 2018 2017 2016
Common shares 204,493,040 204,493,040 79,843,902
Options (stock option plan) 2,851,667 2,851,667 2,445,000
Options (long term incentive plan) 7,214,506 3,449,461 -
The increase in Common shares as at December 31, 2017 relates to the Common shares issued on January 27, 2017 to fund the acquisition of Circle Oil
plc’s Egyptian and Moroccan assets (see further discussion elsewhere in this MD&A) and within note 4 to the Consolidated Financial Statements
(107,056k common shares), as well as an additional fund raising completed in September (17,559k common shares).
During the period, 640,000 stock options were issued to four non-executive Directors of the Company, 100,000 options lapsed and 100,000 options were
cancelled due to employees leaving the Company, 33,332 options were exercised.
The following table summarizes the outstanding stock option plan options as at December 31, 2017:
Outstanding options Vested options
Number of Remaining Number of Remaining
Exercise price range options contractual life options contractual life
CAD $0.39 - $0.76 2,851,667 3-5 years 2,395,000 3-5 years
Stock based compensation
Stock option program
The Company has a stock option program that entitles officers, directors, employees and certain consultants to purchase shares in the Company.
Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key
consultants of the Company. The fair value of all options granted is estimated using the Black-Scholes option pricing model. Each tranche in an award is
considered a separate award with its own vesting period and grant date fair value. Compensation cost is expensed over the vesting period with a
corresponding increase in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as
contributed surplus are recorded as share capital.
Long Term Incentive Plan (“LTIP”)
On July 31, 2017 the Company established a new Long Term Incentive Plan and issued awards to its Executive Directors and certain other key employees.
For further details see note 17 to the Consolidated Financial Statements.
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SDX Energy Inc.
2017 Annual Report 32
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Liquidity and capital resources (continued)
Capital resources
As at December 31, 2017 the Company had working capital of approximately US$46.7 million. The Company expects to fund its 2018 capital program
through funds generated from operations and cash on hand.
As at December 31, 2017, the Company had cash and cash equivalents of US$25.8 million compared to US$4.7 million as at December 31, 2016.
During the twelve months ended December 31, 2017 the Company had a net cash inflow US$21.1 million respectively (including the effects of foreign
exchange on cash and cash equivalents). For further detail, please see sources and uses table below.
As at December 31, 2017, the Company had US$37.7 million in trade and other receivables compared to US$9.5 million as at December 31, 2016.
Approximately US$25.6 million is due from a government of Egypt controlled corporation (“EGPC”) for oil sales, gas and NGL sales and production service
fees, all of which is expected to be received in the normal course of operations. The Company also had US$1.6 million related to the joint venture partner
account for the South Disouq concession.
US$3.6 million is owed by a Government of Morocco controlled corporation, Office National Hydrocarbures et des Mines (“ONHYM”), and relates to
ONHYM’s share of well completion and connection costs and production costs.
US$3.2 million is owing from third party gas customers in Morocco and is expected to be collected within agreed credit terms.
The other receivables of US$3.7 million consist of US$2.9 million related to prepayments predominantly associated with the Morocco and South Disouq
drilling campaign, US$0.3 million for Goods and Services Tax (“GST”)/ Value Added Tax (“VAT”) and US$0.5 million for other items.
Subsequent to December 31, 2017, the Company collected US$12.9 million of trade receivables from those that were outstanding at December 31, 2017;
US$7.9 million for NW Gemsa, US$2.8 million for Block-H Meseda and US$2.2 million from third party gas customers in Morocco.
The following table outlines the Company’s working capital. Working capital is defined as current assets less current liabilities, and includes drilling
inventory materials which may not be immediately monetized.
December 31 December 31
2017 2016
$000’s
Current assets
Cash and cash equivalents 25,844 4,725
Trade and other receivables 37,656 9,463
Inventory 5,157 1,698
Total current assets 68,657 15,886
Current liabilities
Trade and other payables 19,459 3,674
Deferred income 495 -
Decommissioning liability 1,063 -
Current income taxes 915 389
Total current liabilities 21,932 4,063
Working capital 46,725 11,823
33
SDX Energy Inc.
2017 Annual Report
The following table outlines the Company’s sources and uses of cash for the twelve months ended December 31, 2017 and 2016:
Twelve months ended December 31
$000’s
2017 2016
Sources
Operating cash flow before working capital movements 16,568 2,264
Issuance of common shares 48,510 10,127
Cash balance acquired during the period 3,108 -
Dividends received 760 825
Changes in non-cash working capital 5,412 -
Effect of foreign exchange on cash and cash equivalents 141 -
Total sources 74,499 13,216
Uses
Property, plant and equipment expenditures (21,132) (161)
Exploration and evaluation expenditures (3,785) (11,729)
Acquisition of subsidiaries (28,056) -
Finance costs paid (43) (96)
Income taxes paid (364) (766)
Changes in non-cash working capital - (3,440)
Effect of foreign exchange on cash and cash equivalents - (469)
Total uses (53,380) (16,661)
Increase/(decrease) in cash 21,119 (3,445)
Cash and cash equivalents at beginning of period 4,725 8,170
Cash and cash equivalents at end of period 25,844 4,725
The Company’s operating cash flow before working capital movements for the twelve months ended December 31, 2017 compared to the prior period
ended December 31, 2016 has increased by US$14.3 million primarily due to:
i)
an increase of US$26.3 million in net revenues as a result of the acquisition of the Egyptian and Moroccan assets of Circle Oil (US$27.1 million) in
2017, improved pricing at Block-H Meseda (US$1.7 million), and improved oil pricing offset by lower production attributable to the Company’s
existing share of NW Gemsa ((US$2.5 million));
ii) an increase in operating costs of US$5.0 million as a result of the Circle Oil acquisition, partly offset by production declines; and
iii) an increase in general and administrative costs in 2017 (US$5.1 million) due to Circle Oil transaction costs, the costs of the expanded business
and staff bonuses.
Financial instruments
The Company is exposed to financial risks due to the nature of its business and the financial assets and liabilities that it holds. The following discussion
reviews material financial risks, quantifies the associated exposures, and explains how these risks and the Company’s capital are managed.
Market risk
Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates could affect the Company’s
income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within
acceptable parameters, while optimizing the return.
Commodity price risk
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil
and natural gas are impacted by not only the relationship between the United States dollar and other currencies but also world economic events that
impact the perceived levels of supply and demand. The Company may hedge some oil and natural gas sales through the use of various financial derivative
forward sales contracts and physical sales contracts. In Egypt, the Company’s production is sold on the daily average price and in Morocco at contracted
prices. The Company may give consideration in certain circumstances to the appropriateness of entering into longer term, fixed price marketing contracts.
The Company will not enter into commodity contracts other than to meet the Company’s expected sale requirements.
At December 31, 2017 the Company did not have any outstanding derivatives in place.
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SDX Energy Inc.
2017 Annual Report 34
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Liquidity and capital resources (continued)
Financial instruments (continued)
Foreign currency risk
Currency risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The reporting and functional
currency of the Company is United States dollars (“US$”). Substantially all of the Company’s operations are in foreign jurisdictions and as a result, the
Company is exposed to foreign currency exchange rate risk on some of its activities, primarily on exchange fluctuations between the Egyptian Pound
(“EGP”) and the US$, the Moroccan Dirham (“MAD”) and the US$, and Sterling (“GBP”) and the US$. The majority of capital expenditures are incurred in
US$, EGP and MAD, and oil, natural gas, NGL and service fee revenues are received in US$, EGP and MAD. The Company is able to utilize EGP and MAD
to fund its Egyptian and Moroccan office general and administrative expenses and to part-pay cash requirements for both capital and operating
expenditure, therefore reducing the Company’s exposure to foreign exchange risk during the period.
The table below shows the Company’s exposure to foreign currencies for its financial instruments
Total per FS(1) US$ EGP GBP MAD Other
As at December 31, 2017 US$ Equivalent
Cash and cash equivalents 25,844 9,673 1,314 2,840 12,011 6
Trade and other receivables(2) 34,781 25,742 75 145 8,783 36
Trade and other payables (19,459) (12,606) (810) (315) (2,945) (2,783)
Current income taxes (915) - (915) - - -
Balance sheet exposure 40,215 22,809 (336) 2,670 17,849 (2,741)
(1) FS denotes Financial Statements
(2) Excludes prepayments
The average exchange rates during the three months ended December 31, 2017 and 2016 were 1 US$ equals:
Average: October 1, 2017 to December 31, 2017 Average: October 1, 2016 to December 30, 2016
USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD
Period average 17.7107 0.7537 9.4442 Period average 14.3634 0.8044 9.9607
The average exchange rates during the twelve months ended December 31, 2017 and 2016 were 1 US$ equals:
Average: January 1, 2017 to December 31, 2017 Average: January 1, 2016 to December 31, 2016
USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD
Period average 17.8534 0.7770 9.7047 Period average 10.0211 0.7405 9.8042
The exchange rates as at December 31, 2017 and 2016 were 1 US$ equals:
Period end: December 31, 2017 Period end: December 31, 2016
USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD
December 31, 2017 17.7875 0.7398 9.3519 December 31, 2016 18.1274 0.8113 10.1132
Trade and other payables
The foreign currency risk from a trade and other payables perspective arises due to the fact that the Company’s operations are conducted in Egypt and
Morocco and its corporate offices are in London and Canada with G&A and other listing and regulatory costs in both jurisdictions.
As at December 31, 2017 and December 31, 2016 the Company’s trade and other payables are as follows:
December 31
2016
$000’s
Trade payables 2,636 663
Accruals 9,536 684
Joint venture partners 5,686 1,743
Other payables 1,601 584
Total trade and other payables 19,459 3,674
December 31
2017
Carrying amount
For discussion of the Company’s trade and other payables, see note 12 to the Consolidated Financial Statements for the year ended December 31, 2017.
35
SDX Energy Inc.
2017 Annual Report
Management’s Discussion & Analysis
for the three and six months ended June 30, 2016
(prepared in US$)
Credit risk
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and
arises principally from the Company’s receivables from joint operations partners, oil and natural gas marketers, and cash held with banks. The maximum
exposure to credit risk at the end of the period is as follows:
December 31
$000’s
2016
Cash and cash equivalents 25,844 4,725
Trade and other receivables(1) 34,781 8,809
60,625 13,534
Total
December 31
2017
Carrying amount
(1) Excludes prepayments
Trade and other receivables:
All of the Company’s operations as at December 31, 2017 were conducted in Egypt and Morocco. The Company’s exposure to credit risk is influenced mainly
by the individual characteristics of each counter party. The Company does not anticipate any default as it expects continued payment from customers
against invoiced sales. Management has further considered the recoverability of the Company’s trade receivables balance alongside confirmations received
from EGPC and concession operators of amounts to be settled, as well as forecast use of EGP in operations, and do not consider it necessary to apply
discounting. The trade receivables balance and any updates to the conclusion over discounting will be monitored over the coming months.
The maximum exposure to credit risk for trade and other receivables at the reporting date by type of customer was:
December 31
$000’s
2016
Government of Egypt controlled corporations 25,582 7,745
Government of Morocco controlled corporations 3,597 -
Third party gas customers 3,175 -
Joint venture partners 1,586 578
Other(1)
841 486
Total trade and other receivables 34,781 8,809
December 31
2017
Carrying amount
(1) Excludes prepayments
As at December 31, 2017 and December 31, 2016, the Company’s trade and other receivables, excluding prepayments, are aged as follows:
December 31
$000’s
2016
Current (less than 90 days) 21,261 6,209
Past due (more than 90 days) 13,520 2,600
Total trade and other receivables 34,781 8,809
December 31
2017
Carrying amount
For discussion of the Company’s trade and other receivables, see note 6b to the Consolidated Financial Statements for the period ended
December 31, 2017.
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SDX Energy Inc.
2017 Annual Report 36
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Liquidity and capital resources (continued)
Financial instruments (continued)
Cash and cash equivalents:
The Company limits its exposure to credit risk by only investing in liquid securities and only with highly rated counterparties. The Company’s cash and cash
equivalents are currently held in established banks in either countries of operation or the UK, the majority of which have A or AA ratings. Given these
credit ratings, management does not expect any counterparty to fail to meet its obligations.
Capital management:
The Company defines and computes its capital as follows:
December 31
$000’s
2016
Equity 114,619 37,264
Working capital (1) (46,725) (11,823)
Total capital 67,894 25,441
December 31
2017
Carrying amount
(1) Working capital is defined as current assets less current libilities.
The Company’s objective when managing its capital is to ensure it has sufficient capital to maintain its ongoing operations, pursue the acquisition of
interests in producing or near to production oil and gas properties, and to maintain a flexible capital structure which optimizes the cost of capital at an
acceptable risk. The Company manages its capital structure and adjusts it, based on the funds available to the Company, in order to support the
exploration and development of its interests in its existing properties and to pursue other opportunities.
37
SDX Energy Inc.
2017 Annual Report
Accounting policies and estimates
The Company is required to make judgments, assumptions and estimates in the application of accounting policies that could have a significant impact on
our financial results. Actual results may differ from those estimates, and those differences may be material. The estimates and assumptions used are
subject to updates based on experience and the application of new information. The accounting policies and estimates are reviewed annually by the Audit
Committee of the Board. Further information on the basis of presentation and our significant accounting policies can be found in the notes to the
Consolidated Financial Statements and Annual MD&A for the year ended December 31, 2016.
Accounting policies
The accounting policies adopted are consistent with those of the previous financial year, except for the adoption of new standards and interpretations
effective January 1, 2017.
Further information on the accounting policies and estimates can be found in the notes to the Consolidated Financial Statements and MD&A for the three
and twelve months ended December 31, 2017.
Future changes in accounting policies
There are no updates to future changes in accounting policies during 2017.
Business risk assessment
There are a number of inherent business risks associated with oil and gas operations and development. Many of these risks are beyond the control of
management. The following outlines some of the principal risks and their potential impact to the Company.
Political Risk
SDX operates in Egypt and Morocco which have different political, economic and social systems compared to North America and which subject the
Company to a number of risks not within the control of the Company. Exploration or development activities in such countries may require protracted
negotiations with host governments, national oil companies and third parties and are frequently subject to economic and political considerations such as
taxation, nationalization, expropriation, inflation, currency fluctuations, increased regulation and approval requirements, corruption and the risk of actions
by terrorist or insurgent groups, changes in laws and policies governing operations of foreign-based companies, economic and legal sanctions and other
uncertainties arising from foreign governments, any of which could adversely affect the economics of exploration or development projects.
Financial Resources
The Company’s cash flow from operations may not be sufficient to fund its ongoing activities and implement its business plans. From time to time the
Company may enter into transactions to acquire assets or the shares of other companies. Depending on the future exploration and development plans, the
Company may require additional financing, which may not be available or, if available, may not be available on favorable terms. Failure to obtain such
financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or
terminate operations. If the revenues from the Company’s reserves decrease as a result of lower oil prices or otherwise, it will impact its ability to expend
the necessary capital to replace its reserves or to maintain its production. If cash flow from operations are not sufficient to satisfy capital expenditure
requirements, there can be no assurance that additional debt, equity, or asset dispositions will be available to meet these requirements or available on
acceptable terms. In addition, cash flow is influenced by factors which the Company cannot control, such as commodity prices, exchange rates, interest
rates and changes to existing government regulations and tax and royalty policies.
Exploration, Development and Production
The long-term success of SDX will depend on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. These risks are
mitigated by SDX through the use of skilled staff, focusing exploration efforts in areas in which the Company has existing knowledge and expertise or
access to such expertise, using up-to-date technology to enhance methods, and controlling costs to maximize returns. Despite these efforts, oil and
natural gas exploration involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to
overcome. There is no assurance that SDX will be able to locate satisfactory properties for acquisition or participation or that the Company’s expenditures
on future exploration will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to accurately project the costs of
implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering
various drilling conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and locations as a result of prior exploratory
wells or additional seismic data and interpretations thereof.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient
net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of
drilling, completion, infrastructure and operating costs. In addition, drilling hazards and/or environmental damage could greatly increase the costs of
operations and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining
governmental approvals or consents, shut-in of wells resulting from extreme weather conditions or natural disasters, insufficient transportation capacity or
other geological and mechanical conditions. As well, approved activities may be subject to limited access windows or deadlines which may cause delays or
additional costs. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production
delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to
varying degrees.
The nature of oil and gas operations exposes SDX to risks normally incident to the operation and development of oil and natural gas properties, including
encountering unexpected formations or pressures, blow-outs, and fires, all of which could result in personal injuries, loss of life and damage to the
property of the Company and others. The Company has both safety and environmental policies in place to protect its operators and employees, as well as
to meet the regulatory requirements in those areas where it operates. In addition, the Company has liability insurance policies in place, in such amounts as
it considers adequate. The Company will not be fully insured against all of these risks, nor are all such risks insurable.
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SDX Energy Inc.
2017 Annual Report 38
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Business risk assessment (continued)
Oil and Natural Gas Prices
The price of oil and natural gas will fluctuate based on factors beyond the Company’s control. These factors include demand for oil and natural gas, market
fluctuations, the ability of regional state-owned monopolies to control prices, the proximity and capacity of oil and natural gas pipelines and processing
equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and
exporting of oil and natural gas. Fluctuations in price will have a positive or negative effect on the revenue to be received by the Company.
Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids, reserves and cash flows to be derived there
from, including many factors beyond the Company’s control. In general, estimates of economically recoverable oil and natural gas reserves and the future
net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production
rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of
regulation by governmental agencies and future operating costs, all of which may vary from actual results. For those reasons, estimates of the
economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of
recovery and estimates of future net revenues expected there from prepared by different engineers, or by the same engineers at different times, may vary.
The Company’s actual production, revenues and development and operating expenditures with respect to its reserves will vary from estimates thereof and
such variations could be material.
Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar
types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production
history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated
reserves and such variations could be material.
The Company’s actual future net cash flows as estimated by independent reserve engineers will be affected by many factors which include, but are not
limited to: actual production levels; supply and demand for oil and natural gas; curtailments or increases in consumption by oil and natural gas purchasers;
changes in governmental regulation; taxation changes; the value of the Moroccan Dirham, British Pound, Egyptian Pound and US$; and the impact of
inflation on costs.
Actual production and cash flows derived there from will vary from the estimates contained in the applicable engineering reports. The reserve reports are
based in part on the assumed success of activities the Company intends to undertake in future years. The reserves and estimated cash flows to be derived there
from contained in the engineering reports will be reduced to the extent that such activities do not achieve the level of success assumed in the calculations.
Reliance on Operators and Key Employees
To the extent the Company is not the operator of its oil and natural gas properties, the Company will be dependent on such operators for the timing of
activities related to such properties and largely is unable to direct or control the activities of the operators. In addition, the success of the Company will be
largely dependent upon the performance of its management and key employees. The Company has no key-man insurance policies, and therefore there is a
risk that the death or departure of any member of management or any key employee could have a material adverse effect on the Company.
Government Regulations
The Company may be subject to various laws, regulations, regulatory actions and court decisions that can have negative effects on the Company. Changes
in the regulatory environment imposed upon the Company could adversely affect the ability of the Company to attain its corporate objectives. The current
exploration, development and production activities of the Company require certain permits and licenses from governmental agencies and such operations
are, and will be, governed by laws and regulations governing exploration, development and production, labor laws, waste disposal, land use, safety, and
other matters. There can be no assurance that all licenses and permits that the Company may require to carry out exploration and development of its
projects will be obtainable on reasonable terms or on a timely basis, or that such laws and regulation would not have an adverse effect on any project that
the Company may undertake.
Environmental Factors
All phases of the Company’s operations are subject to environmental regulation in Egypt and Morocco. Environmental legislation is evolving in a manner
which requires stricter standards and enforcement, increased fines, and penalties for non-compliance, more stringent environmental assessments of
proposed projects and a heightened degree of responsibility for companies and their officers, directors and employees.
Insurance
The Company’s involvement in the exploration for and development of oil and natural gas properties may result in the Company or its subsidiaries, as the
case may be, becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Prior to drilling, the Company or the
operator will obtain insurance in accordance with industry standards to address certain of these risks. However, such insurance has limitations on liability
that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable or, in certain
circumstances, the Company or its subsidiaries, as the case may be, may elect not to obtain insurance to deal with specific risks due to the high premiums
associated with such insurance or other reasons. The occurrence of a significant event that the Company may not be fully insured against, or the
insolvency of the insurer of such event, could have a material adverse effect on the Company’s financial position.
39
SDX Energy Inc.
2017 Annual Report
Regulatory Matters
The Company’s operations will be subject to a variety of federal and provincial or state laws and regulations, including income tax laws and laws and
regulations relating to the protection of the environment. The Company’s operations may require licenses from various governmental authorities and there
can be no assurance that the Company will be able to obtain all necessary licenses and permits that may be required to carry out planned exploration and
development projects.
Operating Hazards and Risks
Exploration for natural resources involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to
overcome. Operations in which the Company has a direct or indirect interest will be subject to all the hazards and risks normally incidental to exploration,
development and production of resources, any of which could result in work stoppages, damages to persons or property and possible environmental damage.
Although the Company has obtained liability insurance in an amount it considers adequate, the nature of these risks is such that liabilities might exceed
policy limits, the liabilities and hazards might not be insurable, or the Company might not elect to insure itself against such liabilities due to high premium
costs or other reasons, in which event the Company could incur significant costs that could have a material adverse effect upon its financial condition.
Repatriation of earnings
All of the Company’s production and earnings are generated in Egypt and Morocco. Currently there are no restrictions on foreign entities repatriating
earnings from Egypt. However, there can be no assurance that restrictions on repatriation of earnings from Egypt will not be imposed in the future. A
company can repatriate earnings from Morocco each year up to the limit of its retained earnings.
Disruptions in Production
Other factors affecting the production and sale of oil and gas that could result in decreases in profitability include: (i) expiration or termination of permits
or licenses, or sales price redeterminations or suspension of deliveries; (ii) future litigation; (iii) the timing and amount of insurance recoveries; (iv) work
stoppages or other labor difficulties; (v) changes in the market and general economic conditions, equipment replacement or repair, fires, civil unrest or
other unexpected geological conditions that can have a significant impact on operating results.
Foreign Investments
All of the Company’s oil and gas investments are located outside of Canada. These investments are subject to the risks associated with foreign investment
including tax increases, royalty increases, re-negotiation of contracts, currency exchange fluctuations and political uncertainty. The jurisdictions in which
the Company operates, Egypt and Morocco, have well-established fiscal regimes.
As operations are primarily carried out in US dollars, the main exposure to currency exchange fluctuations is the conversion to equivalent EGP, MAD and GBP.
Competition
The Company operates in the highly competitive areas of oil and gas exploration, development and acquisition with a substantial number of other
companies, including U.S.-based and foreign companies doing business in Egypt and Morocco. The Company faces intense competition from both major
and other independent oil and gas companies in seeking oil and gas exploration licences and production licences in Egypt and Morocco; and acquiring
desirable producing properties or new leases for future exploration.
The Company believes it has significant in-country relationships within the business community and government authorities needed to obtain cooperation
to execute projects.
Disclosure Controls and Procedures
As the Company is classified as a Venture Issuer under applicable Canadian securities legislation, it is required to file basic Chief Executive Officer and Chief
Financial Officer Certificates, which it has done for the period ended December 31, 2017. The Company makes no assessment relating to establishment
and maintenance of disclosure controls and procedures and internal controls over financial reporting as defined under Multilateral Instrument 52-109 as at
December 31, 2017.
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SDX Energy Inc.
2017 Annual Report 40
Management’s Discussion & Analysis
for the three and twelve months ended December 31, 2017
(prepared in US$)
Summary of quarterly results
Fiscal year 2017 2016
Financial $000’s Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q4
Cash, beginning of period 30,469 27,627 21,052 4,725 4,961 6,949 8,671 8,170
Cash, end of period 25,844 30,469 27,627 21,052 4,725 4,961 6,949 8,671
Working capital 46,725 58,397 43,048 40,039 11,823 9,593 8,232 5,414
Comprehensive income/(loss) (2,621) 4,408 (427) 26,947 (2,058) 140 (25,164) (883)
Net income/(loss) per share - basic (0.010) 0.022 (0.005) 0.172 (0.030) 0.002 (0.455) (0.02)
Capital expenditures 15,328 3,423 1,504 811 857 188 6,475 5,819
Total assets 141,057 138,898 132,766 132,794 41,617 43,901 47,231 64,907
Shareholders' equity 114,619 116,981 102,559 102,964 37,264 39,161 38,560 54,457
Common shares outstanding (000's) 204,493 204,459 186,900 186,900 79,844 79,844 75,934 37,642
41
SDX Energy Inc.
2017 Annual Report
Fiscal year 2017 2016
Operational Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q4
NW Gemsa oil sales (bbl/d) 1,710 1,893 1,832 1,493 468 510 554 606
Block H Meseda production service fee (bbl/d) 561 551 623 646 679 704 616 646
Morocco gas sales (boe/d) 680 611 651 441 - - - -
Other products sales (bbe/d) 310 384 419 286 3,166 - - -
Total boe/d 3,261 3,439 3,525 2,866 4,313 1,214 1,170 1,252
NW Gemsa oil sales volumes (bbls) 157,302 174,202 166,693 134,395 43,087 46,935 50,407 55,159
Block H Meseda production service fee volumes (bbls) 51,599 50,674 56,736 58,126 62,504 64,792 56,026 58,823
Morocco gas sales volumes (boe) 62,543 56,219 59,246 39,646 - - -
Other products sales volumes (boe) 28,550 35,404 38,143 25,832 291,261 - - -
Total sales and service fee volumes (boe) 299,994 316,499 320,818 257,999 396,852 111,727 106,433 113,982
Brent oil price (US$/bbl) 61.52 52.07 49.68 53.64 49.23 45.78 45.54 33.73
West Gharib oil price (US$/bbl) 53.59 44.48 41.50 41.93 38.07 34.86 30.38 25.65
Realized oil price (US$/bbl) 57.77 48.28 45.56 48.73 44.56 40.84 39.90 28.69
Realized service fee (US$/bbl) 44.11 36.41 33.98 34.34 31.12 28.32 24.51 20.49
Realised oil sales price and service fees 54.39 45.61 42.62 44.38 36.60 33.58 31.80 24.46
Realized Morocco gas price (US$/mcf) 9.72 9.53 9.44 9.29 - - - -
Royalties (US$/boe) 9.89 11.94 10.71 11.37 6.33 7.37 8.11 5.96
Operating costs (US$/boe) 8.42 8.44 9.38 7.94 4.41 11.11 12.12 8.77
Netback - (US$/boe) 28.26 23.54 21.48 23.60 9.08 15.10 11.56 9.73
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SDX Energy Inc.
2017 Annual Report 42
Low cost, high margin production
The stable and sustainable low cost of operations
ensures SDX Energy will be a significant beneficiary of
the eventual increase in commodity pricing.
Production
8,387
boe/d
Combined Egyptian daily average gross production
for the twelve months to December 31, 2017
Reserves
25.7
mmboe
Asset reserves (gross) - North West Gemsa, Meseda, South Disouq
and Morocco at December 31, 2017
43
SDX Energy Inc.
2017 Annual Report
Independent Auditor’s Report
To the Shareholders of SDX Energy Inc.
We have audited the accompanying consolidated financial statements of SDX Energy Inc. and its subsidiaries, which comprise the Consolidated Balance
Sheet as at December 31, 2017 and December 31, 2016, the Consolidated Statement of Comprehensive Income, the Consolidated Statement of Changes
in Equity and Consolidated Statement of Cash Flows for the years then ended, and the related notes, which comprise 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 audit. We conducted our audit 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 SDX Energy Inc. and its subsidiaries as
at December 31, 2017 and December 31, 2016 and their financial performance and their cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Accountants
PricewaterhouseCoopers LLP
431 Union Street
Aberdeen
AB11 6DA
March 23, 2018
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SDX Energy Inc.
2017 Annual Report 44
Consolidated Balance Sheet
as at December 31, 2017 and 2016
As at As at
December 31 December 31
(thousands of United States dollars) Note 2017 2016
Assets
Cash and cash equivalents 7 25,844 4,725
Trade and other receivables 6b 37,656 9,463
Inventory 8 5,157 1,698
Current assets 68,657 15,886
Investments 11 2,724 2,503
Property, plant and equipment 9 54,445 12,605
Intangible exploration and evaluation assets 10 15,231 10,623
Non-current assets 72,400 25,731
Total assets 141,057 41,617
Liabilities
Trade and other payables 12 19,459 3,674
Deferred income 13 495 -
Decommissioning liability 14 1,063 -
Current income taxes 15 915 389
Current liabilities 21,932 4,063
Deferred income 13 737 -
Decommissioning liability 14 3,479 -
Deferred income taxes 15 290 290
Non-current liabilities 4,506 290
Total liabilities 26,438 4,353
Equity
Share capital 16 88,785 40,275
Warrants 16 - -
Contributed surplus 5,666 5,128
Accumulated other comprehensive loss (888) (917)
Retained earnings/(accumulated loss) 21,056 (7,222)
Total equity 114,619 37,264
Equity and liabilities 141,057 41,617
The notes are an integral part of these Consolidated Financial Statements.
The financial statements on pages 45 to 71 were approved by the Board of Directors on March 23, 2018 and signed on its behalf by:
Paul Welch Mark Reid
Chief Executive Officer Chief Financial Officer
45
SDX Energy Inc.
2017 Annual Report
Consolidated Statement of Comprehensive Income
for the years ended December 31, 2017 and 2016
Twelve months ended December 31
(thousands of United States dollars) Note 2017 2016
Revenue, net of royalties 18 39,166 12,914
Direct operating expense (10,254) (5,282)
Gross profit 28,912 7,632
Exploration and evaluation expense (187) (24,833)
Depletion, depreciation and amortisation 9 (17,824) (3,266)
Impairment expense 9 - (4,303)
Reversal of inventory provision 8 798 479
Stock based compensation 17 (538) 47
Share of profit from joint venture 11 1,022 1,222
General and administrative expenses
- Ongoing general and administrative expenses 19 (6,420) (3,679)
- Transaction costs 19 (2,373) -
Operating income/(loss) 3,390 (26,701)
Net finance (expense)/income (129) 4
Gain on acquisition 4 29,558 -
Income/(loss) before income taxes 32,819 (26,697)
Current income tax expense 15 (4,541) (1,499)
Deferred income tax expense 15 - (4)
Total current and deferred income tax expense (4,541) (1,503)
Net income/(loss) 28,278 (28,200)
Other comprehensive income
Foreign exchange 29 237
Total comprehensive income/(loss) for the period 28,307 (27,963)
Net income/(loss) per share
Basic
20 $0.153 $(0.394)
Diluted 20 $0.151 $(0.394)
The notes are an integral part of these Consolidated Financial Statements.
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Consolidated Statement of Changes in Equity
for the years ended December 31, 2017 and 2016
Twelve months ended December 31
(thousands of United States dollars) Note 2017 2016
Share capital
Balance, beginning of period 16 40,275 30,148
Issuance of common shares 16 49,589 10,988
Share issue costs 16 (1,079) (861)
Balance, end of period 88,785 40,275
Warrants
Balance, beginning of period - 99
Expiry of warrants - (99)
Balance, end of period - -
Contributed surplus
Balance, beginning of period 5,128 5,175
Share based payments for the period 538 (47)
Balance, end of period 5,666 5,128
Accumulated other comprehensive loss
Balance, beginning of period (917) (1,154)
Foreign currency translation adjustment for the period 29 237
Balance, end of period (888) (917)
Retained earnings/(accumulated loss)
Balance, beginning of period (7,222) 20,978
Net income/(loss) for the period 28,278 (28,200)
Balance, end of period 21,056 (7,222)
Total equity 114,619 37,264
The notes are an integral part of these Consolidated Financial Statements.
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2017 Annual Report
Consolidated Statement of Cash Flows
for the years ended December 31, 2017 and 2016
Twelve months ended December 31
(thousands of United States dollars) 2017 2016
Cash flows generated from/(used in) operating activities
Income/(loss) before income taxes 32,819 (26,697)
Adjustments for:
Depletion, depreciation and amortization 9 17,824 3,266
Exploration and evaluation expense 10 187 24,416
Impairment expense 9 - 4,303
Reversal of inventory provision 8 (798) (479)
Finance expense/(income) 129 (4)
Stock based compensation 17 538 (47)
Gain on acquisition 4 (29,558) -
Tax paid by State 15 (3,551) (1,272)
Share of profit from joint venture 11 (1,022) (1,222)
Operating cash flow before working capital movements 16,568 2,264
Decrease/(increase) in trade and other receivables 6b 4,871 (3,001)
Decrease/(increase) in trade and other payables 12 2,496 (408)
Increase in inventory 8 (1,951) (31)
Payments for decommissioning 14 (4) -
Cash generated from/(used in) operating activities 21,980 (1,176)
Income taxes paid 15 (364) (766)
Net cash generated from/(used in) operating activities 21,616 (1,942)
Cash flows (used in)/generated from investing activities:
Property, plant and equipment expenditures 9 (21,132) (161)
Exploration and evaluation expenditures 10 (3,785) (11,729)
Dividends received 11 760 825
Acquisition of subsidiaries 4 (28,056) -
Cash balance acquired during the period 4 3,108 -
Net cash used in investing activities (49,105) (11,065)
Cash flows generated from/(used in) financing activities:
Issuance of common shares 16 48,510 10,127
Finance costs paid (43) (96)
Net cash generated from financing activities 48,467 10,031
Increase/(decrease) in cash and cash equivalents 20,978 (2,976)
Effect of foreign exchange on cash and cash equivalents 141 (469)
Cash and cash equivalents, beginning of period 4,725 8,170
Cash and cash equivalents, end of period 25,844 4,725
The notes are an integral part of these Consolidated Financial Statements.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
1. Reporting entity
SDX Energy Inc. (“SDX” or “the Company”) is a company domiciled in Canada. The address of the Company’s registered office is 1900, 520 – 3rd Avenue
SW, Centennial Place, East Tower, Calgary, Alberta T2P 0R3. The Consolidated Financial Statements of the Company as at and for the years ended
December 31, 2017 and 2016 comprise the Company and its wholly owned subsidiaries and include the Company’s share of joint arrangements as
explained in note 11 below (together the “Group”). As described in note 4 to the Consolidated Financial Statements, on January 27, 2017,
the Company acquired the Egyptian and Moroccan assets of Circle Oil plc.
The Company is engaged in the exploration for and development and production of oil and natural gas. The Company’s principle properties are located
in the Arab Republic of Egypt and the Kingdom of Morocco.
The Company’s share trade on the Toronto Venture Stock Exchange (“TSX-V”) in Canada and on the London Stock Exchange’s Alternative Investment
Market (“AIM”) in the United Kingdom under the symbol “SDX”.
2. Basis of preparation
(a) Statement of compliance
The Consolidated Financial Statements of the Company have been prepared in accordance with International Financial Reporting Standards as issued
by the International Accounting Standards Board (“IASB”) and with IFRS Interpretations Committee (“IFRS IC”) interpretations. These accounting
standards and interpretations are collectively referred to as “IFRS” in this report.
The accounting policies that follow set out those policies that apply in preparing the Consolidated Financial Statements for the year ended
December 31, 2017. The policies applied are based on IFRS issued and outstanding as of March 23, 2018.
(b) Basis of measurement
The Consolidated Financial Statements have been prepared on the historical cost basis.
(c) Functional and presentation currency
The functional currency for each entity in the Group, and for joint arrangements and associates, is the currency of the primary economic environment
in which that entity operates. Transactions denominated in other currencies are converted to the functional currency at the exchange rate ruling at the
date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at year-end exchange rates.
The Group’s financial statements are presented in US dollars, as that presentation currency most reliably reflects the business performance of the
Group as a whole. On consolidation, income statement items for each entity are translated from the functional currency into US dollars at average
rates of exchange where the average is a reasonable approximation of rates prevailing on the transaction date. Balance sheet items are translated
into US dollars at period-end exchange rates.
(d) Use of estimates and judgments
The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the
application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates
and affect the results reported in these Consolidated Financial Statements. Estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.
Purchase price allocations, depletion, depreciation and amortization, and amounts used in impairment calculations are based on estimates of crude oil
and natural gas reserves. Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing
of future capital expenditures, all of which are subject to many uncertainties, interpretations and judgements. The Company expects that, over time,
its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production
levels, and may be affected by changes in commodity prices.
In accounting for property, plant and equipment, during the drilling of oil and gas wells, at period end it is necessary to estimate the value of work done
(“VOWD”) for any unbilled goods and services provided by contractors.
The invoicing of produced crude oil, natural gas and Natural Gas Liquids is, for non-operated concessions, performed by the Company’s joint venture
partners. In certain concessions, the operator is reliant on production and/or price information from other third parties, which may not be consistently
prepared and received on a timely basis. In such instances, the Company may be required to estimate production volumes and/or prices based upon
the most robust available data.
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(e) Going concern
The Directors have reviewed the Company’s forecast cash flows for the next twelve months from the date of publication of this Annual Report and
through until December 31, 2019. The capital expenditure and operating costs used in these forecast cash flows are based on the Company’s Board
approved 2018 SDX corporate budget which reflects approved operating budgets for each of its operating assets and an estimate of 2019 SDX
corporate general and administrative expenses. The Company’s forecast cash flows also reflect its best estimate of operational and corporate
expenditure, including corporate general and administrative costs for the year to December 31, 2019. The Directors have made enquiries into and
considered the Egyptian business environment, future expectations regarding commodity price risk and, in particular, oil price risk given the volatility
in quoted Brent and WTI crude oil prices.
Having considered these sensitivities and potential outcomes relating to:
(i) country and commodity price risks;
(ii) the Company’s ability to change the timing and scale of discretionary capital expenditure;
(iii) the Company’s ability to manage operating costs; and
(iv) the Company’s ability to manage general and administrative costs.
The Directors consider that in a lower cost environment the Company has sufficient resources at its disposal to continue for the foreseeable future.
The foreseeable future is defined as not being less than twelve months from the date of publication of the 2017 Annual Report.
Given the above, these Consolidated Financial Statements continue to be prepared under the going concern basis of accounting.
3. Significant accounting policies
The accounting policies set out below have been applied consistently to all years presented in these Consolidated Financial Statements and have been
applied consistently by the Company and its subsidiaries.
(a) Basis of consolidation
(i) Subsidiaries
Subsidiaries are entities controlled by the Company. Control exists where the Company has: power over the entities, that is existing rights that give
it the current ability to direct the relevant activities of the entities (those that significantly affect the Companies’ returns); exposure, or rights, to
variable returns from its involvement with the entities; and the ability to use its power to affect those returns. Subsidiaries are fully consolidated
from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases.
(ii) Joint arrangements
A joint arrangement is an arrangement of which two or more parties have joint control. Joint control is the contractually agreed sharing of control
such that decisions about the relevant activities of the arrangement (those that significantly affect the Companies’ returns) require the unanimous
consent of the parties sharing control. The Company has one joint arrangement, being its 50% equity interest in Brentford Oil Tools LLC
(“Brentford”). As the parties sharing joint control in this entity have rights to its net assets, the arrangement constitutes a joint venture and is
accounted for using the equity accounting method. Under the equity method of accounting, the investment in Brentford was initially recognized
at cost and adjusted thereafter for the post-acquisition change in the net assets. The Company’s Consolidated Statement of Comprehensive
Income includes its share of Brentford’s profit or loss. The Company’s other comprehensive income includes its share of Brentford’s other
comprehensive income. Dividends received or receivable from Brentford are recognized as a reduction in the carrying amount of the investment.
(iii) Investments in associates
An associate is an entity over which the Company has significant influence, and is equity accounted for.
(iv) Transactions eliminated on consolidation
Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions are eliminated
in preparing the Consolidated Financial Statements.
(b) Foreign currency
Transactions in foreign currencies are translated to United States dollars at exchange rates at the dates of the transactions. Monetary assets
and liabilities denominated in foreign currencies are translated to United States dollars at the period end exchange rate.
(c) Financial instruments
(i) Non-derivative financial instruments
Non-derivative financial instruments comprise of trade and other receivables, cash and cash equivalents, and trade and other payables.
Non-derivative financial instruments are recognized initially at fair value. Subsequent to initial recognition non-derivative financial instruments
are measured as described below.
Financial assets and liabilities are recognized when the Company becomes party to the contractual provisions of the instrument. Financial assets
are derecognized when the rights to receive cash flows from the assets have expired or have been transferred and the Company has transferred
substantially all risks and rewards of ownership.
Financial assets and liabilities are offset and the net amount is reported in the balance sheet when there is a legally enforceable right to offset
the recognized amounts and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
3. Significant accounting policies (continued)
(c) Financial instruments (continued)
Cash and cash equivalents
Cash and cash equivalents are comprised of cash in hand, deposits with banks, term deposits, and other short-term highly liquid investments
with original maturities of three months or less. Cash and cash equivalents are designated as loans and receivables.
Financial assets at fair value through the Consolidated Statement of Comprehensive Income
An instrument is classified at fair value through the Consolidated Statement of Comprehensive Income if it is held for trading or is designated as
such upon initial recognition. Financial instruments are designated at fair value through the Consolidated Statement of Comprehensive Income if
the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company’s risk
management or investment strategy. Upon initial recognition attributable transaction costs are recognized in the Consolidated Statement of
Comprehensive Income when incurred. Financial instruments are measured at fair value, and changes therein are recognized in the Consolidated
Statement of Comprehensive Income.
Financial liabilities
Financial liabilities at amortized cost include trade payables. Trade payables are initially recognized at the amount required to be paid, less, when material,
a discount to reduce the payables to fair value. Subsequently, trade payables are measured at amortized cost using the effective interest method.
Financial assets
Trade and other receivables, which are non-derivative financial assets that have fixed or determinable payments that are not quoted in an active
market, are classified as loans and receivables. They are included in current assets, except for maturities greater than 12 months after the
reporting date, which are classified as non-current assets.
(ii) Equity instruments
Equity instruments are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized
as a deduction from equity, net of any tax effects, if any.
(d) Inventory
Inventories consist of tangible drilling materials, and other consumables. Inventories are stated at the lower of cost and net realizable value.
Cost is determined using the weighted average method. Net realizable value is the estimated selling price less applicable selling expenses.
(e) Property, plant and equipment and intangible exploration and evaluation expenses
(i) Recognition and measurement
Development and production costs
Property, plant and equipment is stated at cost, less accumulated depletion and depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation,
the initial estimate of any decommissioning obligation, if any, and, for qualifying assets, borrowing costs. The purchase price or the construction
cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
Expenditures on major maintenance, inspections or overhauls are capitalized when the item enhances the life or performance of an asset above its
original standard. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves
and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of
any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in the
Consolidated Statement of Comprehensive Income as incurred. Where an asset or part of an asset that was separately depreciated is replaced and
it is probable that future economic benefits associated with the item will flow to the Company, the expenditure is capitalized and the carrying
amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programs are capitalized and amortized over
the period to the next inspection. All other maintenance expenditures are expensed as incurred.
Intangible exploration and evaluation expenditures
Pre-licence costs are recognized in the Consolidated Statement of Comprehensive Income in the period that they are incurred.
Exploration and evaluation expenditures, including the costs of acquiring licences and directly attributable general and administrative costs,
geological and geophysical costs, acquisition of mineral and surface rights, technical studies, other direct costs of exploration (drilling, trenching,
sampling and evaluating the technical feasibility and commercial viability of extraction) and appraisal are accumulated and capitalized as
intangible exploration and evaluation (“E&E”) assets.
On a quarterly basis, a review of any areas classified and accounted for as E&E is performed to determine whether enough information exists to
make a determination of the technical feasibility and commercial viability of the area. Where appropriate, review may indicate that an area should
be further sub-divided due to a significant portion having been explored whilst a significant undeveloped portion with different traits (i.e.
different zone, technical approach, play type, etc.) remains that requires additional E&E activities to arrive at the point where it can be assessed
for technical feasibility and commercial viability.
The assessment of technical feasibility and commercial viability is performed on an area level basis unless further sub-division is merited.
Depending on the extent and complexity of the prospective play, many wells may need to be drilled and potentially significant E&E costs
accumulated prior to obtaining enough information to make the determination of technical feasibility and commercial viability possible.
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E&E costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical feasibility is
demonstrated and commercial reserves are discovered, then, the carrying value of the relevant E&E asset will be reclassified as a development and
production asset (“D&P”) into the cash generating unit (“CGU”) to which it relates, but only after the carrying value of the relevant E&E asset has
been assessed for impairment, and where appropriate, its carrying value adjusted. Typically, technical feasibility and commercial viability of
extracting a mineral resource is considered to be demonstrable when proven or probable reserves are determined to exist. However, if the
Company determines the area is not technically feasible and commercially viable, accumulated E&E costs are expensed in the period during which
this determination is made.
(ii) Depletion and depreciation
The net carrying value of development and production assets is depleted using the unit of production method by reference to the ratio of
production in the year to the related proven and probable reserves, taking into account estimated future development costs necessary to bring
those reserves into production. Future development costs are estimated taking into account the level of development required to produce the
reserves. These estimates are reviewed by independent reserve engineers at least annually.
For other assets (see below), a straight-line basis is used over the assets’ estimated useful lives, as follows:
Fixtures and fittings 1 – 5 years
Office equipment 1 – 5 years
Vehicles 1 – 5 years
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
(f) Impairment
(i) Financial assets
A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is
considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows
of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the
present value of the estimated future cash flows discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively
in groups that share similar credit risk characteristics.
All impairment losses are recognized in the Consolidated Statement of Comprehensive Income.
An impairment loss is reversed when there is a significant change in the underlying estimates or other objective evidence. For financial assets
measured at amortized cost the reversal is recognized in the Consolidated Statement of Comprehensive Income.
(ii) Non-financial assets
Exploration and evaluation costs are tested for impairment when reclassified to D&P assets or whenever facts and circumstances indicate potential
impairment. Exploration and evaluation assets are tested separately for impairment. An impairment loss is recognized for the amount by which the
exploration and evaluation expenditure’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of the
exploration and evaluation expenditure’s fair value less cost of disposal and their value in use.
Values of oil and gas properties and other property, plant and equipment are reviewed for impairment when indicators of such impairment exist.
If any indication of impairment exists an estimate of the asset’s recoverable amount is calculated. Assets are grouped for impairment assessment
purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets
(the CGU). The recoverable amount of a CGU is the greater of its fair value less cost of disposal and its value in use. Where the carrying amount
of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. An impairment loss is
charged to the income statement. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the CGU and
are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money.
For assets excluding goodwill, an assessment is made at each reporting date as to whether there is any indication that previously recognized
impairment losses may no longer exist or may have decreased, and if such indication exists, the Company makes an estimate of the recoverable
amount. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s
recoverable amount since the last impairment loss was recognized. If that is the case the carrying amount of the asset is increased to its
recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation,
had no impairment loss been recognized for the asset in prior years.
(g) Share based payments
The grant date fair value of options granted to employees is recognized as stock based compensation expense, with a corresponding increase in
contributed surplus over the vesting period. Each tranche granted is considered a separate grant with its own vesting period and grant date fair value.
A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest.
(h) Segment Reporting
Operating segments are reported in a manner consistent with the internal reporting provided to the senior operating decision-makers. The senior
operating decision-makers have been identified as the Executive directors that, as a group, make strategic decisions regarding the Company.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
3. Significant accounting policies (continued)
(i) Provisions
A provision is recognized, if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably,
and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected
future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions
are not recognized for future operating losses.
(j) Decommissioning obligations
The Company’s activities can give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated
cost of site restoration and capitalized in the relevant asset category.
Decommissioning obligations are measured at the present value of management’s best estimate of expenditure required to settle the present
obligation at the balance sheet date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the
passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time
is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred
upon settlement of the asset retirement obligations are charged against the provision to the extent the provision is established.
(k) Revenue
Revenue from the sale of oil, condensates, natural gas and natural gas liquids (“NGLs”) is recorded when the significant risks and rewards of ownership
of the product is transferred to the buyer which is usually when legal title passes to the external party. This is generally at the time product enters the
pipeline or is delivered to the refinery or other end customer. Revenue is measured net of discounts, customs duties and royalties.
Revenue from the services provided in the production of oil and natural gas is recognized when title passes from the Company to the customer.
Production service fee revenue represents the Company’s share of oil and gas production that remains after all obligations under its contracts have
been recorded, inclusive of any royalty obligations to government and other mineral interest owners.
Tariffs and tolls charged to other entities for the use of pipelines and facilities owned by the Company are recognized as revenue as they accrue in
accordance with the terms of the service or tariff and tolling agreements.
(l) Income tax
Income tax expense comprises current and deferred tax. Income tax expense is recognized in the Consolidated Statement of Comprehensive Income
except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date,
and any adjustment to tax payable in respect of previous years.
Pursuant to the terms of the Company’s Egyptian concession agreements, the corporate tax liability of the joint venture partners is paid by the
government controlled corporations (“Corporations”) out of the profit oil attributable to the Corporations, and not by the Company. For accounting
purposes the corporate taxes paid by the Corporations are treated as a benefit earned by the Company; the amount is included in net oil revenues and
in income tax expense, therefore having a net neutral impact on reported net income. Income tax expense is recognized in each interim period based
on the best estimate of the weighted average annual income tax rate expected for the full financial year.
The Company also has a production service agreement in Egypt relating to Block – H Meseda. The Company’s subsidiary, Madison Egypt Ltd (“MEL”)
an Egyptian registered entity, is the SDX contracting party in this production service agreement. Corporate tax is payable by MEL based on its taxable
income, from this production service agreement, for the year using tax rates enacted or substantively enacted at the reporting date.
The Company’s Moroccan operations benefit from a 10 year corporation tax holiday from first production and no taxation is due on Moroccan profits
as at December 31, 2017.
Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities
for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets
or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising
on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they
reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there
is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax
entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference
can be utilized.
(m) Earnings per share
Basic earnings per share is calculated by dividing the profit or loss attributable to common shareholders of the Company by the weighted average
number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the profit or loss attributable to
common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options
granted to employees and warrants.
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(n) Business combinations
Business combinations are accounted for using the acquisition method. Assets and acquired and liabilities assumed in a business combination are
recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair value of the net assets acquired is
recognized as an asset. Any excess of the fair value of the net assets acquired over the consideration paid is recognized in the Consolidated Statement
of Comprehensive Income.
(o) New standards and interpretations
The Consolidated Financial Statements have been prepared on the basis of accounting policies consistent with those applied in the Consolidated
Financial Statements for the year ended December 31, 2016. The amendment to IAS 12: “Recognition of Deferred Tax Assets for Unrealised Losses”,
which is mandatory for 2017, clarifies the accounting treatment for deferred tax assets related to debt instruments measured at fair value. An
amendment to IAS 7 “Statement of Cash Flows: Disclosure Initiative”, which is mandatory for 2017, requires entities to provide disclosures about
changes in liabilities arising from financing activities, including changes from financing cash flows and non-cash changes (such as foreign exchange
gains or losses). Neither of these amendments have had a material impact on the Consolidated Financial Statements. The clarification in “Annual
Improvements 2014 -2016 – IFRS 12 Disclosure of interests in other entities” regarding the scope of the standard is not relevant to the Consolidated
Financial Statements.
At the date of authorization of these Consolidated Financial Statements, the International Accounting Standards Board (“IASB”) has issued the
following new and revised standards which are not yet effective for the relevant periods:
IFRS 9 – Financial Instruments (“IFRS 9”)
In July 2014, the IASB issued IFRS 9, which replaces IAS 39, Financial Instruments – Recognition and Measurement, and establishes principles for the
financial reporting of financial assets and financial liabilities that will present relevant and useful information to users of financial statements for their
assessment of the amounts, timing and uncertainty of an entity’s future cash flows. This new standard is effective for the Company’s interim and
annual Consolidated Financial Statements commencing January 1, 2018. The Company does not expect this standard to have a significant impact
on its Consolidated Financial Statements.
IFRS 15 – Revenue from Contracts with Customers (“IFRS 15”)
IFRS 15 was issued in May 2014 and will provide a more structured approach to measuring and recognizing revenue. The new guidance includes
a five-step recognition and measurement approach and enhanced qualitative disclosure requirements. The underlying principle is that an entity will
recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those
goods or services. The standard is effective for annual periods beginning on or after January 1, 2018. Entities will have a choice of full retrospective
application, or prospective application with additional disclosures (simplified transition method). The Company has assessed the impact of IFRS 15
and determined that its application will result in no changes in its revenue recognition.
IFRS 16 – Leases (“IFRS 16”)
On January 13, 2016, the IASB published IFRS 16 which replaces the current guidance in IAS 17 ‘Leases’ (“IAS 17”). Classification of leases by the
lessor under IFRS 16 continues as either an operating or a finance lease, as was the treatment under IAS 17 ‘Leases’. The treatment of leases by the
lessee will require capitalization of most leases resulting in accounting treatment similar to finance leases under IAS 17. Exemptions for leases of very
low value or short term leases will be applicable. The new standard will result in an increase in lease assets and liabilities for the lessee. Under the new
standard the treatment of all lease expense is aligned in the Consolidated Statement of Comprehensive Income with depreciation, and an interest
expense component recognized for each lease, in line with finance lease accounting under IAS 17. The Company’s leases will come on balance sheet
on adoption of IFRS16 and the impact is still being assessed. IFRS 16 will be applied for annual periods beginning on or after 1 January 2019 with
the cumulative effect of initially applying the standard recognised at the date of initial application.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
4. Business Combination
On January 27, 2017, the Company announced the acquisition, through two of its wholly-owned subsidiaries, of the entire issued share capital
of Circle Oil Egypt Limited (“COEL”) and Circle Oil Morocco Limited (“COML”) for a cash purchase price of US$28.1 million.
The acquisition was funded by means of a conditional placing of new Common Shares in SDX at a Placing Price of 30 pence (C$0.50) per Placing Share,
amounting to US$40.0 million before costs.
COEL holds a 40% interest in the NW Gemsa concession, Eastern Desert, Egypt. Prior to the acquisition, SDX held a 10% interest in this concession,
bringing the post-acquisition holding to 50%.
COML holds a 75% interest and operatorship in certain licences, onshore Morocco, with L’Office National des Hydrocarbures et des Mines (“ONHYM”)
holding a 25% interest.
The acquisition is in accordance with the Company's strategy to pursue value adding production and development opportunities in North Africa
to complement its organic growth strategy.
The provisional fair value of the identifiable assets and liabilities of COEL and COML as at the date of acquisition were:
Fair value as at
US$ million January 27, 2017
Non-current assets
Property, plant & equipment 43.2
Current assets
Cash and cash equivalents 3.1
Trade and other receivables 32.9
1.1
Inventory
Current tax 0.1
Non-current liabilities
Decommissioning liability (2.8)
Deferred income (0.7)
Current liabilities
Trade and other payables (17.1)
Decommissioning liability (1.2)
Deferred income (0.9)
Total identifiable net assets at fair value 57.7
Total consideration (28.1)
Excess of fair value over cost (bargain purchase) 29.6
Prior to the acquisition the parent company of COEL and COML, Circle Oil Jersey Limited, was placed into administration. The excess of fair value over
cost arises due to the fact that COEL and COML were distressed businesses and purchased out of administration. A provisional bargain purchase gain
amounting to US$30.0 million has been recognised in the Consolidated Statement of Comprehensive Income for the twelve months ended December 31,
2017, after recording the following adjustments:
• A provision of US$2.6 million has been recognised against certain aged receivables due from ONHYM relating to its share of historic construction
costs, and US$0.5 million additional deferred income identified. These have been partially offset by additional billings for well completions in
Morocco of US$1.0 million (US$0.8 million net of VAT). Management has further considered the recoverability of the trade receivables balance
alongside confirmations received from EGPC and concession operators of amounts to be settled, as well as forecast uses of Egyptian Pounds in
operations, and do not consider it necessary to apply discounting. The trade receivables balance and any updates to the conclusion over
discounting will be monitored over the coming months.
• Ahead of the drilling campaign that commenced in the second half of 2017, an assessment was made of the acquired inventory. Certain items
were identified as being unfit for use and an obsolescence provision of US$0.2 million was recognised. Aged working capital of US$0.9 million
associated with legacy suppliers was eliminated.
• A further US$1.9 million has been recorded for additional liabilities acquired, relating to potential tax and legal claims.
• An accrued payable relating to back-dated tariff charges and other costs of US$4.8 million at NW Gemsa has been released following
the agreement of a payment plan with the operator. The estimate of natural gas and NGL receivable acquired has been revised down
by US$1.3 million following the receipt of additional information from the operator (see note 6b) to US$6.9 million.
COEL and COML contributed US$14.1 million revenue and US$0.5 million net profit and US$12.4 million revenue and US$0.4 million net profit
respectively to the Consolidated Financial Statements for the twelve months to December 31, 2017.
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5. Determination of fair values
A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and
liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further
information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.
The different levels of financial instrument valuation methods have been defined as follows:
Level 1 fair value measurements are based on unadjusted quoted market prices.
Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices.
Level 3 fair value measurements are based on unobservable information.
The carrying value of cash and cash equivalents, trade and other receivables, trade and other payables, and loans and borrowings included in the
consolidated balance sheet approximate to their fair value due to the short term nature of those instruments.
The fair value of employee stock options is measured using a Black-Scholes option pricing model. Measurement inputs include share price on
measurement date, exercise price of the instrument, expected volatility based on weighted average historic volatility adjusted for changes expected due
to publicly available information, weighted average expected life of the instruments based on historical experience and general option holder behavior,
expected dividends, and the risk-free interest rate.
6. Financial risk management
(a) Overview
The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing
activities such as:
• credit risk;
• liquidity risk;
• market risk;
• foreign currency risk; and
• other price risk.
This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes
for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these
Consolidated Financial Statements.
The Board of Directors oversees managements’ establishment and execution of the Company’s risk management framework. Management has
implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and
analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and
the Company’s activities.
(b) Credit risk
Credit risk is the risk of financial loss to the Company if a customer, partner, or counterparty to a financial instrument fails to meet its contractual
obligations and arises principally from the Company’s receivables from joint venture partners, oil and natural gas customers, and cash held with banks.
The maximum exposure to credit risk at the end of the period is as follows:
December 31 December 31
$000’s
2017 2016
Cash and cash equivalents 25,844 4,725
Trade and other receivables(1) 34,781 8,809
60,625 13,534
Total
Carrying amount
(1) Excludes prepayments
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
6. Financial risk management (continued)
(b) Credit risk (continued)
Trade and other receivables
Subsequent to the acquisition described in note 4, all of the Company’s operations were conducted in Egypt and Morocco. The Company’s exposure
to credit risk is influenced mainly by the individual characteristics of each counter party.
The Company does not anticipate any default as it expects continued payment from customers. As such no provision for doubtful accounts has been
recorded as at December 31, 2017 and 2016. Receivables have not been discounted.
The maximum exposure to credit risk for loans and receivables at the reporting date by type of customer was:
December 31 December 31
$000’s
2017 2016
Government of Egypt controlled corporations 25,582 7,745
Government of Morocco controlled corporations 3,597 -
Third party gas customers 3,175 -
Joint venture partners 1,586 578
Other(1)
841 486
Total trade and other receivables 34,781 8,809
Carrying amount
(1) Excludes prepayments of US$2.9 million which are included in the Consolidated Balance Sheet as Trade and other receivables but which are not categorised as Financial Assets as summarised above.
As a result of the acquisition of Circle Oil plc on January 27, 2017, US$32.9 million of Trade and other receivables were added to SDX’s Trade and
other receivables upon completion of the transaction, and this is the reason for the significant increase in these balances as at December 31, 2017.
US$25.6 million of current receivables related to oil, gas and NGL sales and production service fees which are due from EGPC (2016: US$7.7 million),
a Government of Egypt controlled corporation. The Company expects to collect outstanding receivables of US$22.7 million for NW Gemsa (2016:
US$3.4 million) and US$2.9 million for Block – H Meseda (2016: US$2.3 million), in the normal course of operations. During 2017, as part of the
Government of Egypt’s commitment to reduce amounts owing to international oil companies, the Company received US$10.0 million in lump-sum
payments, of which US$9.0 million related to the acquired Circle Oil NW Gemsa receivables.
US$3.6 million is owed by ONHYM and relates to ONHYM’s share of well completion and connection and production costs outstanding. During Q4
2017 the Company received US$2.2 million in settlement of 8” pipeline construction and some well completion costs.
US$3.2 million is owing from third party gas customers in Morocco and is expected to be collected within agreed credit terms.
Subsequent to December 31, 2017, the Company collected US$12.9 million of trade receivables from those that were outstanding at December 31,
2017; US$7.9 million for NW Gemsa, US$2.8 million for Block-H Meseda and US$2.2 million from third party gas customers in Morocco.
The joint venture partner current accounts represent the net of monthly cash calls paid less billings received. At December 31, 2017, US$1.6 million
was receivable from joint venture partners in the South Disouq concession (2016: South Disouq - US$0.6 million).
The other receivables of US$0.8 million consist of US$0.3 million for Goods and Services Tax (“GST”)/ Value Added Tax (“VAT”) and US$0.5 million
for other items. US$2.9 million related to prepayments predominantly associated with the Morocco and South Disouq drilling campaigns is recorded
in the Consolidated Balance Sheet.
As at December 31, 2017 and December 31, 2016, the Company’s trade and other receivables, other than prepayments, are aged as follows:
December 31 December 31
2017 2016
$000’s
Current
Current (less than 90 days) 21,261 6209
Past due (more than 90 days) 13,520 2,600
Total trade and other receivables 34,781 8,809
Carrying amount
Current trade and other receivables are unsecured and non-interest bearing. The balances which are past due are not considered impaired.
Current trade and other receivables past due (more than 90 days old) have increased by US$10.9 million when compared to December 31, 2016.
This increase is primarily due to the acquired Circle NW Gemsa and Morocco receivables, which had a significantly more aged profile than those
previously managed by the Company. This US$10.9 million increase however is after taking account of the collection of US$2.0 million of the
Company’s Shukheir Marine receivables, and the receipt of US$10.0 million of lump-sum payments from the Government of Egypt which were
applied to aged receivables, of which US$9.0 million related to the acquired Circle Oil NW Gemsa receivables.
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Cash and cash equivalents
The Company limits its exposure to credit risk by only investing in liquid securities and only with highly rated counterparties. The Company’s cash and
cash equivalents are currently held in established banks in either countries of operation or the UK, the majority of which have A or AA ratings. Given
these credit ratings, management does not expect any counterparty to fail to meet its obligations.
(c) Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing
liquidity is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed
conditions, without incurring unacceptable losses or risking damage to the Company’s reputation.
Typically the Company ensures that it has sufficient cash on demand to meet expected operational expenses, including the servicing of financial
obligations; this excludes the potential impact of extreme circumstances that cannot reasonably be predicted, such as natural disasters and political
unrest. To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered
necessary. Further, the Company utilizes authorizations for expenditures on projects to further manage capital expenditure and has a Board of Director
approved signing authority matrix. The Company also attempts to match its payment cycle with collection of oil and service fee revenue to the extent
possible.
As at December 31, 2017, other than the non-current elements of the deferred income and decommissioning liabilities, the Company’s financial
liabilities are due within one year.
(d) Market risk
Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates will affect the Company’s
income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within
acceptable parameters, while optimizing the return.
The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted
within risk management tolerances that are reviewed by the Board of Directors.
(e) Foreign currency risk
Currency risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The reporting and
functional currency of the Company is United States dollars (“US$”). Substantially all of the Company’s operations are in foreign jurisdictions and
as a result, the Company is exposed to foreign currency exchange rate risk on some of its activities, primarily on exchange fluctuations between the
Egyptian Pound (“EGP”) and the US$, the Moroccan Dirham (“MAD”) and the US$, and Sterling (“GBP”) and the US$. The majority of capital
expenditures are incurred in US$, EGP and MAD, and oil, natural gas, NGL and service fee revenues are received in US$, EGP and MAD. The Company
is able to utilize EGP and MAD to fund its Egyptian and Moroccan office general and administrative expenses and to part-pay cash requirements for
both capital and operating expenditure, therefore reducing the Company’s exposure to foreign exchange risk during the period.
The table below shows the Company’s exposure to foreign currencies for its financial instruments:
Total per FS (1) US$ EGP GBP MAD Other
As at December 31, 2017 US$ equivalent
Cash and cash equivalents 25,844 9,673 1,314 2,840 12,011 6
Trade and other receivables(2) 34,781 25,742 75 145 8,783 36
Trade and other payables (19,459) (12,606) (810) (315) (2,945) (2,783)
Current income taxes (915) - (915) - - -
Balance sheet exposure 40,251 22,809 (336) 2,670 17,849 (2,741)
(1) FS denotes Financial Statements
(2) Excludes prepayments
The average exchange rates during the three months ended December 31, 2017 and 2016 were 1 US$ equals:
Average: October 1, 2017 to December 31, 2017 Average: October 1, 2016 to December 30, 2016
USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD
Period average 17.7107 0.7537 9.4442 Period average 14.3634 0.8044 9.9607
The average exchange rates during the twelve months ended December 31, 2017 and 2016 were 1 US$ equals:
Average: January 1, 2017 to December 31, 2017 Average: January 1, 2016 to December 31, 2016
USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD
Period average 17.8534 0.7770 9.7047 Period average 10.0211 0.7405 9.8042
The exchange rates as at December 31, 2017 and 2016 were 1 US$ equals:
Period end: December 31, 2017 Period end: December 31, 2016
USD/EGP USD/GBP USD/MAD USD/EGP USD/GBP USD/MAD
December 31, 2017 17.7875 0.7398 9.3519 December 31, 2016 18.1274 0.8113 10.1132
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
6. Financial risk management (continued)
(f) Other price risk
Other price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil
and natural gas are impacted by not only the relationship between the United States dollar and other currencies but also macro-economic events
that impact the perceived levels of supply and demand.
The Company may hedge some oil and natural gas sales through the use of various financial derivative forward sales contracts and physical sales
contracts. The Company’s production is sold on the daily average price. The Company, however, may give consideration in certain circumstances
to the appropriateness of entering into long term, fixed price marketing contracts.
At December 31, 2017 the Company did not have any outstanding derivatives in place.
(g) Capital management
The Company defines and computes its capital as follows:
December 31 December 31
$000’s
2017 2016
Equity 114,619 37,264
Working capital (1) (46,725) (11,823)
Total capital 67,894 25,441
Carrying amount
(1) Working capital is defined as current assets less current liabilities.
The Company’s objective when managing its capital is to ensure it has sufficient funds to maintain its ongoing operations, to pursue the acquisition
of interests in producing or near to production oil and gas properties and to maintain a flexible capital structure which optimizes the cost of capital at an
acceptable risk. The Company manages its capital structure and makes adjustments to it based on the funds available to the Company, in order to support
the exploration and development of its interests in its existing oil and gas properties and to pursue other opportunities.
7. Cash and cash equivalents
December 31 December 31
$000’s
2017 2016
Cash and bank balances 24,248 4,725
Restricted cash (1) 1,596 -
Total cash and cash equivalents 25,844 4,725
Carrying amount
(1) Cash collateral of US$1.5 million is held at the bank to cover bank guarantees for minimum work commitments on the Company's Moroccan concessions. These guarantees are subject to forfeiture in certain circumstances if the
Company does not fulfil its minimum work obligations.
Cash at bank earns interest at floating rates based on the daily bank deposit rates.
8. Inventory
As at December 31, 2017 the Company undertook a comprehensive stockcounting exercise over all spare parts and consumables inventory across its
Moroccan and Egyptian operations. Given the forthcoming exploration and development drilling operations on the South Disouq concession, and in order
to identify an optimal use for the Company’s inventory, a quantity of on hand drill pipe and casing was inspected and certified for use in the planned wells.
This inventory was from legacy operations and previously was carried at nil value as it was not planned to be used and thus was uncertified. Furthermore,
the inventory had been attributed zero realizable value due to the limited resale market in Egypt and was therefore fully provided-for. The reversal of the
provision previously recognized against this inventory has resulted in a US$0.8 million credit to the Consolidated Statement of Comprehensive Income.
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9. Property, plant and equipment
Oil and gas Furniture
properties and fixtures Total
$000’s
Cost:
Balance at December 31, 2015 30,663 120 30,783
Additions 1,705 68 1,773
Balance at December 31, 2016 32,368 188 32,556
Additions 15,975 457 16,432
Acquisitions 43,232 - 43,232
Balance at December 31, 2017 91,575 645 92,220
Accumulated depletion, depreciation, amortization and impairment:
Balance at December 31, 2015 (12,334) (48) (12,382)
Depletion, depreciation and amortization for the year (3,225) (41) (3,266)
Impairment charge (4,303) - (4,303)
Balance at December 31, 2016 (19,862) (89) (19,951)
Depletion, depreciation and amortization for the year (17,737) (87) (17,824)
Balance at December 31, 2017 (37,599) (176) (37,775)
NBV Property, plant and equipment as at December 31, 2016 12,506 99 12,605
NBV Property, plant and equipment as at December 31, 2017 53,976 469 54,445
During the year ended December 31, 2017, the PP&E additions of US$16.0 million predominantly related to the Morocco drilling campaign
(US$11.4 million), as well as well workovers in the NW Gemsa field, well workovers in the Block-H Meseda concession, the acquisition of additional
technical software, and the refurbishment of the Rabat corporate office in Morocco. The difference between the US$16.0 million disclosed above and the
US$21.1 million Property, plant and equipment expenditure in the Consolidated Statement of Cash Flows is due to the fact that c.US$8.1 million of aged
capital expenditure payables acquired from Circle Oil were paid during 2017, partially offset by accrued payables for Moroccan drilling, which are part of
Trade and other payables as at December 31, 2017.
The Company has also recorded, on the face of the table above, the assets acquired from Circle Oil plc, at fair value of US$43.2 million.
Impairment assessment
At the reporting date, management performed an impairment indicator assessment and concluded that no such indicators existed for the Company’s
properties in Egypt and Morocco.
In the prior period the NW Gemsa field was impaired by US$4.3 million, due to increased forecast operating expenditure and a reduction in the proved
and probable reserves.
10. Intangible exploration and evaluation assets
$000’s
Balance at December 31, 2015 23,473
Additions 11,566
Exploration and evaluation expense (24,416)
Balance at December 31, 2016 10,623
Additions 4,608
Balance at December 31, 2017 15,231
During the twelve months ended December 31, 2017, E&E additions totaling US$4.6 million consisted of US$2.8 million at South Disouq for seismic
interpretation, SDX’s share of drilling costs of the SD-1X well and preparatory work for the 2018 drilling campaign and US$1.8 million in Morocco in
respect of work for the ongoing drilling campaign, primarily the ELQ-1 well, and annual training fees for the exploration concessions.
The difference between the US$4.6 million additions above, and the US$3.8 million reflected in the Cash Flow relates to unpaid charges at the year end.
During the prior year, the Company completed its activities in Cameroon and made a full provision against the capitalized exploration cost of US$24.4 million.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
11. Investments
The Company owns a 50% equity interest in Brentford Oil Tools LLC (“Brentford”), an oilfield services business incorporated in Egypt, over which it
exercises joint control. Brentford owns all assets which it uses to provide its services and is legally responsible for settling its liabilities. Although in the
current and comparative period Brentford has only provided services to its shareholders, it is not contractually obliged to do so and in the past it has
contracted with third parties and continues to seek opportunities to do so. On the balance of facts, the Company has concluded that Brentford is a Joint
Venture under IFRS 11 – “Joint Arrangements” and the Company’s interest is equity accounted for. The investment is reviewed regularly for indicators of
impairment and no impairment was identified for the periods ended December 31, 2017 and December 31, 2016.
The following table summarizes the changes in investments for the periods ended December 31, 2017 and December 31, 2016:
December 31 December 31
2017 2016
$000’s
Investments, beginning of period 2,503 2,106
Dividends received (801) (825)
Share of operating income 1,022 1,222
Investments, end of period 2,724 2,503
The following table summarizes the Company’s 50% interest in the assets, liabilities, revenue and operating income of Brentford as at December 31, 2017
and 31 December 2016:
December 31 December 31
SDX share (50%) of Brentford ($000s) 2017 2016
Total assets 2,235 2,405
Total liabilities 14 3
Revenue 1,448 1,656
Net income 1,022 1,222
During the year ended December 31, 2017 50% (December 31, 2016 – 50%) of Brentford’s revenue was earned from fees charged to the Company.
12. Trade and other payables
December 31 December 31
2017 2016
$000’s
Current
Trade payables 2,636 663
Accruals 9,536 684
Joint venture partners 5,686 1,743
Other payables 1,601 584
Total trade and other payables 19,459 3,674
Carrying amount
The US$2.0 million increase in Trade payables as at December 31, 2017, is due to billed services and goods associated with the Moroccan drilling
campaign, as well to the increased size of the Group post-Circle Oil acquisition.
Accruals include amounts for products and services received which have yet to be invoiced. The US$8.8 million increase period on period reflects work
undertaken but not yet billed on the Morocco drilling campaign well and additional liabilities incurred with the business combination, relating to potential
tax and legal claims.
Joint venture partners comprise partner current accounts of US$1.0 million for NW Gemsa (2016:US$1.2 million), US$1.2 million Block-H Meseda
(2016: US$0.5 million) and US$3.5 million for the Morocco concessions (2016: US$nil). The joint venture partner current accounts represent the net
of monthly cash calls paid less billings received.
Other payables of US$1.6 million comprise an estimated liability of US$0.5 million related to the relinquishment of the Shukheir Marine concession
(2016: US$0.5 million), employee costs accrued and associated taxes of US$0.7 million (2016: $0.1 million) and sundry creditors of US$0.4 million
(2016: US$nil).
The difference between the increase of US$15.8 million in trade and other payables in the Consolidated Balance Sheets as at December 31, 2017
and December 31, 2016 and the line item in the Consolidated Statement of Cash Flows relating to the implied increase in Trade and other payables
of US$2.5 million relates primarily to the introduction of US$17.1 million of Trade and Other Payables from Circle Oil plc which is included in the cash
flow statement as part of the US$29.6 million Gain on acquisition and the US$28.1 million Acquisition of subsidiaries.
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13. Deferred income
Deferred income relates to an advance receipt for gas sales from a customer in Morocco. This payment was used to fund the tie-in of the customer’s
manufacturing premises to the Company’s operated gas pipeline. The amount will be credited to the Consolidated Statement of Comprehensive Income
under the terms of an agreement entered into with the customer under which the selling price of gas is discounted by 5% until the advance payment is
fully recouped, expected to be during the year ended December 31, 2019.
14. Decommissioning liability
Upon acquisition of Circle Oil’s Moroccan assets, the Company assumed responsibility for the decommissioning of these assets, and has drilled further
wells since acquisition that will require decommissioning in future periods.
As at December 31, 2017 the total future undiscounted cash flows amounted to US$4.9 million, to be incurred between the years 2018 and 2021 and
the liability was discounted using a risk-free rate of 3.0%. Expenditure of US$0.1 million was incurred during Q4 2017 with a further US$1.1 million
anticipated within the next 12 months.
In addition, following the drilling of the SD-1X well and submission of the South Disouq field development plan, the Company has a present obligation
to decommission this asset, under the terms of the concession agreement. The total future undiscounted cash flows amounted to US$0.1 million, to be
incurred in 2022, and the liability was discounted using a risk-free rate of 8.0%.
December 31 December 31
$000’s
2017 2016
Decommissioning liability, beginning of period - -
Changes in estimate 625 -
Liabilities acquired through business combination 3,968 -
Payments for decommissioning (137)
Accretion 86 -
Decommissioning liability, end of period 4,542 -
Of which:
Current 1,063 -
Non-current 3,479 -
Carrying amount
No decommissioning liabilities are recorded in respect of the Company’s other Egyptian assets, under the terms of the respective concession agreements.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
15. Income tax - current and deferred
Pursuant to the terms of the Company’s Egyptian PSCs, the corporate tax liability of the joint venture partners is paid by the government controlled
corporations (“Corporations”) who participate in these PSCs, out of the profit oil attributable to the Corporations, and not by the Company. For
accounting purposes however, the corporate taxes paid by the Corporations are treated as a benefit earned by the Company, with the amount being
“grossed up” and included in net oil revenues and the income tax expense of the Company. During 2017 US$3.55 million of corporation tax was paid by
government corporations.
The Company also has a PSA related to Block-H Meseda with legal title residing with Madison Egypt Limited (“Madison Egypt”), an Egyptian incorporated
entity. The Company is governed by the laws and tax regulations of the Arab Republic of Egypt and pays corporate taxes on the adjusted profit of
Madison Egypt.
The current income tax expense in the Consolidated Statement of Comprehensive Income for the three and twelve months ended December 31, 2017
relates to income tax on North West Gemsa’s PSC and income tax relating to the Company’s PSA in Block-H Meseda.
The current income tax liability of US$0.9 million in the Consolidated Balance Sheet relates to the Company’s PSA in Block H Meseda.
The Company’s Moroccan operations benefit from a 10 year corporation tax holiday from first production and no taxation is due on Moroccan profits
as at December 31, 2017.
(a) Income tax expense differs from that which would be expected from applying the effective Canadian federal and provincial income tax rates of 27%
(2016: 27%) to income before income taxes as follows:
Consolidated Statement of Comprehensive Income
Twelve months ended December 31
2016
$000’s except per unit amounts
Income before income taxes 32,819 (26,697)
2017
Canadian statutory income tax rate 27% 27%
Expected income taxes 8,861 (7,208)
Adjustments:
Non deductible items 518 (57)
Non taxable gain on acquisition (7,981) -
Unrecognized income tax benefit 518 385
Foreign tax differential 1,291 433
Expenses incurred with no recognized tax benefit 1,334 7,950
Total current and deferred income tax expense 4,541 1,503
(b) The components of the deferred income tax assets and liabilities at December 31, 2017 and 2016 include the following:
Consolidated Balance Sheet
Twelve months ended December 31
$000’s except per unit amounts 2017 2016
Deferred tax assets/(liabilities):
Investments (10) (9)
Property and equipment (324) (292)
Other 44 11
Deferred income tax liability (290) (290)
(c) The Company has US$61.5 million of non-capital losses available at December 31, 2017 (2016: US$56.5 million) to shelter future taxable income,
the majority of which were incurred in Canada and expire between 2026 and 2035. The Company has not recognized any deferred tax assets as at
December 31, 2017 and 2016 primarily relating to its Canadian business as it has determined that its deferred tax assets are not probable to be
realized from current operations.
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16. Share capital
(a) The Company is authorized to issue unlimited common shares with no-par value and unlimited preferred shares with no-par value.
(b) Common Shares issued
December 31, 2017 December 31, 2016
Number Number
of Shares Stated Value of Shares Stated Value
($000’s) ($000’s) ($000’s) ($000’s)
Balance, beginning of period 79,844 40,275 37,642 30,148
Issue of common shares (less share issue costs) 124,649 48,510 42,202 10,127
Balance, end of period 204,493 88,785 79,844 40,275
Weighted average shares outstanding 184,422 71,509
(c) Common Share Warrants issued
December 31, 2017 December 31, 2016
Number Number
of Shares Stated Value of Shares Stated Value
($000’s) ($000’s) ($000’s) ($000’s)
Balance, beginning of period - - 611 99
Expiry of warrants - - (611) (99)
Balance, end of period - -
The 610,743 warrants expired on July 27, 2016.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
17. Stock-based compensation
Stock option plan
The Company has a stock option plan that entitles officers, directors, employees and certain consultants to purchase shares in the Company.
Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key
consultants of the Company. The fair value of all options granted is estimated using the Black-Scholes option pricing model. Each tranche in an award is
considered a separate award with its own vesting period and grant date fair value. Compensation cost is expensed over the vesting period with a
corresponding increase in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as
contributed surplus are recorded as share capital. Using this methodology, the charge for 2017 is US$0.5 million.
During the year ended December 31, 2016, 395,000 options were cancelled as a result of two non-executive Directors and one employee leaving the
Company. In addition, 190,000 options were issued during the year to three new employees. During the twelve months ended December 31, 2017,
640,000 stock options were issued to four non-executive Directors of the Company, 100,000 options lapsed and 100,000 options were cancelled due
to employees leaving the Company, and 33,332 options were exercised.
The number and weighted average exercise prices of stock options for the Company’s stock option plan is as follows:
Number Weighted average
of Options exercise price
(000’s) (CDN$)
Outstanding January 1, 2016 2,650 0.63
Cancelled during the year (395) 0.63
Issued during the year 190 0.36
Outstanding December 31, 2016 2,445 0.61
Exercisable December 31, 2016 1,567 0.62
Lapsed during the year (100) 0.54
Cancelled during the year (100) 0.45
Exercised during the year (33) 0.36
Issued during the year 640 0.76
Outstanding December 31, 2017 2,852 0.65
Exercisable December 31, 2017 2,395 0.64
The exercise price of the outstanding options under the stock option plan as at December 31, 2017 is as follows:
Outstanding options Vested options
Number of Remaining Number of Remaining
Exercise price range options contractual life options contractual life
CAD $0.39 - $0.76 2,851,667 3-5 years 2,395,000 3-5 years
Key assumptions relating the options issued to December 31, 2017 are as follows:
2017 2016 2015
Fair value at grant date (CDN) $0.26 $0.28 $0.61
Share price (CDN) $0.76 $0.36 $0.63
Exercise price (CDN) $0.76 $0.36 $0.63
Volatility (%) 70 70 70
Forfeiture (%) 0 0 0
Option life 5 years 5 years 5 years
Dividends (%) 0 0 0
Risk-free interest rate (%) 0.8 0.8 0.8
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Long Term Incentive Plan (“LTIP”)
On July 31, 2017 the Company established a new Long Term Incentive Plan and issued awards to its Executive Directors and certain other key employees.
The Company recognizes the need to ensure that Executive Directors and key employees from its operational, commercial, technical and financial
divisions, who are critical to executing the Company's strategy over the next phase of its development, are retained and incentivized to generate long term
value for shareholders.
The number of shares subject to the LTIP Awards has been determined by reference to the mid‐market price of a share on July 28, 2017 (£0.45 pence per
share). The Company has granted market value options as defined under UK tax legislation ("CSOP Options") to certain participants. The exercise price of
each CSOP Option is £0.45 pence per share, being the closing mid‐market price of a share on July 28, 2017.
The LTIP Awards and CSOP Options granted under the Plan take the form of a base award over a number of common shares. These awards will normally vest
on the third anniversary of the date of grant of the awards, subject to meeting certain strategic, operational, financial and shareholder return performance
criteria and the continued employment of the participant. The awards for the Executive Directors are subject to a further two year holding period from the
date of vesting with clawback provisions contained in the rules of the Plan which can be applied to awards made to all participants.
The following awards were granted to the two Executive Directors. These grants equate to 100% of each of the Executive Directors' salaries on 31 July 2017.
Number of common shares Number of common shares
Name
Status subject to LTIP award subject to CSOP option
Paul Welch Director 770,500 66,666
Director 555,555 66,666
Mark Reid
The above number of common shares granted to Executive Directors, over which the LTIP Awards and CSOP Options may vest, can be increased by
a multiple of up to one times depending on the level of share price growth over the three year period from date of grant. The potential level of increased
share awards is calculated as follows;
• If the share price growth in the three year period is less than 11% pa, there will be no increase in the base award number of shares set out above; and
• If the share price growth in the three year period is between a range of 11% pa and 20% pa, the additional number of shares which vest will increase
proportionately within this range up to a cap of a multiple of one times the base award number of shares. This cap will be triggered at share price
growth of 20% pa or more.
For the avoidance of doubt, the maximum number of shares which can vest for the CEO and CFO respectively is 1,541,000 and 1,111,111, as if any
of the CSOP options vest there will be a commensurate reduction in LTIP units vesting.
Based upon the grant at 31 July 2017, the maximum potential number of common shares that can vest to the Executive Directors and other selected
employees under the LTIP was in aggregate 3,449,461. All of these options are outstanding as at December 31, 2017 and March 23, 2018 but none
have vested. A further 3,765,045 options were awarded subsequent to the period end, and none have vested.
The LTIP will be presented to the Company's shareholders for approval at the next annual general meeting of shareholders. The number of ordinary shares
that may be issued or reserved for issuance under the awards granted pursuant to the LTIP, together with all common shares which may be issued under
options granted pursuant to the Company's stock option plan, may not exceed 10% of the Company's issued and outstanding common shares at the time of
grant. No ordinary shares of the Company will be issued pursuant to awards granted under the LTIP until such time as such shareholder approval is received.
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Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
18. Revenue, net of royalties
Twelve months ended December 31
$000’s
2017 2016
NW Gemsa oil sales revenue 31,641 7,432
Royalties (13,580) (3,190)
Net oil revenue 18,061 4,242
Block H Meseda production service fee revenues 8,045 6,359
Morocco gas sales revenue 12,425 -
Net other products revenue 635 2,313
Total net revenue before tax 39,166 12,914
The oil, gas and NGLs revenue and royalties relate to the NW Gemsa concession, which is governed by a PSC. The royalties are those attributable to the
government take in accordance with the fiscal terms of the PSC. Gas and NGLs are disclosed as ‘other products’ in the table above.
The Company commenced sales of gas and NGLs in February 2013 from the NW Gemsa concession, recognizing revenue from February to September
of that year. Subsequent to this, the Company ceased recognizing revenue due a dispute with EGPC over entitlement volumes. This dispute was resolved
in Q4 2016 and revenues from October 1, 2013 to December 31, 2016, which equate to US$2.2 million of gas sales and US$2.4 million of NGLs were
recognized in Q4 2016 and are reflected in the Consolidated Financial Statements. These sales have continued to be recognized for the twelve months
ended December 31, 2017. In December 2017, the operator of the NW Gemsa concession advised that the invoices that it had issued were based on
erroneous volumes and prices and that the actuals were lower. The adjustment has been made during Q4 2017, with the portion relating to the acquired
Circle Oil receivables (US$1.3 million) adjusted through the gain on acquisition, and the remainder through revenue (US$0.3 million).
The Moroccan gas sales revenue is derived from a Petroleum Agreement with the Moroccan state.
19. General and administrative expenses
Twelve months ended December 31
$000’s
2017 2016
Wages and employee costs 6,513 2,532
Consultants - inc. PR/IR 699 479
Legal fees 332 237
Audit, tax and accounting services 641 246
Public company fees 365 332
Travel
382 166
Office expenses 1,092 668
IT expenses 303 322
Service recharges (3,907) (1,303)
Ongoing general and administrative expenses 6,420 3,679
Transaction costs 2,373 -
Total net G&A 8,793 3,679
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2017 Annual Report
20. Income/(loss) per share
Twelve months ended December 31
$000’s
2017 2016
Net income/(loss) before comprehensive income for the period 28,278 (28,200)
Weighted average amount of shares
Basic 184,422 71,509
Diluted 187,389 71,557
Per share amount
Basic $0.153 $(0.394)
Diluted $0.151 $(0.394)
Basic income/(loss) per share is calculated by dividing the income attributable to shareholders of the Company by the weighted average number
of ordinary shares in issue during the period. Diluted per share information is calculated by adjusting the weighted average number of ordinary shares
outstanding to assume conversion of all dilutive potential ordinary shares. The Company computes the dilutive impact of common shares assuming the
proceeds received from the pro-forma exercise of in-the-money stock options or warrants are used to purchase common shares at average market prices.
21. Segmental Reporting
Following the acquisition of the Egyptian and Moroccan assets of Circle Oil plc, the Company’s operations are managed on a geographic basis, by country.
Prior year comparative figures have been updated to reflect the new basis of reporting.
The Company is engaged in one business of upstream oil and gas exploration and production. The executive directors are the Company’s chief operating
decision maker within the meaning of IFRS 8.
Twelve months ended December 31, 2017 Twelve months ended December 31, 2016 (restated)
Egypt Morocco Unallocated1 Total Egypt Morocco Cameroon2 Unallocated1 Total
Revenue 26,741 12,425 - 39,166 12,914 - - - 12,914
Operating costs (9,166) (1,088) - (10,254) (5,282) - - - (5,282)
Netback (pre tax) 17,575 11,337 - 28,912 7,632 - - - 7,632
Exploration and evaluation expense (2) - (185) (187) - - (24,731) (102) (24,833)
Depletion, depreciation & amortization (7,797) (9,898) (129) (17,824) (3,225) - - (41) (3,266)
Impairment expense - - - - (4,303) - - - (4,303)
Reversal of inventory provision 798 - - 798 479 - - - 479
Stock based compensation - - (538) (538) - - - 47 47
Share of profit from joint venture 1,022 - - 1,022 1,222 - - - 1,222
General and administrative expenses (1,053) (957) (6,783) (8,793) (879) - - (2,800) (3,679)
Operating income/(loss) 10,543 482 (7,635) 3,390 926 - (24,731) (2,896) (26,701)
(1) Unallocated expenditure, assets and liabilities include amounts of a corporate nature and not specifically attributable to a geographical segment.
(2) As described in note 10, in 2017 the Company no longer operates in Cameroon.
The segment assets and liabilities as at December 31, 2017 and December 31, 2016 are as follows:
December 31, 2017 December 31, 2016 (restated)
Egypt Morocco Unallocated1 Total Egypt Morocco Cameroon2 Unallocated1 Total
Segment assets 74,046 51,277 15,734 141,057 37,696 - - 3,921 41,617
Segment liabilities (4,703) (19,523) (2,212) (26,438) (2,926) - - (1,427) (4,353)
(1) Unallocated expenditure, assets and liabilities include amounts of a corporate nature and not specifically attributable to a geographical segment.
(2) As described in note 10, in 2017 the Company no longer operates in Cameroon.
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2017 Annual Report 68
Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
22. Commitments and contingencies
Pursuant to the concession and production service fee agreements in Egypt and Morocco, the Company is required to perform certain minimum
exploration and development activities that include the drilling of exploration and development wells. These obligations have not been provided for
in the Consolidated Financial Statements.
In Morocco, the commitments are for the drilling of four development/appraisal wells (ELQ-1 (ongoing over the period end), ONZ-7, KSS-2 and SAH-2)
in the Sebou and Gharb Centre permits, and two exploration wells in the Lalla Mimouna permit, LMS-1 and LNB-1. In addition, as a condition of being
awarded the Gharb Centre permit, the Company has committed to undertake an exploration work program consisting of 240km2 of 3D seismic and at
least two exploration wells. The total estimated cost of these commitments is c.US$19.5 million, including unpaid well costs at the period end.
In Egypt the Commitments are for the drilling of one development well and facilities upgrade for South Ramadan (US$3.0 million) and two exploration
wells, two development well and no less than 100km2 of 3D for the second exploration phase commitment for South Disouq. The Company estimates
that its share of this committed exploration cost on South Disouq is $8.5 million which will be incurred within the next twelve months.
The anticipated timing of the expenditure associated with the above commitments is as follows:
December 31 December 31
$000's
2017 2016
Less than one year 31,000 1,340
Between one and five years - 2,933
31,000 4,273
Total
The Company has a lease commitment for its office premises in London under a non-cancellable operating lease.
Commitments for minimum lease payments in relation to non-cancellable operating leases are payable as follows:
December 31 December 31
$000's
2017 2016
Less than one year 172 318
Between one and five years 375 499
547 817
Total
There are no contingencies as at December 31, 2017.
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2017 Annual Report
23. Related party transactions
All subsidiaries and joint arrangements (Brentford Oil Tools) are listed below. A list of the investments in subsidiary undertakings (all of whose operations
comprise one class of business, being oil and gas exploration, development and production), including the name, proportion of ownership interest,
country of operation and country of registration, is given below.
Country of Country of
Percentage operation registration
Name
Sea Dragon Energy (UK) Ltd 100% U.K. U.K.
SDX Energy Investments (UK) Ltd 100% U.K. U.K.
SDX Energy Morocco (UK) Ltd 100% U.K. U.K.
Sea Dragon Cooperatieve U.A. (Netherlands) 100% Netherlands Netherlands
Sea Dragon Energy Holding B.V. (Netherlands) 100% Netherlands Netherlands
Sea Dragon Energy (Kom Ombo) B.V. (Netherlands) 100% Egypt Netherlands
Sea Dragon Energy (GOS) B.V. (Netherlands) 100% Egypt Netherlands
Sea Dragon Energy (Nile) B.V. (Netherlands) 100% Egypt Netherlands
Sea Dragon Energy (NW Gemsa) B.V. (Netherlands) 100% Egypt Netherlands
Sea Dragon Energy Holding Ltd (BVI) 100% British Virgin British Virgin
Islands Islands
NPC (Shukheir Marine) Ltd (BVI) 100% Egypt British Virgin
slands
NPC (South Ramadan) Ltd (BVI) 100% Egypt British Virgin
Island
Madison International Oil & Gas Ltd 100% Barbados Barbados
Madison Egypt Oil & Gas Ltd 100% Egypt Barbados
Madison Cameroon Oil & Gas Ltd 100% Cameroon Barbados
Madison Egypt Ltd 100% Egypt Egypt
SDX Energy Morocco (Jersey) Ltd 100% Morocco Jersey
SDX Energy Egypt (Jersey) Ltd 100% Egypt Jersey
Brentford Oil Tools 50% Egypt Egypt
24. Compensation of key management personnel
The remuneration of directors and other key management personnel during the years ended December 31, 2017 and 2016 was as follows:
Twelve months ended December 31
2016
2017
Salaries, incentives and short term benefits 2,489 1,087
Directors’ fees 173 153
Stock based compensation 417 (114)
3,079 1,126
Total
Key management personnel have been identified as the non-executive directors and executive officers of the Company. The executive officers include the
President and CEO and CFO.
In the year ended December 31, 2017, termination benefits of $383k were paid to Ahmed Moaaz, the former Egypt Country Manager.
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2017 Annual Report 70
Notes to the Consolidated Financial Statements
for the years ended December 31, 2017 and 2016
(tabular amounts are in thousands of United States dollars except where stated)
25. Post balance sheet events
On January 4, 2018, it was announced that the Company had completed drilling of the ELQ-1 well in the Gharb Centre permit in Morocco to a total
depth of 1,484 meters and encountering 23 net meters of reservoir interval and two meters of marginal net conventional gas pay in the Hoot formation.
These results are considered non-commercial and well will be plugged and abandoned.
On January 23, 2018, it was announced by the Company that a gas discovery has been made at its ONZ-7 development well on the Sebou permit
in Morocco. The ONZ-7 well was drilled to a total depth of 1,167 meters with 5 meters of net conventional natural gas pay in the Hoot formation.
The well will be completed, tested and connected to existing infrastructure.
On February 21, 2018, it was announced that the Company had completed drilling of the KSS-2 well in the Sebou permit in Morocco to a total depth
of 1,293 meters and encountered 8 net meters of high quality reservoir interval in the Gaddari and Guebbas sequences. These results are considered
non-commercial and well will be plugged and abandoned.
On March 9, 2018, it was announced by the Company that a gas discovery has been made at its SAH-2 development well on the Sebou permit in
Morocco. The SAH-2 well was drilled to a total depth of 1,304 meters with 5 meters of net conventional natural gas pay across two zones in the
Guebbas and Hoot formations. The well will be completed, tested and connected to existing infrastructure.
On March 14, 2018 it was announced that the Company had completed drilling of the Rabul 5 Well in the West Gharib Concession in Egypt. The well
was drilled to 5,280 feet total depth and encountered approximately 151 feet of net heavy oil pay across the Yusr and Bakr formations, with an average
porosity of 18%. Further evaluation of the discovery is ongoing, after which the Company expects the well to be completed as a producer and connected
to the central processing facilities at Meseda.
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Corporate information
Executive Officers
Paul Welch
President &
Chief Executive Officer &
Chief Operating Officer
Mark Reid
Chief Financial Officer
Independent Directors
Michael Doyle
Non-Executive Chairman
David Mitchell
David Richards
Michael Raynes
Stock Exchange Listing
TSX Venture Exchange
London Stock Exchange AIM
Symbol: SDX
Registrar and Transfer Agent (Canada)
TSX Trust Company
200 University Avenue, 3rd Floor
Toronto, ON
M5H 4H1 Canada
T: +1 (416) 361 0152
F: +1 (416) 361 0470
Registrar (United Kingdom)
Link Market Services (Guernsey) Limited
Mont Crevalt House, Bulwer Avenue
St Sampson, Guernsey, GY2 4LH
Channel Islands
T: +44 (0)37 1664 0300
Nominated Advisor and Joint Broker
Stifel Nicolaus Europe Limited
Callum Stewart/Nicholas Rhodes/
Ashton Clanfield
150 Cheapside, London, EC2V 6ET,
United Kingdom
Tel: +44 (0) 20 7710 7600
Joint Brokers
GMP FirstEnergy
Jonathan Wright/David van Erp
85 London Wall, London, EC2M 7AD
United Kingdom
T: +44 (0)20 7448 0200
Cantor Fitzgerald Europe
David Porter
One Churchill Place, Canary Wharf
London, E14 5RB, United Kingdom
T: +44 (0)20 7894 7000
Independent Engineers
ERC Equipoise
6th Floor Stephenson House
2 Cherry Orchard Road
Croydon, CR0 6BA
Auditors
PricewaterhouseCoopers LLP
431 Union Street, Aberdeen, AB11 6DA
United Kingdom
Public Relations
Celicourt Communications
Mark Antelme/Jimmy Lea
7-10 Adam House, The Strand
London, WC2N 6AA, United Kingdom
Telephone: +44 (0)20 7520 9261
SDX Energy Office Locations
Canada
Centennial Place, East Tower,
1900, 520 - 3rd Avenue SW
Calgary, Alberta, Canada T2P 0R3
T: +1 (403) 457 5035
F: +1 (403) 457 5420
Egypt
Road 261, No. 10,
New Maadi, Cairo, Egypt
T: +20 2 2517 6528
F: +20 2 2517 6524
Morocco
Forum 6, Rue Ibrahim Tadili
Bureau n 7- 1er Etage
Souissi - Rabat, Kingdom of Morocco
T: +212 537 635 656
F: +212 537 656 314
United Kingdom
38 Welbeck Street, London W1G 8DP
United Kingdom
T: +44 (0)20 3219 5640
F: +44 (0)20 3219 5655
Designed and produced by effektiv
+44 (0)20 7251 7720 / www.effektiv.co.uk
SDX Energy Inc.
2017 Annual Report 72
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High Margin Growth
www.sdxenergy.com