2016
Annual Report
Our Highlights
Fourth Quarter 2016
Corporate and Financial
•
SDX’s key financial metrics for the 3 and 12 months ended December 31, 2016 and 2015 are as follows:
Three months ended December 31Twelve months ended December 31
US$ million except per unit amounts 2016 2015 2016 2015
Net Revenues 5.4 3.4 12.9 11.4
Netback (1) 3.6 1.0 7.6 6.4
Net realized average oil price/service fees - US$/barrel 36.61 33.09 31.50 35.74
Net realized average gas price - US$/mcf 1.22 - 1.22 -
Non-cash exploration and evaluation write down - - (28.4) -
Non-cash impairment expense (4.3) (6.8) (4.3) (6.8)
Total comprehensive income/(loss) (2.1) 8.5 (28.0) 9.4
Net cash (used in)/generated from operating activities 0.6 (2.3) (1.9) (5.2)
(1) Refer to “Non-IFRS Measures” section of this release below for details of Netback.
•
•
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The above financial metrics do not reflect any impact of the acquisition of the Egyptian and Moroccan businesses of Circle Oil PLC which completed on
January 27, 2017;
Some relevant financial metrics relating to these acquired businesses are;
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Unaudited Revenues and Netback for the 12 months ended December 31, 2016 for the businesses acquired were US$28.9 MM and US$22.4 MM
respectively
The Fair Value of the net assets acquired as at January 27, 2017 amounted to US$59.6 MM of which US$3.1 MM related to cash and US$18.4 MM
related to non-cash Working Capital excluding deferred income and decommissioning.
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The following comments relate only to SDX’s key financial metrics for the 12 months ended December 31, 2016;
SDX’s comprehensive loss of US$(28.0) MM for 12 months ended December 31, 2016 is due predominantly to;
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write down of US$(24.4) MM in the Bakassi West, Cameroon exploration asset resulting from the decision to withdraw from concession; and
an impairment of US$(4.3) MM due to the North West Gemsa field now being projected to reach its economic limit earlier as a result of the reserve
auditor’s lower oil price forecast in future years.
• 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;
• US$13.3 MM of capital expenditure has been invested into the business during the 12 months ended December 31, 2016;
US$1.7 MM primarily related to the drilling of 2 wells on North West Gemsa;
US$6.0 MM on the 3D seismic campaign at South Disouq; and
US$5.6 MM on the drilling of the Manatee-1 well at West Bakassi.
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As at December 31, 2016, SDX had cash on hand of US$4.7 MM and zero debt. As at February 28, 2017, cash on hand had increased to US$18.3 MM and
the Company remained debt free.
•
Operational Highlights
•
•
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Average daily oil sales and production service fees equated to 1,196 barrels of oil per day (“BOP/D”) for the 12 months to December 31, 2016 and
1,147 BOP/D for the 3 months to December 31, 2016;
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 935 and 3,718 barrels of oil equivalent (“BOEP/D”) for the 12 and 3 months to December 31, 2016. Out of the 935 BOEP/D,
153 BOE/D was actually generated in the 12 months to December 31, 2016;
As at March 23, 2017 the Company’s share of production from its operations was:
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- Meseda 776 BOP/D
- Morocco 663 BOE/D
North West Gemsa 2,794 BOEP/D
Contents
02 Financial and Operating Highlights
04 Where We Operate
06 Chairman’s Statement
07 Chief Executive’s Statement
08 Review of Operations
14 Reserves Summary
15 Board of Directors
16 Remuneration Report
17 Corporate Governance Statement
20 Management’s Discussion & Analysis
49 Independent Auditors’ Report
50 Financial Statements
54 Notes to the Consolidated Financial Statements
IBC Corporate Information
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• Meseda
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South Disouq
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•
Morocco
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Sebou
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Lalla Mimouna
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Corporate
•
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Operational Highlights (continued)
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In North West Gemsa, six successful well workovers were completed in the 12 months ended December 31, 2016;
In Meseda, following the successful completion of a nine well workover program and strategic initiative focussed on development optimization and increasing
production, the partners completed a fluid handling review in H2 2016 which concluded that the Meseda facility treating capacity had to be increased. A
tendering process to secure the equipment necessary to increase facility treating capacity has been completed and construction of the new facilities equipment
has commenced. Once completed it will be shipped to location and installed;
In South Disouq the 3D seismic acquisition was completed ahead of schedule and under budget. Processing and interpretation has also been completed and
has identified potential for both oil and gas bearing prospects with strong Class III amplitude versus offset (AVO) responses observed in several prospects. Well
planning and selection of drilling location was completed as planned and the well operations commenced on March 20, 2017. Enquiries have also been
received from a number of operators regarding farming into the licence; and
At the South Ramadan development concession, a technical review of prospectivity has been completed and an evaluation of project economics is underway.
An extension to complete the drilling commitment has been requested from the government with any drilling now being planned for early 2018.
•
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Outlook:
Egypt
• North West Gemsa
Complete 12 well workover program focused on ESP installation/maintenance and tubing maintenance to ensure production uptime;
Complete unitization arrangement with offset operator and prepare for any additional development activities;
Drill 2 development wells (pending government approval) and 2 exploration wells;
Replace up to 6 ESPs;
Continue with redevelopment, waterflood program and facility capacity upgrade;
Complete drilling of SD-1X exploration well and reach TD early Q2 2017;
Depending on results of SD-1X, decide upon next steps which may include commencing development planning and deciding whether to enter the 2nd
exploration phase;
Drill up to 5 wells in H2 2017; 3 development and 2 appraisal;
Look to increase Gas volumes to existing customers and agree contracts with, and start supplying volumes to, new customers;
In H1 2017, high-grade 2 prospects for drilling;
Drill these 2 prospects in H2 2017.
Continue to explore opportunities to expand asset base in the North Africa region; and
Continue to minimise costs and crystallise synergies post completion of the acquisition of Circle Oil PLC’s businesses in Egypt and Morocco.
Paul Welch, President & CEO of SDX Energy, commented:
“I am pleased to report on the solid progress that was made throughout 2016, with high levels of activity across the entire portfolio. At North West Gemsa and
Meseda we successfully completed extensive workover programmes, with production expected to double at Meseda over the coming months. Our 3D seismic
acquisition at South Disouq was also successfully completed resulting in the identification of both oil and gas bearing prospects for our 2017 drilling campaign.
Following the completion of the technical review of prospectivity at South Ramadan, a forward plan for the concession has been developed which minimises the
Company’s capital exposure in 2017.
“The successful fundraise and acquisition of Circle’s assets in Egypt and Morocco, announced in January, demonstrates our ability to deliver on SDX’s ambitious
growth strategy. With increased production and cash flow as a result of the acquisition, our balance sheet has been further strengthened, leaving us well placed to
progress the development of the existing portfolio, while positioning the Company to capitalise on further opportunities that we are actively identifying within the
North Africa region.”
SDX Energy Inc.
2016 Annual Report 01
Financial & Operating Highlights
Proforma Combined Businesses
Three months ended December 31Twelve months ended December 31
$000’s except per unit amounts Prior quarter 2016 2015
Financial
Gross revenues 3,752 8,436 4,128 18,362 23,030
Royalties (823) (3,082) (686) (5,448) (5,467)
Net revenues 2,929 5,354 3,442 12,914 17,563
Operating costs (1,241) (1,752) (2,483) (5,282) (6,039)
Netback 1,688 3,602 959 7,632 11,524
Total comprehensive (loss)/income 140 (2,059) 8,542 (27,963) 7,358
per share - basic - (0.03) 0.23 (0.39) 0.20
Cash, end of period 4,961 4,725 8,170 4,725 8,170
Working capital (excluding cash) 4,632 7,098 3,382 7,098 3,382
Capital expenditures 188 856 2,404 13,339 6,359
Total assets 43,901 41,617 60,016 41,617 60,016
Shareholders’ equity 39,161 37,264 55,246 37,264 55,246
Common shares outstanding (000’s) 79,844 79,844 37,642 79,844 37,642
2016
2015
Operational
Oil sales (bbl/d) 510 468 652 534 759
Gas sales (boe/d) - 3,273 - 823 -
NGL sales (bbl/d) - 445 - 112 -
Production service fee (bbl/d) 704 679 704 662 760
Total oil sales and production service fee boe/d 1,214 4,865 1,356 2,131 1,519
Realized oil price (US$/bbl) 40.84 44.56 38.71 38.00 48.02
Realized service fee (US$/bbl) 28.32 31.12 27.90 26.26 35.10
Net oil sales and production service fee realized price ($/bbl) 33.58 36.60 33.09 31.51 41.55
Realized gas price (US$/mcf) - 1.22 - 1.22 -
Realized NGL price (US$/bbl) - 57.73 - 57.73 -
Net realized price - all products (US$/boe) 33.58 18.85 33.09 23.55 41.55
Royalties ($/bbl) 7.37 6.89 5.50 6.99 9.86
Operating costs ($/bbl) 11.11 3.91 19.91 6.77 10.90
Netback ($/bbl) 15.10 8.05 7.68 9.79 20.79
Financial Statements
Three months ended December31 Twelve months ended December 31
2015
$000’s except per unit amounts Prior quarter 2016 2015
Financial
Gross revenues 3,752 8,436 4,128 18,362 12,058
Royalties (823) (3,082) (686) (5,448) (686)
Net revenues 2,929 5,354 3,442 12,914 11,372
Operating costs (1,241) (1,752) (2,483) (5,282) (4,973)
Netback 1,688 3,602 959 7,632 6,399
Total comprehensive (loss)/income 140 (2,059) 8,542 (27,963) 9,400
per share - basic - (0.03) 0.23 (0.39) 0.20
Cash, end of period 4,961 4,725 8,170 4,725 8,170
Working capital (excluding cash) 4,632 7,098 3,382 7,098 3,382
Capital expenditures 188 856 2,404 13,339 5,120
Total assets 43,901 41,617 60,016 41,617 60,016
Shareholders’ equity 39,161 37,264 55,246 37,264 55,246
Common shares outstanding (000’s) 79,844 79,844 37,642 79,844 37,642
2016
Operational
Oil sales (bbl/d) 510 468 652 534 164
Gas sales (boe/d) - 3,273 - 823 -
NGL sales (bbl/d) - 445 - 112 -
Production service fee (bbl/d) 704 679 704 662 760
Total oil sales and production service fee boe/d 1,214 4,865 1,356 2,131 924
Realized oil price (US$/bbl) 40.84 44.56 38.71 38.00 38.71
Realized service fee (US$/bbl) 28.32 31.12 27.89 26.26 35.10
Net oil sales and production service fee realized price ($/bbl) 33.58 36.60 33.09 31.51 35.74
Realized gas price (US$/mcf) - 1.22 - 1.22 -
Realized NGL price (US$/bbl) - 57.73 - 57.73 -
Net realized price - all products (US$/boe) 33.58 18.85 33.09 23.55 35.74
Royalties ($/bbl) 7.37 6.89 5.50 6.99 2.03
Operating costs ($/bbl) 11.11 3.91 19.91 6.77 14.74
Netback ($/bbl) 15.10 8.05 7.68 9.79 18.97
02
SDX Energy Inc.
2016 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 high
margin production.
10,278 boe/d
16.9 mmboe
Combined Egyptian daily average gross production
for the twelve months to December 31, 2016
Asset reserves - North West Gemsa and Meseda
(gross) at December 31, 2016
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SDX Energy Inc.
2016 Annual Report 03
Where We Operate
Egypt
Our assets
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
SDX Energy is actively involved in
exploration and development activities in
three of Egypt’s premier oil provinces – the
Eastern Desert, the Nile Delta, and the
Gulf of Suez.
1,405km2
Combined asset area
Key highlights
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 gained 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.
4 concessions
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04
SDX Energy Inc.
2016 Annual Report
Where We Operate
Morocco
Our assets
Larache
Atlantic
Ocean
O u e d S e b o u
Oued Baht
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P i p
Kenitra
Sebou, a 135km2 concession and Lalla
Mimouna, a 2,211km2 concession are
both located in the Rharb Basin of
northern Morocco. These concessions
were acquired by SDX Energy in January
2017 from Circle Oil plc.
Atlantic
Ocean
MOROCCO
Algeria
Mauritania
Mali
Lalla Mimouna
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Mechra Bel Ksiri
Exploration Licence
Exploitation Licence
3D Seismic Outline
20 KM
2,246km2
Combined asset area
2 concessions
75% working interest in each
SDX Energy Inc.
2016 Annual Report 05
Chairman’s Statement
2016 was a pivotal year
for SDX as we set, and
began to deliver, our
clear, high margin
growth strategy.
In September 2016, we were pleased to welcome
both Michael Raynes, Non Executive Director,
and Mark Reid, Chief Financial Officer, to the
Board of Directors. Both have already made
significant contributions to the company.
Paul Moase and Barrie Wright, formerly Non
Executive Directors, retired from the Board and
I reiterate my thanks for their extremely valuable
service during the period of their directorships.
On behalf of the Board, I would like to thank
all our stakeholders for their continued support,
and in particular our staff in Egypt, Morocco
and the UK, our host governments, partners and
investors. We are pleased with the progress that
was made throughout 2016 and believe that we
are well placed to create further value through
2017 and beyond.
Michael Doyle
Non-Executive Chairman
Over the period, we made considerable in-roads
into establishing SDX as a North African focused
E&P of scale.
Despite the macro economic challenges that
continued to hamper many of SDX’s peers,
the Company was highly successful in moving
forward its portfolio of Egyptian assets, and in
laying the foundations for the subsequent
expansion of the business, both in Egypt and
into Morocco.
A clear highlight of 2016 was the successful
admission of SDX’s shares to trading on AIM.
London has long been established as a natural
home for ambitious E&P companies. Our high
margin, onshore production and development
assets were recognised as presenting an
attractive investment opportunity.
Consequently, we were able to accompany the
May 2016 secondary listing on AIM with a fund
raising of US$11million. We were very
heartened by the supportive response of the
investment community to the SDX story and
were extremely pleased to welcome a number of
new institutional shareholders onto the register.
Post year end, we were very pleased to be able
to announce the successful completion of the
acquisition of Circle Oil Plc’s assets in Egypt and
Morocco and a concurrent US$40 million fund
raise. This was a company transforming
transaction and was firmly in line with our stated
growth strategy. It also demonstrated the
management team’s ability to identify and
crystallise high value distressed asset
opportunities.
06
SDX Energy Inc.
2016 Annual Report
Chief Executive’s Statement
I am pleased to report that throughout 2016
considerable progress was made across SDX’s
balanced portfolio of high margin onshore
production and development assets. As I write
to you today, SDX is a considerably transformed
business from one year ago.
Average daily oil sales and production service
fees for the year equated to 1,196 barrels of oil
per day (“BOPD”) and average daily natural gas
and natural gas liquids production equated to
935 barrels of oil equivalent per day (“BOEPD”).
I am very pleased to report significant progress
across the portfolio throughout 2016. At North
West Gemsa, gross production averaged
5,344 bopd and we completed six successful
well workovers during the reporting period.
At Meseda, gross production averaged
3,439 bopd following the successful completion
of a nine well workover program. SDX is
expecting to double production at Meseda over
the coming months, and a strategy was
implemented during the year, focused on
development optimization, in order to achieve
this. 2016 saw the completion of the 3D seismic
acquisition at South Disouq. This was completed
ahead of schedule and under budget. Seismic
data processing has been completed, with
interpretation having identified potential for
both oil and gas bearing prospects. At South
Ramadan we successfully completed the
technical review of prospectivity on the
development concession and an evaluation of
project economics is currently underway which
will assist in determining the optimum way
forward for SDX in this concession.
Strong capital discipline is at the heart of
everything we do. SDX remains a very low cost
producer targeting production costs of less than
US$10 per barrel which positions us firmly at the
lower end of the industry cost curve.
We are firmly committed to our growth strategy,
as was clearly evidenced by the successful
acquisition of Circle Oil’s assets. For a
consideration of US$28.1 million, SDX acquired
total production of 3350 boepd and 2P reserves
of 4.69 MMboe, as well as working capital of
US$21.5 million excluding deferred income and
decommissioning. In addition to increasing our
working interest in Egypt’s North West Gemsa
Concession to 50%, the Morocco country entry
saw us secure a 75% working interest in the
Sebou production and Lalla Mimouna
exploration concessions.
As at February 28, 2017 SDX had a strong
liquidity position with US$18.3 million cash
on hand, and zero debt. This leaves the
company well placed to not only progress
the development of our existing well balanced
portfolio, but also to continue to capitalise on
further opportunities that it is actively
identifying in the North Africa region. Egypt
provides access to not only some of the best
geology in the world, where multiple world class
hydrocarbon basins have been discovered, but it
also has an excellent operating environment in
which SDX has a successful track record. In
Morocco, which we entered through the Circle
transaction, we enjoy one of the best fiscal
regimes within the industry, as well as access
to the very attractive domestic gas market.
2017 promises to be another extremely active
year for the company. The work over programme
continues apace at North West Gemsa, and the
facilities upgrade and remaining six well
workover programme is underway at Meseda,
where production is expected to double over the
course of the year. On March 23, 2017 we spud
the carried SD-1X exploration well at South
Disouq. South Ramadan sees a development
well being planned during the second half, and
in Morocco exploration and development
drilling is anticipated in the second half of
the year.
Finally, I would like to thank the Board for their
ongoing support, and to reiterate the Chairman’s
gratitude to the wider SDX stakeholders and
team, and in particular, to all of our shareholders
for their continuing support.
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
production
Increase value
through exploration
Growth through
low cost asset
acquisition
SDX Energy Inc.
2016 Annual Report 07
Review of Operations
Egypt
North West Gemsa Concession
Overview
The North West Gemsa concession
is located in the Eastern Desert,
300km southeast of Cairo.
Gulf of Suez
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Desert
Red Sea
North West Gemsa
GEYAD
AL AMIR
Eastern
Desert
AL OLA
Eastern
Desert
10KM
For more information please visit our website:
www.sdxenergy.com
08
SDX Energy Inc.
2016 Annual Report
The concession is 82.7km2 in area and includes three fields;
Geyad, Al Amir SE, and Al Ola (the southern extension of Al Amir SE).
All of 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 27th, 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% in 2016 to 50% at present
(Zenhua Oil (the operator) has the remaining 50%). Operatorship remains
unchanged.
The Al Amir SE and Geyad fields produce light oil (40-42o API oil; priced
at Brent less a quality discount and a marketing fee) from two reservoir
intervals; the Miocene-aged Shagar and Rahmi sandstones of the Kareem
Formation. 2016 production averaged 6,870 BOEPD (687 BOEPD net
to SDX at a 10% interest level) from the Al Amir SE and Geyad fields.
Cumulative production from North West Gemsa for 2016 was 2,496 MBOE,
bringing total production over the life of the fields to more than
24.79 million BOE.
2016 Activity
In 2016 two development wells were drilled and five workovers were
completed in the Al Amir SE and Geyad fields. The workover program
was focused on wellbore maintenance and is expected to increase well
production uptime. A summary of the results from the two development
wells are given below.
Al Amir SE-23 (AASE-23a): The AASE-23 was spud in December, 2015
and drilled to a TD of 9820 feet; the well was subsequently side-tracked
(AASE-23ST) to a more geologically favourable location and reached TD in
January, 2016. The well logged 22 feet of net pay in the Shagar sandstone
and 29 feet of net pay in the Rahmi sandstone. The well was completed in
the Shagar sandstone and was tested at 4080 BOEPD (1.3% water cut;
48/64ths choke). Improved drilling technique allowed the original wellbore
to be drilled for 30% under approved expenditure limits, and the sidetrack
for 17% under approved expenditure limits, greatly improving
well economics.
Al Amir SE-24 (AASE-24): The AASE-24 was spud in February, 2016
and was subsequently side-tracked (AASE-24ST) to a more geologically
favourable location reaching a TD of 9,925 feet in March, 2016. The well
logged 15 feet of net pay in the Shagar sandstone and 7 feet of net pay
in the Rahmi sandstone. The well was tested at an average rate of
1,714 BOPD and 3.062 MMscf/day.
During 2016 six workovers were completed in the Al Amir SE and Geyad
fields. This program was focused on wellbore maintenance and is expected
to increase well production uptime.
Unitization
Unitization talks with the offset operator have continued to progress
throughout 2016 and resolution is expected in 2017.
2017 Work Program
The 2017 work program comprises a 12 well workover program in the
Al Amir SE and Geyad fields. This program is focused on ESP installation
and maintenance as well as tubing maintenance to ensure asset integrity
and production uptime.
Review of Operations
Egypt
Block-H Meseda
Overview
Block-H is located in the Eastern Desert,
230km southeast of Cairo.
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HOSHIA
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The block is 22km2 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, while Dublin International Petroleum (the operator)
holds the remaining 50% working interest.
open
Meseda field produces from the high-quality Miocene-aged Asl sands
of the Rudeis Formation. 2016 production from Meseda field averaged
3,439 BOPD (662 BOPD net to SDX Energy) of 16-18o API oil.
Cumulative production through the end of 2016 for Meseda field
was 6,418 MBO, with cumulative production for 2016 of 1,266 MBO.
East
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South Hania
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AA
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For more information please visit our website:
www.sdxenergy.com
2016 Activity
During 2016 a nine well workover program was conducted in the Meseda
field. The program consisted of tubing and pump replacements, well bore
cleanouts, and adding perforations aimed at ensuring future production
uptime.
The partners conducted an operational strategic review of the asset during
2016 to determine the benefits of a water injection program, how to best
optimize production from existing wells, and to determine the future
development drilling and exploration programs. Results from the studies
indicate that both field production rates and oil recovery factors can be
increased. As such, the partners plan to expand the existing facilities and
undertake a further pump replacement and upgrade program as described
below in the 2017 Work Program.
2017 Work Program
Following the 2016 operational strategic review of the asset described
above, the partners plan to drill two exploration wells, two development
wells (pending government approval) and conduct up to six pump
replacements and upgrades in existing wells to increase production.
A tender for the necessary equipment is currently being conducted and
the campaign is expected to begin in Q2 2017. Furthermore, it is planned
to expand the central processing facility.
This expansion will accommodate the planned increase in production,
enabling the central processing facility to handle 20,000 barrels of fluid per
day compared to its current operating range of 12,000-14,000 barrels of
fluid per day. The facility design work has been completed and long lead
time equipment has been ordered. It is anticipated that construction work
will begin in Q2 2017 with minimal disruption to existing production.
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SDX Energy Inc.
2016 Annual Report 09
Review of Operations
Egypt
South Ramadan Concession
Overview
The 26km2 South Ramadan development
concession is located in the offshore Gulf
of Suez, between the prolific Ramadan
and Morgan fields.
Gulf of Suez
RAMAD
AN
South Ramadan
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For more information please visit our website:
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10
SDX Energy Inc.
2016 Annual Report
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.
2016 Activity
In 2016 seismic reprocessing activities were completed and the final PSTM
and PSDM 3D seismic volumes were received. Subsequent interpretations
of the data have delineated potential appraisal locations. A technical
review of prospect volumetrics and economics has been completed.
The partners are currently in discussions with government authorities
to request an extension to complete the drilling commitment.
2017 Work Program
In 2017 the partners anticipate conducting additional studies to evaluate
potential appraisal drilling options. Drilling operations are not expected to
commence until after 2017.
Review of Operations
Egypt
South Disouq Concession
Overview
South Disouq is a 1,275km2 concession
located 65km north of Cairo in the Nile
Delta region.
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For more information please visit our website:
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The concession is along trend with numerous, prolific gas fields in the
Abu Madi Formation. SDX Energy holds a 55% interest and operates
the concession, with IPR holding the remaining 45% interest.
2016 Activity
SDX Energy conducted seismic acquisition operations in the first half of
2016, acquiring 300km2 of high-quality 3D seismic data on schedule and
under budget, with zero reportable HSE incidents. Seismic processing was
conducted in the second half of 2016 and the final pre-stack time
migration (PSTM) and pre-stack depth migration (PSDM) volumes
have been delivered.
The 3D seismic data confirmed the extension of the Abu Madi play fairway
into the South Disouq concession. Subsequent interpretation of the 3D
seismic data has also highlighted the presence of several structural closures
both at the Abu Madi level, which is productive in several nearby fields,
and at deeper structural levels that correspond to producing horizons
present in Egypt’s Western Desert region.
Planning for the initial exploration well, SD-1X, started in Q3 2016.
The drilling location has been finalized, all of the required government
approvals have been granted, and the well design and drilling program
have been finalized.
2017 Work Program
In Q1 2017 Site construction was completed, conductor pipe installed,
and the drilling rig mobilized to location. It is anticipated that the SD-1X
exploration well which spud on March 23, 2017 is expected to reach TD
in mid-late April 2017. This well will satisfy the outstanding work
commitments for the initial work program and will test target intervals in
the Kafr El Sheikh, Abu Madi, Apollonia, and Abu Roash Formations. The
concession has been extended by 6 months to allow the results from the
well to be incorporated into the decision to enter into the secnd
exploration phase.
SDX Energy Inc.
2016 Annual Report 11
Review of Operations
Morocco
Sebou Concession & Lalla Mimouna Concession
Overview
Sebou, a 135km2 concession and Lalla
Mimouna, a 2,211km2 concession are both
located in the Rharb Basin of northern
Morocco, was acquired by
SDX Energy in January 2017 from
Circle Oil plc.
Larache
Atlantic
Ocean
MOROCCO
Algeria
Mauritania
Mali
Lalla Mimouna
O u e d S e b o u
Oued Baht
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P i p
Mechra Bel Ksiri
Exploration Licence
Exploitation Licence
3D Seismic Outline
20 KM
Atlantic
Ocean
Kenitra
For more information please visit our website:
www.sdxenergy.com
Sebou
2D and 3D seismic data have been collected over most of the concession
and sixteen wells have been drilled to date, resulting in 13 natural gas
discoveries. SDX has a 75% working interest and operates the concession,
with ONHYM (Office National Des Hydrocarbures Et Des Mines; the
Moroccan national oil company) holding the remaining 25% interest.
The gas produced from the concession is sold to customers located in
the Kenitra industrial zone some 55km from the field. The sales points in
Kenitra are connected to the field through a 55km 8-inch pipeline which
is 75% owned by the Company (with the other 25% owned by ONHYM).
At the time of acquisition, (January 27th, 2017), gross average annual
production was c.6MMscf/day (4.5MMscf/d net to SDX Energy).
Production is currently from the Miocene-aged Hoot and Guebbas
formations, which are high quality reservoir intervals with favourable
properties. Interpretation of the 3D seismic data has highlighted several
additional infill development drilling locations and near-field exploration
locations. As of July 1st, 2016, total proved + probable reserves were
estimated at 7.1 Bcf (5.3 Bcf net).
2017 Work Program
SDX Energy is currently planning drilling activities for the second half of
2017 and anticipates drilling three development wells and two appraisal
wells in the concession. The three development wells are planned in the
Kisiri field and will ensure deliverability to existing customers, allow volumes
to start being supplied to new customers and increase overall gas production
capacity. The two appraisal wells will test seismic anomalies similar to those
present in successful offset wells. All the selected locations are adjacent to
existing infrastructure and can be placed on production quickly.
Lalla Mimouna
SDX has a 75% working interest and operates the concession,
with ONHYM holding the remaining 25% interest.
Interpretation of a 154km2 of 3D seismic data previously acquired in the
concession has highlighted a number of amplitude-supported prospects
across the acreage at stratigraphic levels equivalent to those producing
in the Sebou concession.
2017 Work Program
SDX Energy anticipates drilling two of the high-graded prospects
in the second half of 2017.
12
SDX Energy Inc.
2016 Annual Report
Review of Operations
Cameroon
Bakassi West Concession
Overview
The Manatee 1-X exploration well concession
(SDX Energy, 35%; Dana Petroleum, 55%,
operator; SoftRock Oil and Gas, 10%) was
drilled in Q1/Q2 2016.
For more information please visit our website:
www.sdxenergy.com
The Manatee 1-X reached a TD of 1,447 meters after intersecting 26
meters of gas bearing section of varying quality on March 27, 2016.
Although the well represents an important discovery in the basin, gas
market economics did not support further activity in the area. As such
SDX Energy exited the concession, assigning its interest in the concession
to SoftRock Oil and Gas, effective July 31, 2016 (as did partner
Dana Petroleum). All in-country operations and associated business
have been concluded.
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SDX Energy Inc.
2016 Annual Report 13
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, Gaffney, Cline & Associates, London, England (“GCA”) in their report dated March 16, 2017.
Reconciliation of gross reserves as at December 31, 2016
Forecast prices and costs
Light & medium crude oil Heavy crude oil Natural gas LPGs BOE
Proved Proved Proved Proved Proved
plus plus plus plus plus
Proved Probable probable Proved Probable probable Proved Probable probable Proved Probable probable Proved Probable probable
(mmbbl) (mmbbl) (mmbbl) (mmbbl) (mmbbl) (mmbbl) (bcf) (bcf) (bcf) (mmbbl) (mmbbl) (mmbbl) (mmboe) (mmboe) (mmboe)
December 31, 2015 0.56 0.21 0.77 1.14 1.32 2.46 632 233 865 0.02 0.01 0.03 1.83 1.58 3.41
2016 Production (0.20) - (0.20) (0.30) - (0.30) (259.95) - (259.95) (0.01) - (0.01) (0.55) - (0.55)
Technical Revisions 0.05 (0.08) (0.02) 0.77 (0.78) (0.01) 60.06 (84.82) (24.76) 0.00 (0.00) (0.00) 0.84 (0.87) (0.04)
Economic Factors (0.08) 0.04 (0.04) (0.03) (0.04) (0.08) (129.40) 14.90 (114.50) (0.01) - (0.01) (0.14) (0.00) (0.15)
December 31, 2016 0.33 0.17 0.50 1.58 0.50 2.08 303 163 466 0.01 0.00 0.01 1.97 0.71 2.68
In Meseda field reserves have been shifted from probable to proved as the completion of the reservoir studies and the finalization of facility upgrades
have increased certainty in the expected recovery factors.
Although spot oil prices for Brent have improved since 2015, the forward-looking price deck used by GCA in their independent evaluation of reserves is
lower than the forward -looking price deck used by DeGolyer & MacNaughton. This change to a more conservative price deck is responsible for a majority
of the revisions ascribed to “economic factors” in the reconciliation table presented above.
Summary of oil and gas reserves at December 31, 2016
Light & medium crude oil Heavy crude oil Natural gas LPGs
Gross Net Gross Net Gross Net Gross Net
Category (mmbbl) (mmbbl) (mmbbl) (mmbbl) (bcf) (bcf) (mmbbl) (mmbbl)
Proved Developed Producing 0.306 0.141 3.210 1.230 0.274 0.127 0.006 0.003
Proved Developed Non-Producing 0.025 0.012 0.915 0.350 0.030 0.013 0.001 0.000
Total Proved 0.331 0.153 4.125 1.580 0.304 0.140 0.007 0.003
Probable 0.173 0.080 1.325 0.500 0.162 0.075 0.004 0.002
Total Proved plus Probable 0.504 0.233 5.450 2.080 0.466 0.215 0.011 0.005
Possible 0.223 0.103 1.755 0.670 0.210 0.097 0.005 0.002
Total Proved plus Probable plus Possible 0.727 0.336 7.205 2.750 0.676 0.312 0.016 0.007
Summary of net present values of future net revenues as of December 31, 2016
Forecast prices and costs (in US$ milions)
After income tax
Discounted at
Category 0% 5% 10% 15% 20%
Proved Developed Producing 33.9 30.01 26.98 24.58 22.63
Proved Developed Non-Producing 9.02 6.74 5.16 4.02 3.16
Total Proved 42.92 36.75 32.14 28.6 25.8
Probable 20.78 14.7 10.97 8.57 6.94
Total Proved plus Probable 63.7 51.45 43.11 37.16 32.75
Possible 30.97 21.77 16.15 12.53 10.1
Total Proved plus Probable plus Possible 94.66 73.22 59.27 49.7 42.84
Reserve Definitions:
(1) 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.
(2) 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.
(3) 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.
(4) 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 GCA’s report dated March 16, 2017 filed on the SEDAR website at www.sedar.com.
14
SDX Energy Inc.
2016 Annual Report
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 currently serves there as Managing Director.
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 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.
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.
Mr Mitchell was appointed CEO of Madison PetroGas on joining in 2008,
building the company prior to the merger with Sea Dragon Energy.
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 Parkbridge Lifestyle Communities Inc. and a director of Realex
Properties Corp. Previously public board experience includes Boardwalk
Equities, Alliance Atlantis Movie Distribution Income Fund, Forte Energy
and Bonnetts Energy Services Trust.
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 7 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 7 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.
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.
Prior to Michael’s role at Waha Capital, he was a Senior Investment Banker
with Barclays Capital in London.
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SDX Energy Inc.
2016 Annual Report 15
Remuneration Report
The remuneration of the directors for the year ended December 31, 2016 was as follows:
Termination
Fees/basic salary Pension Benefits in kind benefits
US$ US$ US$ US$
Paul Welch (1) 450,000 - 65,386 -
Said Arrata (2) - - - -
Olivier Serra (3) - - - -
Mark Reid (4) 270,088 13,504 1,358 -
Ken Fitzgerald (5) - - - -
Barry Swan (5) - - - -
Robert Moffat (5) - - - -
Paul Moase (7) 18,750 - - -
Michael Doyle (6) 35,000 - - -
David Mitchell (6) 30,000 - - -
David Richards (6) 35,000 - - -
Barrie Wright (6) (7) 18,750 - - -
Michael Raynes (8) - - - -
Total 2016
US$
515,386
-
-
284,950
-
-
-
18,750
35,000
30,000
35,000
18,750
-
Total 2015
US$
547,246
461,550
735,428
43,310
14,668
14,668
14,668
21,177
9,112
6,509
9,112
7,810
-
(1) Mr. Welch was appointed President and Chief Executive Officer on April 12, 2013.
(2) On April 12, 2013 Mr. Arrata resigned as Chief Executive Officer but continued on as Chairman of the Corporation. Mr. Arrata resigned as Chairman of the Corporation on September 30, 2015 and in accordance
with his contract of employment is entitled to receive $500,000 for loss of office.
(3) Mr. Serra resigned his position of Chief Financial Officer with the Corporation, by mutual consent, on November 13, 2015. In accordance with his contract of employment Mr. Serra is entitled to receive 200,000 GBP
in lieu of notice and an ex gratia payment of 83,333 GBP.
(4) Mr. Reid was appointed Chief Financial Officer on November 13, 2015 and was appointed as a director on September 26, 2016.
(5) Messrs. Fitzgerald, Swan and Moffat resigned as directors effective September 30, 2015 upon completion of the business combination between the Corporation and Madison Petrogas Ltd.
(6) 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.
(7) Messrs. Moase and Wright retired as directors on September 26, 2016.
(8) Mr. Raynes was appointed as a director on September 26, 2016. He received no fees or other remuneration for this role as he is a representative of a major shareholder.
Stock-based compensation
During the period 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 US0.1 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.
In 2015 the Company incurred share-based payment charges of US$796k in respect of the above named directors.
Share options granted for directors who served during the year are as follows:
Options held at Granted Lapsed/forfeited
January 1, 2016 during the year
Options held at
during the year December 31,2016
Executive directors
Paul Welch 800,000 -
Mark Reid 400,000 -
Non-executive directors
Michael Doyle 160,000 -
David Mitchell 160,000 -
David Richards 160,000 -
Paul Moase (1) 160,000 -
Barrie Wright (1) 160,000 -
-
-
-
-
-
(160,000)
(160,000)
800,000
400,000
160,000
160,000
160,000
-
-
(1) The share options held by Messrs. Moase and Wright lapsed on their retirement as directors.
16
SDX Energy Inc.
2016 Annual Report
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 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 continues 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 Wilmington Capital Management Inc.
Mood Media Inc.
Standard Exploration
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Orientation and continuing education
The Board 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 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 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
outside directors on an annual basis, taking into account such matters
as time commitment, responsibility and compensation provided by
comparable organizations.
See page 16 for details of compensation paid to Directors during 2016.
SDX Energy Inc.
2016 Annual Report 17
Corporate Governance Statement
continued
Reserves Committee
The Board 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 managements’
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 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.
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.
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 David Richards (Chair)
and Michael Doyle. 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 authorizing its use, determining the number of
options, and the terms thereof, that may be issued under the stock option
plan of the Corporation during any particular period and issuing or
authorizing the issuance of such options 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.
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SDX Energy Inc.
2016 Annual Report
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
10,278 boe/d
16.9 mmboe
Combined Egyptian daily average gross production
for the twelve months to December 31, 2016
Asset reserves - North West Gemsa and Meseda
(gross) at December 31, 2016
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SDX Energy Inc.
2016 Annual Report 19
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Basis of Presentation
The following Management’s Discussion and Analysis (the “MD&A”) dated March 24, 2017 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, 2016. This MD&A should be read
in conjunction with the accompanying Consolidated Financial Statements for the year ended December 31, 2016. In order to provide the reader with a
better understanding of the underlying operational performance of the combined business (of Sea Dragon and Madison) for the twelve months ended
December 31, 2016 and 2015, this MD&A also includes various sections headed ’Proforma’. These proforma sections include details of the performance
of the combined business on a twelve months to December 31, 2016 basis versus a twelve months to December 31, 2015 basis. The proforma sections
commence after the completion of the sections of the MD&A based on the Consolidated Financial Statements for the period ended December 31, 2016
which have been prepared under IFRS 3 - Business Combinations.
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.
20
SDX Energy Inc.
2016 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 August 18, 2015 Sea Dragon Energy Inc. (“Sea Dragon”) and Madison Petrogas Ltd (“Madison”) entered into an Arrangement Agreement whereby
Sea Dragon acquired all the issued and outstanding Madison shares. Prior to the closing of the transaction Sea Dragon effected a 35:1 share consolidation
and as a result of this share consolidation the exchange ratio equated to 0.477143 Sea Dragon share for each Madison share.
The business combination and closing of the transaction was effected on October 1, 2015 at which date the former Madison shareholders held
approximately 71% of the combined entity known as SDX Energy Inc.
In preparing the Consolidated Financial Statements the Company must conform with IFRS 3 – Business Combinations. Given that the former Madison
shareholders hold 71% of the combined entity, Madison was treated as the acquirer. This means that in the Consolidated Financial Statements to
December 31, 2016, whilst the 2016 figures in the Consolidated Statement of Comprehensive (Loss)/Income relates to the combined entity, the 2015
comparatives contain twelve months of revenue and costs for Madison and only three months of revenue and costs for Sea Dragon.
Post-balance sheet acquisition
As detailed in note 28 to the Consolidated Financial Statements for the year ended December 31, 2016, on January 27, 2017, the Company announced
the acquisition of the Egyptian and Moroccan assets of Circle Oil plc. The analysis included in this MD&A does not cover these assets.
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.
As mentioned above, in order to provide the reader with a better understanding of the underlying operational performance of the combined business
(of Sea Dragon and Madison) for the periods ended December 31, 2016 and 2015, this MD&A also includes various sections headed ’Proforma’.
These proforma sections include details of the performance of the combined business on a twelve months to December 31, 2016 basis versus twelve
months to December 31, 2015 basis for the combined entity (former Sea Dragon Energy Inc. and Madison Petrogas Ltd).
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 schedule under the outlook section below.
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SDX Energy Inc.
2016 Annual Report 21
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
SDX Energy’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 six concessions with short and long-term potential. The Company exited its operation in Cameroon on July 31, 2016 (see below).
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 and development wells
in its existing portfolio in Egypt and Morocco, combined with high impact exploration drilling in Egypt and Morocco. After analyzing its Bakassi West gas
discovery in Cameroon, and due to challenging gas market economics, the Company decided to exit the concession and the country. In pursuing this
strategy, SDX also intends to leverage its balance sheet, which has been strengthened as a result of its successful US$11 million Placing (less expenses of
c. US$1 million) which closed during Q2 2016, its early mover advantage and its regional network to grow through the acquisition of undervalued and/or
underperforming producing assets principally in onshore Egypt, while maintaining a strict financial discipline to ensure an efficient use of funds.
Subsequent to year end, 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 28 to the Consolidated Financial Statements .
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 one 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.); and
• Morocco (exploration) - The Lalla Mimouna Concession (“Lalla Mimouna”) – (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.
2017 Work program
The Company’s capital expenditure program for 2017 is expected to be approximately US$15.5 million.
In North West Gemsa, the Company will invest c.US$2.2 million for its share of a 12 well workover program focused on ESP installation and maintenance
to increase production uptime.
In Meseda, up to c.US$4.2 million will be contributed for the Company’s share of the cost of drilling two exploration wells and two development wells
(subject to government approval), and completing up to six pump replacements and upgrades in existing wells to increase production. Furthermore,
to accommodate the expected increase in production in 2017, it is planned to expand the central processing facility to enable it to handle 20,000 barrels
of fluid per day compared to its current operating range of 12,000-14,000 barrels of fluid per day.
In South Disouq, the Company estimates that it will incur up to cUS$1.3 million of cost in relation to the drilling of the SD-1X exploration well,
the majority of which relates to cost of drilling to the prospect’s deeper oil target.
In Morocco, a drilling program of up to seven wells is targeted for 2017. The drilling cost of up to US$7.8 million will cover three development
and two appraisal wells in the Sebou concession and two exploration wells in the Lalla Mimouna concession.
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SDX Energy Inc.
2016 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.
Operational and Financial information contained below represents the IFRS 3 information extracted from the Financial Statements for the years ended
December 31, 2016 and 2015.
Three months ended December 31 Twelve months ended December 31
2015
$000’s unless stated Prior quarter (1) 2016 2015
Operational
Oil revenue 1,917 1,920 2,322 7,432 2,322
Royalties (823) (824) (686) (3,190) (686)
Net oil revenue 1,094 1,096 1,636 4,242 1,636
2016
Gas revenue - 2,210 - 2,210 -
Royalties - (1,059) - (1,059) -
Net gas revenue - 1,151 - 1,151 -
NGL revenue - 2,361 - 2,361 -
Royalties - (1,199) - (1,199) -
Net NGL revenue - 1,162 - 1,162 -
Production service fee revenue 1,835 1,945 1,806 6,359 9,736
Total net revenue 2,929 5,354 3,442 12,914 11,372
Operating costs (1,241) (1,752) (2,483) (5,282) (4,973)
Netback (pre tax) 1,688 3,602 959 7,632 6,399
Oil sales (bbl/d) 510 468 652 534 164 (3)
Gas sales (boe/d) (2) - 3,273 - 823 -
NGL sales (bbl/d) (2) - 445 - 112 -
Production service fee (bbl/d) 704 679 704 662 760
Total boe/d 1,214 4,865 1,356 2,131 924
Oil sales volumes (bbls) 46,935 43,087 59,988 195,588 59,988
Gas sales volumes (boe) - 301,137 - 301,137 -
NGL sales volumes (bbls) - 40,897 - 40,897 -
Production service fee volumes (bbls) 64,792 62,504 64,751 242,146 277,407
Total sales volumes (boe) 111,727 447,625 124,739 779,768 337,395
Brent oil price (US$/bbl) $45.78 $49.23 $43.56 $41.70 $52.30
West Gharib oil price (US$/bbl) $34.86 $34.86 $34.35 $32.43 $42.81
Realized oil price (US$/bbl) $40.84 $44.56 $38.71 $38.00 $38.71
Realized service fee (US$/bbl) $28.32 $31.12 $27.89 $26.26 $35.10
Realized oil sales price and service fee $33.58 $36.60 $33.09 $31.51 $35.74
Realized gas price (US$/mcf) - $1.22 - $1.22 -
Realized NGL price (US$/bbl) - $57.73 - $57.73 -
Net realized price - all products (US$/boe) $33.58 $18.85 $33.09 $23.55 $35.74
Total royalties (US$/boe) $7.37 $6.89 $5.50 $6.99 $2.03
Operating costs (US$/boe) (4) $11.11 $3.91 $19.91 $6.77 $14.74
Netback - (US$/boe) $15.10 $8.05 $7.68 $9.79 $18.97
Capital expenditures 188 856 2,404 13,339 5,120
(1) Three months ended September 30, 2016.
(2) As discussed elsewhere in this MD&A, invoices for NGL and gas sales from NW Gemsa were issued during Q4 2016 but for the period February 2013 – December 2016. Actual gas and NGL sales generated for the three
and twelve months ended December 31, 2016 were 130 boe/d and 17 boe/d for the three months ended December 31, 2016 135 boe/d and 18 boe/d for the twelve months ended December 31, 2016.
(3) Due to the IFRS 3 accounting treatment for the Sea Dragon and Madison business combination in 2015, the Consolidated Financial Statements for the year ended December 31, 2015 only included oil sales by
Sea Dragon for period October 1, 2015 to December 31, 2015. If the oil sales for the full year had been included, oil sales would have been 759 bbl/d.
(4) Operating costs/boe of US$3.91 and US$6.77 for the three and twelve months ended December 31, 2016 reflect the inclusion of the gas and NGL volumes discussed at footnote (2) above.
If these volumes and associated costs were excluded from these Operating costs/boe metric would increase to US$13.75 and US$11.38 per boe respectively.
SDX Energy Inc.
2016 Annual Report 23
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Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Operational and financial highlights (continued)
Oil sales and production service fee revenues
Three months ended December 31 Twelve months ended December 31
$000’s
Prior quarter 2016 2015 2016 2015
Oil sales revenue 1,917 1,920 2,322 7,432 2,322
Production fee revenues 1,835 1,945 1,806 6,359 9,736
Oil sales and production fee revenues 3,752 3,865 4,128 13,791 12,058
Oil sales revenue (relates to NW Gemsa and Shukheir Marine only)
Total oil sales volumes for the three months ended December 31, 2016 averaged 468 bbl/d compared to 652 bbl/d for the comparative period of the prior year.
Total sales volumes fell by 16,901 barrels, 28%, to 43,087 barrels in the three months ended December 31, 2016 compared to 59,988 in the comparative
period of 2015. The North West Gemsa concession reached peak production rate in Q4 2014 and volumes have now started to decline.
For the three months ended December 31, 2016 the Company received an average price per barrel of oil of US$44.56 compared to the average Brent Oil
price (“Brent”) of US$49.23; a discount of US$4.67/9% per barrel. 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.
Variance from prior year
For the three months ended December 31, 2016 (compared to the three months ending December 31, 2015) the decrease in oil sales revenue of
US$0.4 million, 17%, to US$1.9 million is due to an increase in realized sales price (US$0.3 million) or 11%, more than offset by a decrease in sales
volume (US$0.7 million), or 28%.
$000’s
Three months ended December 31, 2015 2,322
Price variance 253
Production variance (655)
Three months ended December 31, 2016 1,920
Variance from prior quarter
For the three months ended December 31, 2016 (compared to the three months ending September 30, 2016) oil sales revenue was consistent
with the increase in sales price of US$0.2 million, 8%, being offset by a decrease in sales volume of US$0.2 million, 8%.
$000’s
Three months ended September 30, 2016 1,917
Price variance 161
Production variance (158)
Three months ended December 31, 2016 1,920
24
SDX Energy Inc.
2016 Annual Report
Production service fee revenue (relates to Meseda only)
Total production service fee volumes decreased by 2,247 barrels, 3%, to 62,504 barrels compared to the three months ended December 31, 2015.
This was as a result of natural reservoir decline and resulted in a net reduction of 25 bbl/d in 2016 compared to 2015.
For the three months ended December 31, 2016 the Company received an average service fee per barrel of oil of US$31.12 compared to the average West
Gharib price of US$34.86; a discount of US$3.74, 11%, per barrel. The Company receives a discount to West Gharib due to the quality of the oil produced.
Variance from prior year
For the three months ended December 31, 2016 (compared to the three months ending December 31, 2015) the increase in production service fee
revenue of US$0.1 million, 8%, to US$1.9 million is due to an increase in realized sales price (US$0.2 million) or 11%, partially offset by a decrease
in sales volume (US$0.1 million), or 3%.
$000’s
Three months ended December 31, 2015 1,806
Price variance 202
Production variance (63)
Three months ended December 31, 2016 1,945
Variance from prior quarter
For the three months ended December 31, 2016 (compared to the three months ending September 30, 2016) the increase in production service fee
revenue of US$0.1 million, 6%, to US$1.9 million is due to an increase in realized sales price (US$0.2 million) or 10%, partially offset by a decrease
in sales volume (US$0.1 million), or 4%.
$000’s
Three months ended September 30, 2016 1,835
Price variance 175
Production variance (65)
Three months ended December 31, 2016 1,945
Gas and Natural Gas Liquids (“NGLs”) sales
The Company commenced sales of gas and Natural Gas Liquids (“NGLs”) in February 2013 from the NW Gemsa concession, recognizing revenue from February
2013 to September 2013 of that year. Subsequent to this, the Company ceased recognizing revenue due a dispute with EGPC over entitlement volumes and
pricing. This dispute has now been resolved such that the Company believes it appropriate to recognize revenues before State royalty deductions from
October 1, 2013 to December 31, 2016, which equates to US$2.2 million of gas sales and US$2.4 million of NGLs. These sales were recognized in Q4 2016
and are reflected in the Consolidated Financial Statements.
Direct Operating Costs
Three months ended December 31 Twelve months ended December 31
$000’s Prior quarter 2016 2015
2015
NW Gemsa 377 1,014 377 2,170 377
Shukheir Marine - - 1,205 - 1,205
Block-H Meseda 863 737 897 3,086 3,387
Other
1 1 4 26 4
Direct operating costs 1,241 1,752 2,483 5,282 4,973
2016
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Direct operating costs for the three and twelve months ended December 31, 2016 were US$1.8 million and US$5.3 million respectively compared
to US$2.5 million and US$5.0 million for the comparative periods of the prior year. Prior quarter direct operating costs are US$0.6 million lower at
US$1.2 million compared to US$1.8 million for the three months to December 31, 2016.
NW Gemsa
NW Gemsa direct operating costs for the three months to December 31, 2016 for NW Gemsa were US$0.6 million higher than the comparative
three month period of the prior year and $US0.6 million higher than the prior quarter. This was a result of increased allocation of operator overheads
(US$0.3 million) and operating costs associated with the recognition of NGL and gas sales revenues (US$0.3 million).
Block H-Meseda
Direct operating costs for the three months to December 31, 2016 for Block H-Meseda were US$0.2 million lower than the comparative three month
period of the prior year and $US0.1 million lower than the prior quarter. These decreases were in line with lower production in the relevant periods.
SDX Energy Inc.
2016 Annual Report 25
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Operational and financial highlights (continued)
Impairment charge
At the reporting date, management performed an impairment indicator assessment and concluded that due to a reduction in the proved and probable
reserves for the NW Gemsa concession, as well as reserve auditor lower price forecasts for future years, the asset should be tested for impairment.
The impairment test was carried out in accordance with the accounting policy note stated in note 3. The recoverable amounts of the field has been determined
based on a value-in-use calculation. This calculation requires the use of estimates. The present values of future cash flows were computed by applying forecast
prices for oil and gas reserves to estimated future production of proved and probable reserves. The present value of estimated future net revenues is computed
using a discount factor of 12.5%. The discount rate used reflects the specific risks relating to the underlying cash generating unit (“CGU”).
Based on this calculation for NW Gemsa an impairment charge of US$4.3 million has been recorded.
The value in use calculation assumes Brent oil sales prices in US$/bbl as follows:
2016 2017 2018 2019 2020 2021 2022
US$54.40 US$58.25 US$57.85 US$50.05 US$58.61 US$59.17 US$59.85
If the discount factor applied to the impairment test were to increase by 2.5% above the current factor of 12.5%, the impairment of the NW Gemsa field
would increase by US$0.2 million. If the discount factor applied to the impairment test were to decrease by 2.5% below the current factor of 12.5%, the
impairment of the NW Gemsa field would decrease by US$0.1 million.
A 10% reduction in the Brent oil sales price would increase the impairment by US$1.1 million.
A 15% reduction in the Brent oil sales price would increase the impairment by US$1.6 million.
In the year to December 31, 2015, the NW Gemsa field was impaired by US$6.8 million, due to falling crude oil prices and a reduction in the proved and
probable reserves.
Current Taxes
Three months ended December 31 Twelve months ended December 31
2015
$000’s Prior quarter 2016 2015 2016
Current taxes 363 643 346 1,499 1,168
Current taxes for the three and twelve months ended December 31, 2016 were US$0.6 million and US$1.5 million respectively compared to US$0.3 million
and US$1.2 million for the comparative period of the prior year.
Current taxes increased by US$0.3 million for the three months ended December 31, 2016 when compared to 2015 due the recognition of NGL and gas
sales (discussed above) in the Consolidated Financial Statements during 2016.
Capital expenditures
The following table shows the capital expenditure for the Company in accordance with IFRS3 –Business Combinations and this agrees to the notes 10 and
11 of the Consolidated Financial Statements for the period ended December 31, 2016.
Three months ended December 31 Twelve months ended December 31
$000’s Prior quarter 2016 2015 2016
2015
Property, plant and equipment expenditures ("PP&E") 136 591 (28) 1,705 1,375
Exploration and evaluation expenditures ("E&E") 52 212 2,419 11,566 3,728
Office furniture and fixtures - 53 13 68 17
Capital expenditures 188 856 2,404 13,339 5,120
During the twelve months ended December 31, 2016, the Company incurred capital expenditures of US$1.8 million on PP&E and office furniture and
fixtures, and US$11.6 million on E&E.
The PP&E additions of US$1.8 million predominantly related to the NW Gemsa concession and were for the drilling of Al Amir SE-23 and Al Amir SE-24,
and the well workover programme.
The E&E additions of US$11.6 million consists of US$5.6 million primarily in relation to the drilling of the Manatee 1-X exploration well in the Bakassi West
block in Cameroon (“Bakassi West”) and US$6.0 million in relation to the 3D seismic programme in the South Disouq concession in Egypt.
26
SDX Energy Inc.
2016 Annual Report
Property Plant and Equipment
The following table shows the cumulative costs and associated depletion, depreciation and impairment for property, plant and equipment on all of the
Company’s oil and gas properties. Please see note 10 to the Consolidated Financial Statements for further details:
December 31
$000’s
2015
Oil and gas properties, at cost 32,368 44,775
Accumulated depletion, depreciation, amortization and impairment (19,862) (26,446)
Net Book Value 12,506 18,329
December 31
2016
Furniture and fixtures, at cost 188 567
Accumulated depletion, depreciation and amortisation (89) (495)
Net Book Value 99 72
Property, plant and equipment, end of period 12,605 18,401
At December 31, 2016 for the purposes of the depletion calculation, US$3.3 million (December 31, 2015 – US$3.4 million) of future development
costs are included in the calculation of cost in determining the depletion rate.
Intangible Exploration and Evaluation Assets
The following table shows the cumulative costs for the intangible exploration and evaluation assets on all the Company’s oil and gas properties.
Please see note 11 to the Consolidated Financial Statements for further details:
December 31
$000’s
2015
Exploration and evaluation assets, beginning of period 23,473 16,460
Additions 11,566 3,728
Acquisitions (business combination) - 3,267
Transfer to exploration expense (24,416) 18
Exploration and evaluation assets, end of period 10,623 23,473
December 31
2016
On June 16, 2016 the Company issued a press release announcing its intention to withdraw from the Bakassi West, Cameroon concession
(which became effective July 31, 2016).
As the Bakassi West drilling operations had been completed by June 30, 2016, the Company made a full provision against the capitalised exploration
cost of US$24.4 million and reflected the relevant impairment in the Statement of Comprehensive Income Statement for the period to June 30, 2016.
There has been no material change to this position as at December 31, 2016.
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.
Given that as part of the business combination that occurred in October 2015 Sea Dragon Inc performed a 35:1 share consolidation and that Madison
was previously a privately held company, 12 month comparative figures are not included in the below table.
Three months Three months Twelve months
ended ended ended
December 31 December 31 December 31
Trading statistics Prior quarter 2016 2015 2016
High (CDN) $0.47 $0.55 $1.05 $0.70
Low (CDN) $0.33 $0.34 $0.43 $0.26
Average volume 29,642 64,108 29,669 38,599
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SDX Energy Inc.
2016 Annual Report 27
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Liquidity and capital resources (continued)
Share capital (continued)
The following table summarizes the outstanding common shares, options and warrants as at March 24, 2017, December 31, 2016 and December 31, 2015
for SDX Energy Inc.
December 31
2015
Outstanding as at
Common shares 186,900,253 79,843,902 37,642,067
Warrants - - 610,743
Options 2,445,000 2,445,000 2,650,000
December 31
2016
March 24
2017
The increase in Common shares as at December 31, 2016 relates to the unconditional new Common shares issued on May 20, 2016 on completion of SDX’s
Placing and dual listing on AIM plus a further 3,910,000 conditional Common shares issued to an investor on July 25, 2016 upon receipt of TSX approval as
an Insider. The increase in Common shares as at March 24, 2017 relates to the unconditional Common shares issued on January 27, 2017 on completion of
a further placing of shares to fund the acquisition of Circle Oil plc’s Egyptian and Moroccan assets, see further discussion elsewhere in this MD&A and
within note 28 to the Consolidated Financial Statements.
The 610,743 warrants expired on July 27, 2016.
The following table summarizes the outstanding options as at December 31, 2016:
Outstanding options Vested options
Number of Remaining Number of Remaining
Exercise price range options contractual life options contractual life
CAD $0.36 - $0.63 2,445,000 3 - 5 years 1,566,651 3 - 5 years
Stock based compensation
The Company has an 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.
During the period 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. As a result, a non-cash stock based compensation credit of US$0.1m has
been recognized for the twelve months ended December 31, 2016. For the twelve months ended December 31, 2015 the Company recorded a non-cash
stock based compensation charge of US$0.8 million.
Inventory
As at December 31, 2016 the Company undertook a comprehensive stockcounting exercise over all spare parts and consumables inventory. Given the
forthcoming exploration 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 SD1-X well. This inventory was from legacy exploration operations and
previously was carried at nil value as it was not planned to be used and thus was uncertified, and due to the limited resale market in Egypt was therefore
fully provided-for. The reversal of the provision previously recognized against this inventory has resulted in a US$0.5 million credit to the Consolidated
Statement of Comprehensive Income.
Capital Resources
As at December 31, 2016 the Company had working capital of approximately US$11.8 million. The Company expects to fund its 2017 capital program
through funds generated from operations and cash on hand.
As at December 31, 2016, the Company had cash and cash equivalents of US$4.7 million compared to US$8.2 million as at December 31, 2015.
As at February 28, 2017, and post the Company’s US$40 million (before costs) Equity Placing and purchase of the Egyptian and Moroccan businesses
of Circle Oil plc for US$28.1 million, the Company’s cash and cash equivalents were US$18.3 million.
During the twelve months the Company had net cash outflows of US$3.5 million (including the effects of foreign exchange on cash and cash equivalents).
For further detail, please see sources and uses table below.
28
SDX Energy Inc.
2016 Annual Report
As at December 31, 2016, the Company had US$9.5 million in trade and other receivables compared to US$6.7 million as at December 31, 2015.
Approximately US$7.7 million will be due from a government of Egypt controlled corporation (EGPC) for oil sales, gas and NGL sales and production
service fees. US$5.7 million of this is expected to be received in the normal course of operations and the remaining US$2.0 million is withheld as a rolling
production guarantee towards the work program for the South Disouq concession is also expected to be received in the coming months. The Company
also had a receivable of US$0.6 million related to joint venture partner current accounts for the South Disouq concession, with the remaining US$1.2m
related to sundry debtors and prepayments.
Subsequent to December 31, 2016, the Company collected US$2.5 million of trade receivables from those that were outstanding at December 31, 2016;
US$0.1 million for NW Gemsa representing October 2016 crude oil sales invoices, US$1.3 million for Meseda representing September, October and
November 2016 production service fees and US$1.4 million of the rolling South Disouq production guarantee referred to above.
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.
$000’s
Current assets
Cash and cash equivalents 4,725 8,170
Trade and other receivables 9,463 6,678
Inventory 1,698 1,188
Current assets 15,886 16,036
December 31
2016
December 31
2015
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Current liabilities
Trade and other payables 3,674 3,556
Current income taxes 389 928
Current liabilities 4,063 4,484
Working capital 11,823 11,552
The increase in working capital of US$0.3 million since December 31, 2015 for SDX Energy Inc. is as a result of (i) net cash reduction of US$3.4 million,
(ii) an increase in trade payables of US$0.1 million, offset by (iii) an increase in inventory of US$0.5 million, (iv) an increase in trade receivables of
US$2.8 million and (v) a reduction in current income tax liability of US$0.5 million.
The following table outlines the Company’s sources and uses of cash for the twelve months ended December 31, 2016 and 2015:
Twelve months ended December 31
2015
$000’s
Sources
Operating cash flow before working capital movements 2,264 1,647
Cash from disposal of office assets - 8
Private placement on London Stock Exchange AIM 10,127 -
Dividends received 825 917
Sea Dragon Energy Inc. net working capital as a result of the business combination effective October 1, 2015 - 3,911
13,216 6,483
2016
Uses
Property, plant and equipment expenditures (161) (1,392)
Exploration and evaluation expenditures (11,729) (3,728)
Repayment of debentures - (2,052)
Repayment of bank facility - (1,650)
Finance costs paid (96) -
Income taxes paid (766) (4,678)
Effect of foreign exchange on cash and cash equivalents (469) (565)
Changes in non-cash working capital (3,440) (2,183)
(16,661) (16,248)
Decrease in cash (3,445) (9,765)
Cash and cash equivalents at beginning of period 8,170 17,935
Cash and cash equivalents at end of period 4,725 8,170
SDX Energy Inc.
2016 Annual Report 29
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Liquidity and capital resources (continued)
Capital Resources (continued)
The Company’s operating cash flow before working capital movements for the twelve months ended December 31, 2016 compared to the prior period
ended December 31, 2015 has increased by US$0.6 million primarily due to:
(i) an increase of US$1.5 million in net revenues as a result of the inclusion of a full year of NW Gemsa net revenues (US$2.6 million) in 2016, and the
recognition of net gas and NGL revenues (US$2.3 million) in Q4 2016, partly offset by lower production and pricing at Meseda (US$3.4 million);
(ii) an increase in operating costs of US$0.3 million as a result of the inclusion of the operating expenses incurred by the NW Gemsa concession during
the twelve months to December 31, 2016, partly offset by production declines;
(iii) a net decrease of US$1.1 million in general and administrative costs in 2016 as a result of the absence in 2016 of Madison severance and transaction-
related costs (US$1.5 million) partly offset by the increased costs of the combined entity post-business combination (US$0.4 million);
(iv) an increase in expensed cash exploration and evaluation expenditure of US$0.4 million;
(v) lower finance costs of US$0.1 million due to lower interest charges; and
(vi) the effect of foreign exchange crystallisation giving a US$0.3 million realized loss in 2016 versus a US$0.7 million realized gain in 2015.
Financial instruments
The Company is exposed to financial risks due to the nature of its business and the financial assets and liabilities that it holds. The following discussion
reviews material financial risks, quantifies the associated exposures, and explains how these risks and the Company’s capital are managed.
Market risk
Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates could affect the Company’s
income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within
acceptable parameters, while optimizing the return.
Commodity price risk
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for
oil and natural gas are impacted by not only the relationship between the United States dollar and other currencies but also world economic events that
impact the perceived levels of supply and demand. The Company may hedge some oil and natural gas sales through the use of various financial derivative
forward sales contracts and physical sales contracts. The Company’s production is sold on the daily average price. The Company, however, may give
consideration in certain circumstances to the appropriateness of entering into long term, fixed price marketing contracts. The Company will not enter
into commodity contracts other than to meet the Company’s expected sale requirements.
At December 31, 2016 the Company did not have any outstanding derivatives in place.
Foreign currency risk
Currency risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The reporting and functional
currency of the Company is United States dollars (US$). 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$ and Sterling (GBP) and the US$. The majority of capital expenditures are incurred in US$ and EGP and oil and service fee revenues are
received in both US$ and EGP. The Company is able to utilize EGP to fund its Egyptian office general and administrative expenses and to part-pay cash
calls 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 Other
As at December 31, 2016 US$ Equivalent
Cash and cash equivalents 4,725 1,847 2,104 694 80
Trade and other receivables 9,463 8,544 16 838 65
Trade and other payables (3,674) (1,757) (1,377) (525) (15)
Current income taxes (389) - (389) - -
Balance sheet exposure 10,125 8,634 354 1,007 130
(1) denotes Financial Statements
30
SDX Energy Inc.
2016 Annual Report
The average exchange rates during the three months ended December 31, 2016 and 2015 were 1 US$ equals:
Average: October 1, 2016 to December 31, 2016 Average: October 1, 2015 to December 31, 2015
USD/EGP USD/GBP USD/EGP USD/GBP
Period average 14.3634 0.8044 Period average 7.8530 0.6590
The average exchange rates during the twelve months ended December 31, 2016 and 2015 were 1 US$ equals:
Average: January 1, 2016 to December 31, 2016 Average: January 1, 2015 to December 31, 2015
USD/EGP USD/GBP USD/EGP USD/GBP
Period average 10.0211 0.7405 Period average 7.6849 0.6542
The exchange rates as at December 31, 2016 and 2015 were 1 US$ equals:
Period end: December 31, 2016 Period end: December 31, 2015
USD/EGP USD/GBP USD/EGP USD/GBP
December 31, 2016 18.1274 0.8113 December 31, 2015 7.8041 0.6755
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 (from January 27, 2017 onwards) and its corporate offices are in London and Canada with listing and regulatory costs in both jurisdictions.
As at December 31, 2016 and 2015 the Company’s trade and other payables are as follows:
Carrying amount
$000’s
Current
Trade payables 663 198
Accruals 684 1,284
Other payables 2,327 2,074
Total trade and other payables 3,674 3,556
December 31
2016
December 31
2015
Trade payables include US$0.3 million of NGL and gas transportation and treatment costs associated with the sales of these products recognized during
Q4 2016. There was no corresponding balance as at December 31, 2015.
Accruals primarily comprise general and administrative costs related to legal, audit, tax and reserve reporting fees. The main reduction from the position
as at December 31, 2015 is the absence of a US$0.5 million restructuring accrual which existed at December 31, 2015 and which since been settled.
Other payables of US$2.3 million comprise an estimated liability of US$0.5 million related to the relinquishment of the Shukheir Marine concession
(2015: US$1.1 million), partner current accounts of US$1.2 million for NW Gemsa (2015:US$0.7 million), US$0.5 million Block-H Meseda
(2015:US$nil million) concessions, UK payroll taxes and deferred payroll of US$0.1 million (2015: US$0.3 million).
The joint venture partner current accounts represent the net of monthly cash calls paid less billings received.
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:
Carrying amount
December 31
2015
$000’s
Cash and cash equivalents 4,725 8,170
Trade and other receivables 9,463 6,678
14,188 14,848
Total
December 31
2016
Trade and other receivables
All of the Company’s operations as at December 31, 2016 were conducted in Egypt. The Company’s exposure to credit risk is influenced mainly by the
individual characteristics of each counter party. The Company does not anticipate any default as it expects continued payment from customers.
SDX Energy Inc.
2016 Annual Report 31
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Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Liquidity and capital resources (continued)
Financial instruments (continued)
The maximum exposure to credit risk for trade and other receivables at the reporting date by type of customer was:
Carrying amount
$000’s
Current
Government of Egypt controlled corporations 7,745 5,018
Joint venture partners 578 862
Other
1,140 798
Total trade and other receivables 9,463 6,678
December 31
2016
December 31
2015
US$7.7 million of current receivables related to oil, gas and NGL sales and production service fees which are due from EGPC (December 31, 2015:
US$5.0 million), a Government of Egypt controlled corporation. Receivables in respect of oil sales and service fees are normally collected in two to three
months following production. The Company expects to collect outstanding receivables of US$3.4 million for NW Gemsa (2015: US$0.8 million), which
includes the US$2.3 million gas and NGL revenue recognized in Q4 2016 (with no comparable balance at December 31, 2015), and US$2.3 million for
Block – H Meseda (2015: US$1.2 million), in the normal course of operations. The US$2.0 million of Shukheir Marine oil invoices (2015:US$3.0 million),
which are pledged against the Company’s obligations under its South Disouq work program, are expected to be collected during Q2 2017 as the South
Disouq work programme is now complete.
The joint venture partner current accounts represent the net of monthly cash calls paid less billings received. Joint venture partner receivables of
US$0.6 million (2015 - US$0.9 million) relate to the South Disouq concession only (2015: South Disouq US$0.8 million and Block – H Meseda
US$0.1 million). The other receivables of US$1.1 million consist of US$0.7 million related to prepayments, US$0.3 million for Goods and Services Tax
(“GST”)/ Value Added Tax (“VAT”) and US$0.1 million for other items.
As at December 31, 2016 and December 31, 2015, the Company’s trade and other receivables are aged as follows:
Carrying amount
$000’s
Current
Current (less than 90 days) 6,863 3,364
Past due (more than 90 days) 2,600 3,314
Total trade and other receivables 9,463 6,678
December 31
2016
December 31
2015
The balances which are past due are not considered impaired.
Current trade and other receivables past due (more than 90 days old) have decreased by US$0.7 million when compared to December 31, 2015.
This decrease is primarily due to the collection of US$1.0 million of the Shukheir Marine receivables as explained above.
Subsequent to December 31, 2016, the Company collected US$2.5 million of trade receivables from those that were outstanding at December 31, 2016;
US$0.1 million for NW Gemsa representing October 2016 crude oil sales invoices, US$1.3 million for Meseda representing September, October and
November 2016 production service fees and US$1.4 million of the rolling South Disouq production guarantee referred to above.
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
2015
Equity 37,264 55,246
Working capital (1) (11,823) (11,552)
Total capital 25,441 43,694
December 31
2016
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 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 properties and to pursue other opportunities.
32
SDX Energy Inc.
2016 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 2016.
Further information on the accounting policies and estimates can be found in the notes to the Consolidated Financial Statements and Annual MD&A
for the year ended December 31, 2016.
New standards and interpretations
New and amended standards and interpretations need to be adopted in the first financial statements issued after their effective date (or date of early
adoption). Amendments have been made to the following standards effective January 1, 2016. These amendments have not had a material impact on
the Consolidated Financial Statements.
•
•
•
•
•
•
IFRS 11 – Joint Arrangements
IAS 16 – Property, Plant and Equipment
IAS 38 – Intangible Assets
IAS 27 – Separate Financial Statements
IFRS 10 – Consolidated Financial Statements
IAS 1 – Presentation of 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 interim and 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 does not expect this standard to have a
significant impact on its Consolidated Financial Statements.
IFRS 16 – Leases (“IFRS 16”)
On January 13, 2016, the IASB published IFRS 16 which replaces the current guidance in IAS 17. IFRS 16 requires lessees to recognize a lease liability
reflecting the future lease payments and a “right-of-use asset” for virtually all lease contracts. The standard applies to interim and annual periods
beginning on or after January 1, 2019 with earlier application permitted if IFRS 15 is applied. The Company does not expect this standard to have
a significant impact on its Consolidated Financial Statements.
Future changes in accounting policies
There were no updates to future changes in accounting policies in 2016. Further information on future changes in accounting policies can be found
in the notes to the Consolidated Financial Statements and Annual MD&A for the year ended December 31, 2016.
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SDX Energy Inc.
2016 Annual Report 33
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Business risk assesment
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 flows 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.
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.
34
SDX Energy Inc.
2016 Annual Report
Management’s Discussion & Analysis
for the three and six months ended June 30, 2016
(prepared in US$)
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 (“MAD”), British pound (“GBP”), Egyptian pound (“EGP”) 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.
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SDX Energy Inc.
2016 Annual Report 35
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Business risk assesment (continued)
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.
There are certain restrictions on foreign entities repatriating earnings from Morocco.
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, 2016. 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, 2016.
36
SDX Energy Inc.
2016 Annual Report
Proforma financial information
As mentioned in the introduction to this MD&A, in order to provide the reader with a better understanding of the underlying operational performance
of the combined SDX business for the twelve months to December 31, 2016, the following pages will discuss the actual performance of the combined
business for the twelve months ended December 31, 2016 comparing it to a proforma combined business performance for the twelve months ended
December 31, 2015. The table below sets out how the proforma comprehensive income for the combined business has been created for the twelve
months ended December 31, 2015. These figures do not include the acquisition of the Egyptian and Moroccan assets of Circle Oil plc that occurred
on January 27, 2017.
Income Statement Reconciliation
The table below is a reconciliation of the consolidated Statement of Comprehensive Income and associated operating data for the twelve months ended
December 31, 2015 to the full twelve months ended December 31, 2015 proforma operating data which is discussed within the remainder of this MD&A.
Twelve months ended December 31
2015
2015
2015
Full
twelve months
of combined
SDX Group - Pro
Forma unaudited
SDX Energy Inc
as per Financial
$000’s Statements
Financial
Oil revenue 2,322 10,972 13,294
Royalties (686) (4,781) (5,467)
Net oil revenue 1,636 6,191 7,827
Sea Dragon
Energy Inc
(pre-combination)
Production service fee revenue 9,736 - 9,736
Total net revenue 11,372 6,191 17,563
Operating costs (4,973) (1,066) (6,039)
Netback (pre tax) 6,399 5,125 11,524
Exploration and evaluation expense (73) (557) (630)
Depletion, depreciation and amortization (2,057) (1,718) (3,775)
Impairment expense (6,842) - (6,842)
Impairment of materials inventory - - -
Stock based compensation (761) (140) (901)
Share of profit from joint venture 1,024 - 1,024
Loss on disposal of office assets (3) - (3)
Gain on disposal of materials inventory - 235 235
Loss on disposal of Kom Ombo concession - - -
General and administrative expenses (4,770) (3,132) (7,902)
Operating (loss)/income (7,083) (187) (7,270)
Net finance income/(expense) (96) (605) (701)
Gain on acquisition 18,289 - 18,289
Current income tax expense (1,168) (1,250) (2,418)
Deferred income tax expense 105 - 105
Net (loss)/income 10,047 (2,042) 8,005
Other comprehensive loss
Foreign exchange (647) - (647)
Total comprehensive (loss)/income for the period 9,400 (2,042) 7,358
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SDX Energy Inc.
2016 Annual Report 37
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Income Statement Reconciliation (continued)
2015
Full
twelve months
of combined
SDX Group - Pro
Forma unaudited
Twelve months ended December 31
2015
2015
SDX Energy Inc
as per Financial
per unit amounts Statements (1)
Operational
Oil sales (bbl/d) 652 794 759
Production service fee (bbl/d) 760 - 760
Total boe/d 1,412 794 1,519
Sea Dragon
Energy Inc
(pre-combination)
Oil sales volumes (bbls) 59,988 216,868 276,856
Production service fee volumes (bbls) 277,407 - 277,407
Total sales volumes (boe) 337,395 216,868 554,263
Brent Oil price (US$/bbl) $52.30 $55.24 $52.30
West Gharib oil price (US$/bbl) $42.81 - $42.81
Realized oil price (US$/bbl) $38.71 $50.59 $48.02
Realized service fee (US$/bbl) $35.10 - $35.10
Net realized price (US$/boe) $35.74 $50.59 $41.55
Total royalties (US$/boe) $2.03 $22.04 $9.86
Operating costs (US$/boe) $14.74 $4.91 $10.90
Netback - (US$/boe) $18.97 $23.64 $20.80
Capital expenditures 5,120 1,239 6,359
(1) SDX Energy Inc contains financial information from the Consolidated Statement of Comprehensive Income; see Financial Statements.
38
SDX Energy Inc.
2016 Annual Report
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Proforma financial information
As per the Consolidated Financial Statements for the twelve months ended December 31, 2016, the Company recorded a total comprehensive loss of
US$(28.0) million for the twelve months ended December 31, 2016, compared to a total comprehensive income of US$9.4 million for the twelve months
ended December 31, 2015.
The following table, however, shows the Total Comprehensive (Loss)/Income for the twelve months ended December 31, 2016 and 2015 on a proforma
basis i.e. as if the business combination had been in effect for the 2015 comparative period. The constituent parts for the December 31, 2015 components
of this table are shown in more detail on pages 37 to 40 of this MD&A.
Consolidated Statement of Comprehensive (Loss)/Income
Twelve months ended December 31
2015
Revenue, net of royalties 12,914 17,563
2016
Operating costs (5,282) (6,039)
Netback (pre tax) 7,632 11,524
Exploration and evaluation expense (24,833) (630)
Depletion, depreciation and amortization (3,266) (3,775)
Impairment expense (4,303) (6,842)
Gain on reversal of inventory provision/disposal of materials inventory 479 235
Stock based compensation 47 (901)
Share of profit from joint venture 1,222 1,024
Loss on disposal of office assets - (3)
General and administrative expenses (3,679) (7,902)
Operating loss (26,701) (7,270)
Net finance income/(expense) 4 (701)
Gain on acquisition - 18,289
(Loss)/income before income taxes (26,697) 10,318
Current income tax expense (1,499) (2,418)
Deferred income tax expense (4) 105
Net (loss)/income (28,200) 8,005
Other comprehensive income/(loss)
Foreign exchange 237 (647)
Total comprehensive (loss)/income for the period (27,963) 7,358
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SDX Energy Inc.
2016 Annual Report 39
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Proforma financial information (continued)
Operational and financial highlights
Twelve months ended December 31
2015
$000’s unless stated
Operational
Oil revenue 7,432 13,294
Royalties (3,190) (5,467)
Net oil revenue 4,242 7,827
2016
Gas revenue 2,210 -
Royalties (1,059) -
Net gas revenue 1,151 -
NGL revenue 2,361 -
Royalties (1,199) -
Net NGL revenue 1,162 -
Production service fee revenue 6,359 9,736
Total net revenue 12,914 17,563
Operating costs (5,282) (6,039)
Netback (pre tax) 7,632 11,524
Oil sales (bbl/d) 534 759
Gas sales (boe/d) 823 -
NGL Sales (bbl/d) 112 -
Production service fee (bbl/d) 662 760
Total boe/d 2,131 1,519
Oil sales volumes (bbls) 195,588 276,856
Gas sales volumes (boe) 301,137 -
NGL sales volumes (bbls) 40,897 -
Production service fee volumes (bbls) 242,146 277,407
Total sales volumes (boe) 779,768 554,263
Brent oil price (US$/bbl) $41.70 $52.30
West Gharib oil price (US$/bbl) $32.43 $42.81
Realized oil price (US$/bbl) $38.00 $48.02
Realized service fee (US$/bbl) $26.26 $35.10
Realized oil sales price and service fees $31.51 $41.55
Realized gas price (US$/mcf) $1.22 -
Realized NGL price (US$/bbl) $57.73 -
Net realized price - all products (US$/boe) $23.55 $41.55
Total royalties (US$/boe) $6.99 $9.86
Operating costs (US$/boe) $6.77 $10.90
Netback - (US$/boe) $9.79 $20.79
Capital expenditures 13,339 6,359
40
SDX Energy Inc.
2016 Annual Report
Oil Sales Volumes (relates to NW Gemsa and Shukheir Marine only)
Total oil sales volumes for the twelve months ended December 31, 2016 averaged 534 bbl/d (based on 366 days) compared to 759 bbl/d
(based on 365 days) for the comparative period of the prior year.
Total sales volumes fell by 81,268 barrels, 29%, to 195,588 barrels in the twelve months ended December 31, 2016 compared to 276,856 in the
comparative period of 2015. The North West Gemsa concession reached peak production rate in Q4 2014 and volumes have now started to decline,
which has been the main driver of the reduction in volumes. In addition, 10,093 barrels of this decline relates to the relinquishment of the
Shukheir Marine concession, effective January 31, 2015 which contributed a net reduction of 28 bbl/d.
The crude oil sales volumes by concession are shown in the table below:
Twelve months ended December 31
2015
2016
N W Gemsa 195,588 266,763
Shukheir Marine - 10,093
Total crude oil sales 195,588 276,856
Production Service Fee volumes (relates to Meseda only)
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 35,261 barrels, 13%, to 242,146 barrels compared to the twelve months ended December 31, 2015.
This was as a result of natural reservoir declines. This contributed to a net reduction of 98 bbl/d in 2016 compared to 2015.
The production service fee volumes are shown in the table below:
Twelve months ended December 31
2015
2016
Meseda - Block H 242,146 277,407
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 oil revenues and capital and operational expenditure. The Operational and Financial Highlights
table on the previous page 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.
For the twelve months ended December 31, 2016, oil sales made by the Company achieved an average price per barrel of oil of US$38.00 compared
to the average Brent Oil price (“Brent”) of US$41.70; a discount of US$3.70, 9% per barrel. 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 twelve months ended December 31, 2016 the Company received an average service fee per barrel of oil of US$26.26 compared to the average West
Gharib price of US$32.43; a discount of US$6.17, 19%, per barrel. The Company receives a discount to West Gharib due to the quality of the oil produced.
During the twelve months ended December 31, 2016 the Brent price ranged from a low of US$26.01 per barrel on January 20, 2016 to a high of
US$54.96 per barrel on December 30, 2016. The current low oil price environment is due to 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 countries such as China. At this time,
the Company does not hedge any of its production.
The Company commenced sales of gas and NGLs in February 2013 from the NW Gemsa concession, however recognition of this revenue was
delayed pending resolution of a dispute with EGPC over entitlement volumes and pricing. This was resolved such that US$1.2 million of gas sales
and US$1.3 million of NGL sales were recognized in Q4 2016, net of royalties, covering the period February 2013 – December 2016.
Crude Oil Sales
Twelve months ended December 31
$000’s except per unit amounts
2015
Crude oil sales 7,432 13,294
38.00 48.02
Per bbl
2016
Crude oil sales for the twelve months ended December 31, 2016 were US$7.4 million compared to US$13.3 million for the twelve months ended
December 31, 2015.
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SDX Energy Inc.
2016 Annual Report 41
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Proforma financial information (continued)
Crude Oil Sales (continued)
The crude oil sales per concession were:
Twelve months ended December 31
$000’s
2015
N W Gemsa 7,432 12,879
Shukheir Marine - 415
Total crude oil sales 7,432 13,294
2016
Variance from prior year
For the twelve months ended December 31, 2016 (compared to the twelve months ending December 31, 2015) the decrease in revenue of US$5.9 million,
44%, to US$7.4 million is due to a decrease in realized sales price (US$2.0 million) or 15%, and a decrease in sales volume (US$3.9 million), or 29%.
As explained above the decrease in the sales volume compared to the prior year is due to the relinquishment of the Shukheir Marine concession effective
January 31, 2015 and the decline of the NW Gemsa concession after reaching plateau production during Q4, 2014.
$000’s
Twelve months ended December 31, 2015 13,294
Price variance (1,960)
Production variance (3,902)
Twelve months ended December 31, 2016 7,432
Production Service Fees
Twelve months ended December 31
$000’s except per unit amounts 2016
2015
Production service fees 6,359 9,736
26.26 35.10
Per bbl
Production services fees from Meseda for the twelve months ended December 31, 2016 were US$6.4 million compared to US$9.7 million for the twelve
months ended December 31, 2015.
Variance from prior year
For the twelve months ended December 31, 2016 (compared to the twelve months year ending December 31, 2015) the decrease in production
service fees of US$3.3 million, 34%, to US$6.4 million in 2016 is due to a decrease in realized price of US$2.1 million, 22%, and a decrease in volumes
of US$1.2 million, 13%.
$000’s
Twelve months ended December 31, 2015 9,736
Price variance (2,140)
Production variance (1,237)
Twelve months ended December 31, 2016 6,359
Gas and Natural Gas Liquids (“NGL”) sales
The net gas and NGL sales recognized during the period ended December 31, 2016 were US$1.2 million and US$1.2 million respectively, net of royalties,
and representing all gas and NGL sales made since February 2013 (approximately 1,430 days). Recognition of this revenue was delayed pending resolution
of the invoicing dispute with EGPC, discussed above, which was completed in Q4 2016.
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 concession are as follows:
Twelve months ended December 31
$000’s
2015
N W Gemsa 3,190 5,291
Shukheir Marine - 176
Total royalties by concession 3,190 5,467
2016
42
SDX Energy Inc.
2016 Annual Report
Royalties for crude oil sales per boe by concession are as follows:
Twelve months ended December 31
per unit amounts
2015
N W Gemsa 16.31 19.83
Shukheir Marine - 17.45
Total royalties (US$/boe) by concession 16.31 19.75
2016
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, 2016 and 2015):
SDX Energy 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.
Direct operating costs
Twelve months ended December 31
$000’s except per unit amounts
2015
Direct operating costs 5,282 6,039
Per boe 6.77 10.90
2016
Direct operating costs for the twelve months ended December 31, 2016 were US$5.3 million (US$6.77 per bbl) compared to US$6.0 million (US$10.90
per bbl) in the prior year. Excluding the impact of the gas and NGL revenues recognized in Q4 2016, the direct operating costs for the twelve months
ended December 31, 2016 were $11.38/boe.
The direct operating costs per concession were:
Twelve months ended December 31
$000’s
2015
N W Gemsa 2,170 1,922
Shukheir Marine - 669
Meseda - Block H 3,086 3,387
Other
26 61
Direct operating costs by concession 5,282 6,039
2016
The direct operating costs per boe per concession were:
Twelve months ended December 31
per unit amounts
2015
N W Gemsa 4.04 7.20
Shukheir Marine - 66.31
Meseda - Block H 12.75 12.21
Total direct operating costs (US$/boe) by concession 6.77 10.90
2016
At NW Gemsa, excluding NGL and gas volumes invoiced in Q4 2016, as a result of the concession undergoing a workover programme in the twelve
months to December 31, 2016 and, as a result of the operator of NW Gemsa charging the partners for some backdated overheads, the direct operating
costs for this concession, and per boe, were higher ($9.56/boe) in the twelve months to December 31, 2016 compared to the twelve months to December
31, 2015. However, inclusion of the invoiced NGL and gas volumes brings operating costs per boe below 2015 levels.
At Meseda, lower production levels have been partially offset by the costs of the workover programme, resulting in a 9% reduction in direct operating
costs, but a 4% increase in direct operation costs per boe.
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SDX Energy Inc.
2016 Annual Report 43
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Proforma financial information (continued)
Current taxes
Twelve months ended December 31
$000’s
2015
Current taxes 1,499 2,418
2016
Pursuant to the terms of the Company’s concession agreements for NW Gemsa and Shukheir Marine, 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 presented gross 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 service agreement for Block H-Meseda. The Company’s Egyptian subsidiary, Madison Egypt
Limited, is subject to corporate tax on its profits at an income tax rate of 22.5%.
The current taxes per concession were:
Twelve months ended December 31
2015
$000’s
N W Gemsa 1,272 1,159
Shukheir Marine - 30
Meseda - Block H 227 1,168
Other
- 61
Total current taxes by concession 1,499 2,418
2016
General and administrative costs
Twelve months ended December 31
$000’s
2015
Wages and employee costs 2,532 4,838
Consultants - inc. PR/IR 479 594
Legal fees 237 246
Audit, tax and accounting services 246 790
Public company fees 332 383
166 407
Travel
Office expenses 668 846
IT expenses 322 136
Transaction costs - 496
Service recharges (1,303) (834)
Total - net G&A 3,679 7,902
2016
General and administrative (“G&A”) costs for the twelve months ended December 31, 2016 were US$3.7 million compared to US$7.9 million
for the comparative period of the prior year; a decrease of US$4.2 million, or 53%.
G&A costs in the above table represent a full twelve months ended December 31, 2015 for the combined Sea Dragon Energy Inc. and
Madison Petrogas Ltd, now SDX Energy Inc.
The decrease of US$4.2 million is primarily due to the following:
•
•
•
•
•
•
•
•
lower wages and employee costs (US$2.3 million) due to the absence of $1.0 million of transaction-related expenses (including severance)
and a further US$1.3 million as a result of internal restructuring following the business combination;
lower consultancy fees (US$0.1 million) due to rationalization of providers following the business combination;
lower audit, tax and accounting services (US$0.5 million) due to the re-negotiation of these contracts and only one audit for the SDX group
whereas the comparatives include fees for both groups prior to the combination;
lower office expenses following the consolidation of operations in London and Cairo (US$0.2 million);
travel costs reduced by US$0.2 million due to fewer management travel requirements;
higher IT expenses (US$0.2 million) due to increased technical software licence costs;
the absence of transaction costs incurred by Madison during the business combination (US$0.5 million); and
greater service recharges (US$0.5 million) relating to the increase in cross charging of technical and administrative time spent by the Company
on its exploration assets and the recovery of indirect overhead recharges from a concession partner.
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2016 Annual Report
Depletion, depreciation and amortization (“DD&A”)
Twelve months ended December 31
$000’s except per unit amounts
2015
Depletion, depreciation and amortization 3,266 3,775
4.99 6.81
Per bbl
2016
For the twelve months ended December 31, 2016, depletion, depreciation and amortization (“DD&A”) was US$3.3 million compared to US$3.8 million
the prior year. Excluding the impact of gas and NGL sales invoiced in Q4 2016, the DD&A per bbl was $7.46/bbl.
The DD&A per concession was:
Twelve months ended December 31
$000’s
2015
NW Gemsa 2,216 1,835
Shukheir Marine - 184
Meseda - Block H 1,010 1,619
Corporate - office assets 40 137
Total DD&A 3,266 3,775
2016
Net Earnings
As per the Financial Statements for the twelve months ended December 31, 2016, the Company recorded a Total Comprehensive Loss of US$(28.0)
million, compared to a pro-forma Total Comprehensive Income of US$7.4 million for the twelve months ended December 31, 2015 (page 39 of this
MD&A); a difference of US$(35.4) million.
The main components of the difference (US$(35.4) million) are:
•
•
•
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•
•
•
•
•
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a fall in net revenues of US$4.7 million as a result of lower oil prices, reduced production and the relinquishment of the Shukheir Marine
concession effective January 31, 2015, partly offset by recognition of the gas and NGL revenues at NW Gemsa;
higher exploration and evaluation expense of US$24.2 million as a result of the withdrawal from the Bakassi West concession and the write
down of the asset;
the absence in 2016 of the US$18.3 million gain on acquisition recorded on completion of the business combination between Sea Dragon
and Madison, offset by;
lower operating costs due to lower production levels (US$0.8 million); lower DD&A charges in 2016 (US$0.5 million) due to lower production levels;
a lower impairment charge recorded for NW Gemsa in 2016 (US$2.5 million);
a higher one-off inventory gain in 2016 of US$0.2 million to recognize inventory to be used in the South Disouq SD1-X well;
increased income in Brentford Oil Tools of US$0.2 million;
lower stock based compensation of US$1.0 million due the adjustment of one of the inputs to the Black-Scholes option pricing model, following
the business combination between Sea Dragon and Madison.
lower G&A of US$4.2 million as a result on the business combination and consequent restructuring of the group;
lower financing expenses due to the absence of amortised facility costs in 2016 and a reduction in interest paid (US$0.7 million);
a foreign exchange gain due to the devaluation of the Egyptian pound in November 2016, versus a loss in 2015 (US$0.9 million); and
lower current income tax expense of US$0.9 million as a result of lower profits due to the falling oil price and lower production and the
relinquishment of SHM.
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2016 Annual Report 45
Management’s Discussion & Analysis
for the three and twelve months ended
December 31, 2016
(prepared in US$)
Proforma financial information (continued)
Summary of quarterly results
The fiscal and operational quarterly results shown below include full quarterly information for SDX Energy Inc., formerly Sea Dragon Energy Inc. and
Madison Petrogas Ltd prior to the business combination (pre-combination), effective October 1, 2015. The quarterly results for Q4, Q3, Q2 and Q1, 2016
and Q4, 2015 represent the quarters for the newly combined group, SDX Energy Inc. post-combination. SDX Energy Inc., formerly Sea Dragon Energy Inc.
produces and sells via its concession agreement, oil, gas and NGL. Madison has a production service agreement and obtains a per barrel service fee.
Fiscal year 2016 2015
Financial $000’s Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
Cash, beginning of period
SDX Energy Inc. post combination 4,961 6,949 8,671 8,170 12,480 - - -
Sea Dragon Energy Inc. - pre combination 494 3,105 2,966
Madison Petrogas Ltd - pre combination 12,463 19,056 17,936
Cash, end of period
SDX Energy Inc. post combination 4,725 4,961 6,949 8,671 8,170 - - -
Sea Dragon Energy Inc. - pre combination 490 494 3,105
Madison Petrogas Ltd - pre combination 11,990 12,463 19,056
Working capital
SDX Energy Inc. post combination 11,823 9,593 8,232 5,414 11,552 - - -
Sea Dragon Energy Inc. - pre combination 3,911 2,838 2,243
Madison Petrogas Ltd - pre combination 11,943 13,634 15,028
Income/(loss) and comprehensive income/(loss)
SDX Energy Inc. post combination (2,059) 140 (25,164) (883) 8,542 - - -
Sea Dragon Energy Inc. - pre combination (1,755) 230 (516)
Madison Petrogas Ltd - pre combination (1,029) 1,110 777
Net income/(loss) per share - basic
SDX Energy Inc. post combination (0.030) 0.002 (0.455) (0.023) 0.227 - - -
Sea Dragon Energy Inc. - pre combination (0.005) 0.001 (0.001)
Madison Petrogas Ltd - pre combination (0.013) 0.019 0.018
Capital expenditures
SDX Energy Inc. post combination 856 188 6,475 5,819 2,404 - - -
Sea Dragon Energy Inc. - pre combination 781 270 188
Madison Petrogas Ltd - pre combination 797 1,605 313
Total assets
SDX Energy Inc. post combination 41,617 43,901 47,231 64,907 60,016 - - -
Sea Dragon Energy Inc. - pre combination 28,258 29,145 38,011
Madison Petrogas Ltd - pre combination 42,912 44,333 49,425
Shareholders’ equity
SDX Energy Inc. post combination 37,264 39,161 38,560 54,457 55,246 - - -
Sea Dragon Energy Inc. - pre combination 23,925 25,644 25,355
Madison Petrogas Ltd - pre combination 40,769 41,660 40,403
Common shares outstanding (000’s)
SDX Energy Inc. post combination 79,844 79,844 75,934 37,642 37,642 - - -
Sea Dragon Energy Inc. - pre combination 376,459 376,459 376,459
Madison Petrogas Ltd - pre combination 56,348 56,348 56,348
Warrants outstanding (000’s)
SDX Energy Inc. post combination - - 611 611 611 - - -
Madison Petrogas Ltd - pre combination 1,280 1,280 1,280
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SDX Energy Inc.
2016 Annual Report
Fiscal year 2016 2015
Operational Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
Oil sales (bbl/d) 468 510 554 606 652 674 719 993
Gas sales (mcf/d) 3,273 - - - - - - -
NGL sales (bbl/d) 445 - - - - - - -
Production service fee (bbl/d) 679 704 616 646 704 723 783 832
Total boe/d 4,865 1,214 1,170 1,252 1,356 1,397 1,502 1,825
Oil sales volumes (bbls) 43,087 46,935 50,407 55,159 59,988 62,031 65,434 89,403
Gas sales volumes (mcf) 301,137 - - - - - - -
NGL sales volumes (bbls) 40,897 - - - - - - -
Production service fee volumes (bbls) 65,504 64,792 56,026 58,823 64,751 66,517 71,216 74,923
Total sales and service fee volumes (boe) 444,625 111,727 106,433 113,982 124,739 128,548 136,650 164,326
Brent oil price (US$/bbl) 49.23 45.78 45.54 33.73 43.56 50.26 61.72 53.78
West gharib oil price (US$/bbl) 34.86 - - - - - - -
Realized oil price (US$/bbl) 44.57 40.84 39.90 28.69 38.71 45.91 57.44 48.83
Realized service fee (US$/bbl) 31.12 28.32 24.51 20.49 27.89 33.31 40.72 37.57
Realized oil sales pirce and service fees (US$/bbl) 36.61 33.58 31.80 24.46 33.09 39.39 48.73 43.69
Realized gas price (US$/mcf) 1.22 - - - - - - -
Realized NGL price (US$/bbl) 57.73 - - - - - - -
Net Realized price - all products (US$/boe) 18.85 33.58 31.80 24.46 33.09 39.39 48.73 43.69
Royalties (US$/boe) 6.89 7.37 8.11 5.96 5.50 8.23 14.46 10.62
Sea Dragon Energy Inc. - pre combination - - - - - 17.06 30.19 19.53
Operating costs (US$/boe) 3.91 11.11 12.12 8.77 19.91 11.41 4.89 8.65
Sea Dragon Energy Inc. - pre combination - - - - - 10.49 (5.13) 8.40
Madison Petrogas Ltd - pre combination - - - - - 12.27 14.09 8.95
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Netback - (US$/boe) 8.05 15.11 11.57 9.73 7.68 19.75 29.38 24.42
Sea Dragon Energy Inc. - pre combination - - - - - 18.36 32.38 20.90
Madison Petrogas Ltd - pre combination - - - - - 21.04 26.63 28.61
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2016 Annual Report 47
Low cost, high
marigin production
The stable and sustainable low cost of operations
ensures SDX Energy will be a significant beneficiary of
the eventual increase in commodity pricing.
10,278 boe/d
16.9 mmboe
Combined Egyptian daily average gross production
for the twelve months to December 31, 2016
Asset reserves - North West Gemsa and Meseda
(gross) at December 31, 2016
48
SDX Energy Inc.
2016 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, 2016 and December 31, 2015, 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, 2016 and December 31, 2015 and their financial performance and their cash flows for the years then ended in accordance with
International Financial Reporting Standards.
PricewaterhouseCoopers LLP
Chartered Accountants
Aberdeen
March 24, 2017
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SDX Energy Inc.
2016 Annual Report 49
Consolidated Balance Sheet
as at December 31, 2016 and 2015
As at As at
December 31 December 31
(thousands of United States dollars) Note 2016 2015
Assets
Cash and cash equivalents 7 4,725 8,170
Trade and other receivables 8 9,463 6,678
Inventory 9 1,698 1,188
Current assets 15,886 16,036
Investments 12 2,503 2,106
Property, plant and equipment 10 12,605 18,401
Intangible exploration and evaluation assets 11 10,623 23,473
Non-current assets 25,731 43,980
Total assets 41,617 60,016
Liabilities
Trade and other payables 14 3,674 3,556
Current income taxes 17 389 928
Current liabilities 4,063 4,484
Deferred income taxes 17 290 286
Non-current liabilities 290 286
Total liabilities 4,353 4,770
Equity
Share capital 18 40,275 30,148
Warrants 18 - 99
Contributed surplus 5,128 5,175
Accumulated other comprehensive loss (917) (1,154)
(Accumulated loss)/retained earnings (7,222) 20,978
Total equity 37,264 55,246
Equity and liabilities 41,617 60,016
The notes are an integral part of these Consolidated Financial Statements.
The financial statements on pages 50 to 74 were approved by the Board of Directors on March 24, 2017 and signed on its behalf by:
Paul Welch Mark Reid
Chief Executive Officer Chief Financial Officer
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SDX Energy Inc.
2016 Annual Report
Consolidated Statement of Comprehensive Income
for the years ended December 31, 2016 and 2015
Twelve months ended December 31
(thousands of United States dollars) Note 2016 2015
Revenue, net of royalties 20 12,914 11,372
Revenue 12,914 11,372
Direct operating expense (5,282) (4,973)
Exploration and evaluation expense 11 (24,833) (73)
Depletion, depreciation and amortization 10 (3,266) (2,057)
Impairment expense 10 (4,303) (6,842)
Reversal of inventory provision 9 479 -
Stock based compensation 19 47 (761)
Share of profit from joint venture 12 1,222 1,024
Loss on disposal of office assets - (3)
General and administrative expenses 21 (3,679) (4,770)
Operating loss (26,701) (7,083)
Net finance income/(expense) 22 4 (96)
Gain on acquisition 4 - 18,289
(Loss)/income before income taxes (26,697) 11,110
Current income tax expense 17 (1,499) (1,168)
Deferred income tax expense/(credit) 17 (4) 105
Total current and deferred income tax expense (1,503) 1,063
Net (loss)/income (28,200) 10,047
Other comprehensive income/(loss)
Foreign exchange 237 (647)
Total comprehensive (loss)/income for the period (27,963) 9,400
Net (loss)/income per share
Basic
23 $(0.394) $0.195
Diluted 23 $(0.394) $0.195
The notes are an integral part of these Consolidated Financial Statements.
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SDX Energy Inc.
2016 Annual Report 51
Consolidated Statement of Changes in Equity
for the years ended December 31, 2016 and 2015
Twelve months ended December 31
(thousands of United States dollars) Note 2016 2015
Share capital
Balance, beginning of period 18 30,148 24,512
Issuance of common shares 18 - 5,636
Private placement - secondary listing on the London Stock Exchange AIM 18 10,988 -
Share issue costs 18 (861) -
Balance, end of period 40,275 30,148
Warrants
Balance, beginning of period 18 99 99
Expiry of warrants 18 (99) -
Balance, end of period - 99
Contributed surplus
Balance, beginning of period 5,175 4,414
Share based payments for the period (47) 761
Balance, end of period 5,128 5,175
Accumulated other comprehensive loss
Balance, beginning of period (1,154) (507)
Foreign currency translation adjustment for the period 237 (647)
Balance, end of period (917) (1,154)
Retained earnings
Balance, beginning of period 20,978 10,931
Net (loss)/income for the period (28,200) 10,047
Balance, end of period (7,222) 20,978
Total equity 37,264 55,246
The notes are an integral part of these Consolidated Financial Statements.
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SDX Energy Inc.
2016 Annual Report
Consolidated Statement of Cash Flows
for the years ended December 31, 2016 and 2015
Twelve months ended December 31
(thousands of United States dollars) Note 2016 2015
Cash flows (used in)/from operating activities
(Loss)/income before income taxes (26,697) 11,110
Adjustments for:
Depletion, depreciation and amortization 10 3,266 2,057
Exploration and evaluation expense 11 24,416 73
Impairment expense 10 4,303 6,842
Reversal of inventory provision 9 (479) -
Amortization of deferred transaction costs 22 - 378
Finance costs 22 (4) (9)
Stock-based compensation 19 (47) 761
Gain on acquisition 4 - (18,289)
Tax paid by State 17 (1,272) (255)
Share of profit from joint venture 12 (1,222) (1,024)
Loss on disposal of office assets - 3
Operating cash flow before working capital movements 2,264 1,647
(Increase)/decrease in trade and other receivables 6b (3,001) (3,372)
(Decrease)/increase in trade and other payables 14 (408) 2,377
Increase in inventory 9 (31) (1,188)
Cash used in operating activities (1,176) (536)
Income taxes paid 17 (766) (4,678)
Net cash (used in)/from operating activities (1,942) (5,214)
Cash flows (used in)/generated from investing activities:
Property, plant and equipment expenditures 10 (161) (1,392)
Exploration and evaluation expenditures 11 (11,729) (3,728)
Gain on disposal of office assets - 8
Dividends received 12 825 917
Sea Dragon Energy Inc. net working capital as a result of the business combination effective October 1, 2015 - 3,911
Net cash used in investing activities (11,065) (284)
Cash flows (used in)/generated from financing activities:
Repayment of debentures 13 - (2,052)
Repayment of bank facility 13 - (1,650)
Private Placement on London Stock Exchange AIM 18 10,127 -
Finance costs paid 22 (96) -
Net cash generated from/(used in) financing activities 10,031 (3,702)
Decrease in cash and cash equivalents (2,976) (9,200)
Effect of foreign exchange on cash and cash equivalents (469) (565)
Cash and cash equivalents, beginning of period 8,170 17,935
Cash and cash equivalents, end of period 4,725 8,170
The notes are an integral part of these Consolidated Financial Statements.
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SDX Energy Inc.
2016 Annual Report 53
Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
Note 1. Reporting entity
SDX Energy Inc. (“SDX” or “the Company”), formerly known as Sea Dragon Energy Inc., 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, 2016 and 2015 comprise the Company and its wholly owned subsidiaries and include the
Company’s share of joint arrangements as explained in note 12 below (together the “Group”). As described in note 4 to the Consolidated Financial
Statements, on August 18, 2015 Sea Dragon Energy Inc. and Madison PetroGas Limited entered into a Business Combination Arrangement Agreement,
and, on October 1, 2015 the transaction completed creating the new SDX Energy Inc. combined entity. Full details of the Business Combination are set
out in note 4. Further, as described in note 28 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 Morocco.
The Company’s shares 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 audited 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 audited Consolidated Financial Statements for the year ended
December 31, 2016. The policies applied are based on IFRS issued and outstanding as of March 24, 2017.
(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.
In accounting for property, plant and equipment, amounts recorded for depletion and amounts used for impairment test calculations are based on
estimates of oil and gas reserves and cash flows, including development costs, production volumes and oil and gas prices. Provisions recognized for
decommissioning costs and related accretion expense, derivative fair value calculations, fair value of share-based payments expense, deferred tax
provisions, as well as fair values assigned to any identifiable assets and liabilities in business combinations are also based on estimates. By their nature,
the estimates are subject to measurement uncertainty and the impact on the Consolidated Financial Statements of future periods could be material.
54
SDX Energy Inc.
2016 Annual Report
(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, 2018. The capital expenditure and operating costs used in these forecast cash flows are based on the Company’s Board
approved 2017 SDX corporate budget which reflects approved operating budgets for each of its Joint Ventures and an estimate of 2018 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, 2018. The Directors have made enquiries into and
considered the Egyptian and Moroccan business environments, 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 2016 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.
In the comparative period, the Company’s interest in Brentford was accounted for as an investment in an associate. As this was also equity
accounted, no restatement of comparative figures is required.
(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.
SDX Energy Inc.
2016 Annual Report 55
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
3. Significant accounting policies (continued)
(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.
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.
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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.
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:
Office equipment 1 – 5 years
Fixtures and fittings 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.
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
3. Significant accounting policies (continued)
(f) Impairment (continued)
(ii) Non-financial assets (continued)
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
cash generating unit “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.
(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
Although the Company has no decommissioning obligations as at December 31, 2016, the explanation following sets out the Company’s accounting
policy relating to the obligation that was in place during the year ended December 31, 2015. 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. 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.
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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.
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.
(n) New standards and interpretations
New and amended standards and interpretations need to be adopted in the first financial statements issued after their effective date (or date of early
adoption). Amendments have been made to the following standards effective January 1, 2016. These amendments have not had a material impact
on the Consolidated Financial Statements.
•
•
•
•
•
•
IFRS 11 – Joint Arrangements
IAS 16 – Property, Plant and Equipment
IAS 38 – Intangible Assets
IAS 27 – Separate Financial Statements
IFRS 10 – Consolidated Financial Statements
IAS 1 – Presentation of 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 does not expect this standard to have
a significant impact on its Consolidated Financial Statements.
IFRS 16 – Leases (“IFRS 16”)
On January 13, 2016, the IASB published IFRS 16 which replaces the current guidance in IAS 17. IFRS 16 requires lessees to recognize a lease liability
reflecting the future lease payments and a “right-of-use asset” for virtually all lease contracts. The standard applies to annual periods beginning on or
after January 1, 2019 with earlier application permitted if IFRS 15 is applied. The Company does not expect this standard to have a significant impact
on its Consolidated Financial Statements.
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
4. Business Combination
On August 18, 2015 Sea Dragon Energy Inc. (“Sea Dragon”) and Madison PetroGas Ltd. (“Madison”) entered into an Arrangement Agreement whereby:
•
Sea Dragon acquired all of the issued and outstanding Madison shares on the basis of an exchange ratio of 16.7 Sea Dragon common shares (on a
pre-Sea Dragon Share Consolidation basis) for each Madison share or 0.477143 of a Sea Dragon share for each Madison share on a post-Sea Dragon
Consolidation basis. Sea Dragon affected the share consolidation (the “Sea Dragon Consolidation”) on the basis of one (1) post-share consolidation
Sea Dragon share for thirty-five (35) pre-share consolidation Sea Dragon shares;
• Upon closing the transaction, the existing Madison shareholders held approximately 71% of the combined entity, which was renamed
“SDX Energy Inc.”, with the holders of Sea Dragon shares holding approximately 29% of the combined entity; and
• Notwithstanding that as described above, Sea Dragon acquired all of the issued and outstanding shares of Madison, the guidance in IFRS 10,
Consolidated Financial Statements and IFRS 3, Business Combinations, it has been determined that Sea Dragon Energy Inc. was actually the
accounting acquiree and Madison Petrogas Limited, was the accounting acquirer. As Madison Petrogas Limited was the accounting acquirer,
the Consolidated Financial Statements of SDX Energy Inc. is a continuation of the Madison Petrogas Limited Consolidated Financial Statements,
reflecting the equity instruments of Sea Dragon Energy Inc.
•
Immediately prior to the business combination completing, the name of the group was changed to SDX Energy Inc. The effective date of this
name change was September 30, 2015 and the effective date of the transaction was October 1, 2015.
The effective date of the transaction is October 1, 2015, the date on which the transaction completed.
As discussed above, under IFRS 3 the business combination is deemed to be a reverse takeover whereby Madison acquires Sea Dragon. This means that
a calculation is undertaken to compare the fair value of consideration provided to Sea Dragon shareholders versus the fair value of the assets that they
contributed to the combined entity. As described below, this transaction resulted in a Gain on Acquisition for SDX Energy Inc. as the fair value of the Sea
Dragon assets acquired was greater than the consideration it provided to the Sea Dragon shareholders by way of issue of SDX Energy Inc. common shares.
Calculation of Fair Value of shares issued to Sea Dragon Shareholders:
$000’s
Post consolidation SDX Energy Inc. outstanding shares 10,756
SDX Energy Inc. closing share priceas at September 30, 2015 in CAD$ 0.70
Fair value shares issued 7,529
USD/CAD exchange rate 0.7485
Fair value of shares issued - US$ 5,636
Transaction costs associated with this transaction have been included in the Consolidated Statement of Comprehensive Income; see note 21.
As required by IFRS 3 Business Combinations, management adopted the recognition principle and concluded that the fair value of Sea Dragon’s net assets
acquired was considered to be equal to their book value. Concomitantly to this transaction, management assessed impairment for its PP&E assets during
Q3 2015 and concluded that an insignificant headroom existed at that time, therefore any impairment was deemed to have already been reflected in the
financial statements as at September 30, 2015 and the book value of its PP&E was therefore concluded to be similar to its fair value at that time.
Subsequent to the issuance of Sea Dragon’s Q3 2015 Financial Statements, a significant decrease in oil prices triggered a new impairment assessment at
year end, which resulted in an impairment being recorded as at December 31, 2015 which is described in note 10 to the Consolidated Financial Statements.
The deemed fair value of Sea Dragon Energy Inc.’s identifiable assets and liabilities was determined as their accounting book value as at the date of the
business combination and these are shown below:
$000’s
Current assets (including cash acquired) 8,244
Current liabilities (excluding bank debt) (2,683)
Bank debt (1650)
Property, plant and equipment 16,747
Intangible exploration and evaluation assets 3,267
Total identifiable net assets at fair value 23,925
Paid by:
Fair value of shares issued 5,636
Less: Fair value of assets acquired 23,925
Gain on acquistion 18,289
The reverse takeover resulted in a bargain gain due to the shareholders of Sea Dragon Energy being prepared to, in a low oil price environment, accept a
transaction below fair value in exchange for enhancing Sea Dragon’s immediately available financial resources, near term cost of capital and future access
to capital in order to fund its current field development and exploration commitments, and provide a better platform for its future acquisition opportunities.
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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 marketers, 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
2016 2015
Cash and cash equivalents 4,725 8,170
Trade and other receivables 9,463 6,678
14,188 14,848
Total
Carrying amount
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
6. Financial risk management (continued)
(b) Credit risk (contiuned)
Trade and other receivables
All of the Company’s operations were conducted in Egypt and Cameroon. 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, 2016 and 2015.
The maximum exposure to credit risk for loans and receivables at the reporting date by type of customer was:
December 31 December 31
2016 2015
$000’s
Current
Government of Egypt controlled corporations 7,745 5,018
Joint venture partners 578 862
Other
1,140 798
Total trade and other receivables 9,463 6,678
Carrying amount
Current receivables of US$7.7 million related to oil, gas and NGL sales and production service fees which are due from EGPC (December 31, 2015:
US$5.0 million), a Government of Egypt controlled corporation.
Receivables in respect of oil sales and service fees are normally collected in two to three months following production. The Company expects to collect
outstanding receivables of US$3.4 million for NW Gemsa (2015: US$0.8 million), which includes the US$2.3 million gas and NGL revenue recognized in Q4 2016
(with no comparable balance at December 31, 2015), and US$2.3 million for Block – H Meseda (2015: US$1.2 million), in the normal course of operations.
The US$2.0 million of Shukheir Marine oil invoices (2015:US$3.0 million), which are pledged against the Company’s obligations under its South Disouq
work program, are expected to be collected during Q2 2017 as the South Disouq work programme is now complete.
The joint venture partner current accounts represent the net of monthly cash calls paid less billings received. Joint venture partner receivables of US$0.6
million (2015 - US$0.9 million) relate to the South Disouq concession only (2015: South Disouq US$0.8 million and Block – H Meseda US$0.1 million).
The other receivables of US$1.1 million consist of US$0.7 million related to prepayments, US$0.3 million for Goods and Services Tax (“GST”)/ Value
Added Tax (“VAT”) and US$0.1 million for other items.
The difference between the increase of US$2.8 million in Trade and other receivables as at December 31, 2016 and December 31, 2015 and the
increase of US$3.0 million as reflected in the Consolidated Statement of Cash Flows relates to foreign exchange movements.
As at December 31, 2016 and December 31, 2015, the Company’s trade and other receivables, is aged as follows:
December 31 December 31
2016 2015
$000’s
Current
Current (less than 90 days) 6,863 3,364
Past due (more than 90 days) 2,600 3,314
Total - current 9,463 6,678
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 decreased by US$0.8 million when compared to December 31, 2015.
This decrease is primarily due to the collection of US$1.0 million of the Shukheir Marine receivables as explained above.
Subsequent to December 31, 2016, the Company collected US$2.5 million of trade receivables from those that were outstanding at December 31,
2016; US$0.1 million for NW Gemsa representing October 2016 crude oil sales invoices, US$1.3 million for Meseda representing September, October
and November 2016 production service fees and US$1.4 million of the rolling South Disouq production guarantee referred to above.
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.
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(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, 2016, 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 the 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 EGP
and US$ and GBP and US$. The majority of capital expenditures are incurred in US$ and EGP and oil and service fee revenues are received in both
US$ and EGP. The Company is able to utilize EGP to fund its Egyptian office general and administrative expenses and to part-pay cash calls 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 Other
As at December 31, 2016 US$ equivalent
Cash and cash equivalents 4,725 1,847 2,104 694 80
Trade and other receivables 9,463 8,544 16 838 65
Trade and other payables (3,674) (1,757) (1,377) (525) (15)
Current income taxes (389) - (389) - -
Balance sheet exposure 10,125 8,634 354 1,007 (130)
(1) denotes Financial Statements
The average exchange rates during the three months ended December 31, 2016 and 2015 were 1 US$ equals:
Average: October 1, 2016 to December 31, 2016 Average: October 1, 2015 to December 31, 2015
USD/EGP USD/GBP USD/EGP USD/GBP
Period average 14.3634 0.8044 Period average 7.8530 0.6590
The average exchange rates during the twelve months ended December 31, 2016 and 2015 were 1 US$ equals:
Average: January 1, 2016 to December 31, 2016 Average: January 1, 2015 to December 31, 2015
USD/EGP USD/GBP USD/EGP USD/GBP
Period average 10.0211 0.7405 Period average 7.6849 0.6542
The exchange rates as at December 31, 2016 and 2015 were 1 US$ equals:
Period end: December 31, 2016 Period end: December 31, 2015
USD/EGP USD/GBP USD/EGP USD/GBP
Period end 18.1274 0.8113 Period end 7.8041 0.6755
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(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, 2016 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
2016 2015
Equity 37,264 55,246
Working capital (1) (11,823) (11,552)
Total capital 25,441 43,694
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
2016 2015
Bank balances 4,725 8,170
Cash and cash equivalents 4,725 8,170
Carrying amount
Cash at bank earns interest at floating rates based on the daily bank deposit rates.
8. Trade and other receivables
December 31 December 31
$000’s
2016 2015
Trade receivables 7,745 5,018
Other receivables 1,718 1,660
9,463 6,678
Total
For discussion of these balances, see Note 6 (b).
Carrying amount
9. Inventory
As at December 31, 2016 the Company undertook a comprehensive stockcounting exercise over all spare parts and consumables inventory. Given the
forthcoming exploration 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 SD1-X well. This inventory was from legacy exploration 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 a 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$0.5 million credit to the Consolidated Statement of Comprehensive Income, which has increased the book value of inventory from
US$1.2 million at December 31, 2015 to US$1.7 million at December 31, 2016.
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10. Property, plant and equipment
Oil and gas Furniture
properties and fixtures Total
$000’s
Cost:
Balance at December 31, 2014 12,824 174 12,998
Additions 1,375 17 1,392
Acquisitions 16,679 68 16,747
Foreign currency revaluation - (32) (32)
Decommissioning provision release (208) - (208)
Disposals - (8) (8)
Assets scrapped (7) (99) (106)
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
Accumulated depletion, depreciation, amortization and impairment:
Balance at December 31, 2014 (3,478) (128) (3,606)
Depletion, depreciation and amortization for the year (2,014) (43) (2,057)
Foreign currency revaluation - 28 28
Impairment charge (6,842) - (6,842)
Assets scrapped - 95 95
Balance at December 31, 2015 (12,334) (48) (12,382)
Depletion, depreciation, amortization and impairment for the year (3,225) (41) (3,266)
Impairment charge (4,303) - (4,303)
Balance at December 31, 2016 (19,862) (89) (19,951)
NBV Property, plant and equipment as at December 31, 2015 18,329 72 18,401
NBV Property, plant and equipment as at December 31, 2016 12,506 99 12,605
During the year ended December 31, 2016, PP&E additions of US$1.8 million predominantly related to the NW Gemsa concession and were for the
drilling of Al Amir SE-23 and Al Amir SE-24, and the well work over programme. The difference between the US$1.8 million disclosed above and the
US$0.2 million Property, plant and equipment expenditure in the Consolidated Statement of Cash Flows is due to the fact that c.US$1.6 million of the
costs of the Al Amir SE-23 and SE-24 wells are part of Trade and other payables as at December 31, 2016.
The Company has also recorded, on the face of the table above, the assets acquired from SDX Energy Inc., formerly Sea Dragon Energy Inc., as a result
of the business combination effective October 1, 2015. The gross cost of the assets acquired was US$31.3 million and the accumulated depletion and
depreciation (“DD&A”) US$14.6 million; shown above as a net cost of US$16.7 million.
At December 31, 2016 for the purposes of the depletion calculation, US$3.3 million (December 31, 2015 – US$3.4 million) of future development
costs are included in the calculation of cost in determining the depletion rate.
Impairment assessment
At the reporting date, management performed an impairment indicator assessment and concluded that due to a reduction in the proved and probable
reserves for the NW Gemsa concession, as well as increased forecast operating expenditure, the asset should be tested for impairment.
The impairment test was carried out in accordance with the accounting policy note stated in note 3. The recoverable amounts of the field has been determined
based on a value-in-use calculation. This calculation requires the use of estimates. The present values of future cash flows were computed by applying forecast
prices for oil and gas reserves to estimated future production of proved and probable reserves. The present value of estimated future net revenues is computed
using a discount factor of 12.5%. The discount rate used reflects the specific risks relating to the underlying cash generating unit (“CGU”).
Based on this calculation for NW Gemsa an impairment of US$4.3 million has been recorded.
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
10. Property, plant and equipment (continued)
The value in use calculation assumes Brent oil sales prices in US$/bbl as follows:
2016 2017 2018 2019 2020 2021 2022
US$54.40 US$58.25 US$57.85 US$50.05 US$58.61 US$59.17 US$59.85
If the discount factor applied to the impairment test were to increase by 2.5% above the current factor of 12.5%, the impairment of the NW Gemsa field
would increase by US$0.2 million.
If the discount factor applied to the impairment test were to decrease by 2.5% below the current factor of 12.5%, the impairment of the NW Gemsa field
would decrease by US$0.1 million.
A 10% reduction in the Brent oil sales price would increase the impairment by US$1.1 million.
A 15% reduction in the Brent oil sales price would increase the impairment by US$1.6 million.In the prior period the NW Gemsa field was impaired
by US$6.8 million, due to falling crude oil prices and a reduction in the proved and probable reserves.
11. Intangible exploration and evaluation assets
$000’s
Balance at December 31, 2014 16,460
Additions 3,728
Acquisitions 3,267
Exploration and evaluation expense 18
Balance at December 31, 2015 23,473
Additions 11,566
Exploration and evaluation expense (24,416)
Balance at December 31, 2016 10,623
The E&E additions of US$11.6 million consists of US$5.6 million primarily in relation to the drilling of the Manitee-1 exploration well in the Bakassi West
block in Cameroon (“Bakassi West”) and US$6.0 million in relation to the 3D seismic programme in the South Disouq concession in Egypt.
On June 16, 2016 the Company issued a press release announcing its intention to withdraw from the Bakassi West, Cameroon concession (which became
effective July 31, 2016).
As the Bakassi West drilling operations had been completed by June 30, 2016, the Company made a full provision against the capitalised exploration cost
of US$24.4 million and reflected the relevant impairment in the Consolidated Statement of Comprehensive Income Statement for the period to June 30,
2016. There has been no material change to this position as at December 31, 2016.
In addition to the US$24.4 million provision against capitalized exploration cost, the Consolidated Statement of Comprehensive Income for the year
ended December 31, 2016 reflects a further US$0.4 million of costs relating to new ventures activities.
12. 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 years ended December 31, 2016 and 2015.
The following table summarizes the changes in investments for the year ended December 31, 2016 and 2015:
December 31 December 31
$000’s
2016 2015
Investments, beginning of year 2,106 1,999
Dividends received (825) (917)
Share of profit 1,222 1,024
Investments, end of year 2,503 2,106
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The following table summarizes the Company’s 50% interest in the assets, liabilities, revenue and operating income of Brentford as at and for the years
ended December 31, 2016 and 2015:
December 31 December 31
$000’s
2016 2015
Total assets 2,405 2,469
Total liabilities 3 316
Revenue 1,656 1,816
Net profit 1,222 1,024
During the year ended December 31, 2016 50% (December 31, 2015 – 50%) of Brentford’s revenue was earned from fees charged to the Company.
13. Loans and borrowings
As at December 31, 2016 the Company had no loans or borrowings outstanding.
On September 23, 2011 SDX Dragon Energy Inc., formerly Sea Dragon Energy Inc., entered into a credit agreement with HSBC and BNP Paribas for a
5-year senior secured credit facility (the “Facility”) in the amount of US$50 million. The Facility was secured by a first charge on the shares, project
accounts and interests of certain of the Sea Dragon group of companies.
As at October 7, 2015 SDX Energy Inc. repaid the US$1.65 million that was outstanding on the Facility such that as at December 31, 2015 the Facility had
been repaid in full. All charges and liens held against the Company’s assets were released upon execution of the Deed of Release dated December 10, 2015.
As at September 30, 2015, prior to the business combination Sea Dragon Energy Inc. had US$0.4 million of deferred financing costs. The deferred
financing costs represented the unamortized costs of establishing the Facility which had been amortizing straight line over the five year term of the loan
facility. This amount was released to the Consolidated Statement of Comprehensive Income in October 2015 as a result of the full repayment and
termination of the Facility, see note 22.
14. Trade and other payables
December 31 December 31
2016 2015
$000’s
Current
Trade payables 663 198
Accruals 684 1,284
Other payables 2,327 2,074
3,674 3,556
Total
Carrying amount
Trade payables include US$0.3 million of NGL and gas transportation and treatment costs associated with the sales of these products recognized during
Q4 2016. There was no corresponding balance as at December 31, 2015.
Accruals primarily comprise general and administrative costs related to legal, audit, tax and reserve reporting fees. The main reduction from the position
as at December 31, 2015 is the absence of a US$0.5 million restructuring accrual which existed at December 31, 2015 and which since been settled.
Other payables of US$2.3 million comprise an estimated liability of US$0.5 million related to the relinquishment of the Shukheir Marine concession (2015:
US$1.1 million), partner current accounts of US$1.2 million for NW Gemsa (2015:US$0.7 million), US$0.5 million Block-H Meseda (2015:US$nil million)
concessions, UK payroll taxes and deferred payroll of US$0.1 million (2015: US$0.3 million).
The joint venture partner current accounts represent the net of monthly cash calls paid less billings received.
The difference between the increase of US$0.1 million in trade and other payables in the Consolidated Balance Sheets as at December 31, 2016 and
December 31, 2015 and the cash outflow relating the implied decrease of US$0.4 million as reflected in the Consolidated Statement of Cash Flows relates to
the removal of capital expenditure items from the comparison in the Consolidated Statement of Cash Flows and the impact of foreign exchange movements.
15. Debentures
On July 27, 2012 the Company completed a private placement for secured debentures in the amount of CDN$2,560,000. The debentures pay interest
at a rate of 10% per annum, payable semi-annually, and are repayable after two years. The debentures are redeemable after one year at face value plus
accrued interest, at the company’s option. During 2014, the Company extended the repayment of the debentures until July 31, 2015. The debentures
were repaid in full on May 4, 2015.
The debentures also included the issue of warrants to acquire common shares, on the basis of 500 warrants for each $1,000 of debentures. 1,280,000
warrants were issued at an exercise price of CDN $0.80 per share, exercisable at any time and expiring after two years. During 2014, the Company
extended the expiry date of the warrants until July 27, 2016.
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
15. Debentures (continued)
On October 1, 2015, as a result of the business combination, a common share purchase warrants second supplemental indenture agreement was entered
into which amended the number of warrants to 610,743 with an exercise prices of CDN$1.68. The Company valued the debentures assuming the discount
on the interest rate, as a result of including warrants, was approximately 2%. This resulted in a fair value of the debentures being CDN $2,460,000, with
the remaining fair value of CDN $100,000 (US$ 99,400) being assigned to the warrants.Accretion of the debentures for the year ended December 31,
2015 of $nil was recorded as interest expense, resulting in an effective interest rate on the debentures of 10%.
16. Decommissioning provision
As at December 31, 2016, the Company believes that no decommissioning provision is required.
The Company previously recognized a decommissioning provision in relation to its obligations under the Production Service Agreement (“PSA”) in
managing the oil and natural gas assets including well sites and gathering systems for Block-H Meseda. The total decommissioning provision was
estimated based on the Company’s contractual interest in all wells and facilities, estimated costs to plug all wells drilled and remove all facilities,
equipment and other assets from the field, and the estimated timing of the costs to be incurred in future years.
Upon conclusion of the business combination between SDX Energy Inc., formerly Sea Dragon Energy Inc., and Madison Petrogas Ltd., effective October 1,
2015 a full review of the PSA was undertaken. Upon completion of this review the Company has concurred that there is no obligation under the PSA and
the decommissioning provision has therefore been released. At the termination of the PSA the Company is obliged to return all assets, including well sites,
gathering systems, facilities and other assets to the Egyptian state owned oil company for the continued commercial production of the block.
As at September 30, 2015 the total future undiscounted cash flows was US$0.3 million, to be incurred between the years 2017 and 2035 and the liability
was discounted using a risk-free rate of 2.20%.
Carrying amount
December 31 December 31
$000’s
2016 2015
Decommissioning provisions, beginning of year - 217
Changes in estimate - (4)
Liabilities incurred - 36
Accretion - (9)
Release of decommissioning liability - (240)
Decommissioning provisions, end of year - -
17. Income Tax - Current and Deferred
Pursuant to the terms of the Company’s 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 deducted as
an income tax expense.
The Company has a PSA related to Block-H Meseda with legal title belonging to Madison Egypt Ltd, 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 the entity.
(a) Income tax expense differs from that which would be expected from applying the effective Canadian federal and provincial income tax rates
of 27% (2015 – 26%) to income before income taxes as follows:
Statement of Comprehensive Income
Twelve months ended December 31
2015
$000’s except per unit amounts
Income before income taxes (26,697) 12,684
2016
Canadian statutory income tax rate 27% 26%
Expected income taxes (7,208) 2,889
Adjustments:
Non deductible items (57) 193
Non taxable gain on acquisition - (4,750)
Unrecognized income tax benefit 385 344
Foreign tax differential 433 (50)
Expenses incurred with no recognized tax benefit 7,950 2,437
Total current and deferred income tax expense 1,503 1,063
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(b) The components of the deferred income tax assets and liabilities at December 31, 2016 and 2015 include the following:
Consolidated Blance Sheet
Twelve months ended December 31
2015
$000’s except per unit amounts
Deferred tax assets/(liabilities):
2016
Investments (9) (7)
Property and equipment (292) (286)
Non-capital losses 15,647 15,258
Deferred tax assets not recognized (15,636) (15,251)
Deferred income tax liability (290) (286)
(c) The Company has US$56.5 million of non-capital losses available at December 31, 2016 (2015: US$56.8 million) to shelter future taxable income,
the majority of which were incurred in Canada and expire between 2026 and 2035.
(d) The Company has not recognized its deferred tax assets of US$15.6 million at December 31, 2016 (2015: US$15.3 million) primarily relating
to its Canadian business as it has determined that its deferred tax assets are not probable to be realized from current operations.
18. 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, 2016 December 31, 2015
Number Number
of Shares Stated Value of Shares Stated Value
($000’s) ($000’s) ($000’s) ($000’s)
Balance, beginning of year 37,642 30,148 56,348 24,512
Business combination - - (29,462) -
Share for share exchange - - 10,756 5,636
Private placing of shares on the London Stock Exchange (AIM)
(less share issue costs) 42,202 10,127 - -
Balance, end of year 79,844 40,275 37,642 30,148
Weighted average shares outstanding 71,509 51,633
(c) Common Share Warrants issued
December 31, 2016 December 31, 2015
Number Number
of Shares Stated Value of Shares Stated Value
($000’s) ($000’s) ($000’s) ($000’s)
Balance, beginning of year 611 99 1,280 99
Business combination - - (669) -
Expiry of warrants (611) (99) - -
Balance, end of year - - 611 99
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, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
19. Stock-based compensation
The Company has an 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.
Effective October 1, 2015, and prior to the closing of the business combination between SDX Energy Inc., formerly Sea Dragon Energy Inc., and Madison,
both the Company and Madison cancelled all outstanding stock options. Written agreement was obtained from all directors, officers and employees.
The Company cancelled 28,900,000 stock options with a weighted average exercise price of CDN$0.09 and the directors, officers and employees
of the Company each received a nominal payment of CDN$1.00 for their cancelled options.
Madison cancelled 5,630,000 stock options with a weighted average exercise price of CDN$0.91. The directors, officers and employees of Madison
received cash compensation for cancelled options, based on the Black Scholes model, of CDN$300,083.
Post business combination the enlarged Company introduced a new option program. Pursuant to a Board Resolution effective November 30, 2015 the
Company granted Options to acquire 2,650,000 common shares at an exercise price of CDN$0.63 per common share. The Options have a three year
vesting period and expire five years from the anniversary date.
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 period 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. As a result, a non-cash stock based compensation credit of US$0.1m has
been recognized for the twelve months ended December 31, 2016. For the twelve months ended December 31, 2015 the Company recorded a non-cash
stock based compensation charge of US$0.8 million.
The number and weighted average exercise prices of share options for the Company’s option program is as follows:
Number Weighted average
of Options exercise price
(000’s) (CDN$)
Outstanding January 1, 2016 2,650 0.63
Cancelled during the period (395) 0.63
Issued during the period 190 0.36
Outstanding December 31, 2016 2,445 0.61
Exercisable December 31, 2016 1,567 0.62
The exercise price of the outstanding options is as follows:
Outstanding options Vested options
Number of Remaining Number of Remaining
Exercise price range options contractual life options contractual life
CAD $0.36 - $0.63 2,445,000 3 - 5 years 1,566,651 3 - 5 years
2016 2015
Fair value at grant date (CDN) $0.28 $0.61
Share price (CDN) $0.36 $0.63
Exercise price (CDN) $0.36 $0.63
Volatility (%) 70 70
Forfeiture (%) 0 0
Option life 5 years 5 years
Dividends (%) 0 0
Risk-free interest rate (%) 0.8 0.8
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20. Revenue, net of royalties
Twelve months ended December 31
2015
2016
Oil revenue 7,432 2,322
Royalties (3,190) (686)
Oil revenue, net of royalties 4,242 1,636
Gas revenue 2,210 -
Royalties (1,059) -
Gas revenue, net of royalties 1,151 -
NGL revenue 2,361 -
Royalties (1,199) -
NGL revenue, net of royalties 1,162 -
Production service fees 6,359 9,736
Total net revenue before tax 12,914 11,372
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.
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 to a dispute with EGPC over entitlement volumes. This dispute has now been
resolved such that the Company believes it appropriate to recognize revenues from October 1, 2013 to December 31, 2016, which equates to US$2.2
million of gas sales and US$2.4 million of NGLs. These sales were recognized in Q4 2016 and are reflected in the Consolidated Financial Statements.
The production service fees relate to Block-H Meseda, which is governed by a PSA, and covers the period January to December 2015.
21. General and administration expenses
Twelve months ended December 31
2015
2016
Wages and employee costs 2,532 2,828
Consultants - inc. PR/IR 479 499
Legal fees 237 124
Audit, tax and accounting services 246 449
Public company fees 332 228
Travel
166 250
Office expenses 668 490
IT expenses 322 75
Transaction costs - 496
Service recharges (1,303) (669)
Total - net G&A 3,679 4,770
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, CFO and Egypt Country Manager. Details of key management remuneration is shown in note 27.
General and administrative (“G&A”) costs for 2016 were US$3.7 million, which represented a decrease of US$1.1 million compared to 2015.
In accordance with IFRS 3 - Business Combinations (see note 4) the 2015 G & A expenses represent three months of SDX Energy Inc., formerly Sea Dragon
Energy Inc., and twelve months of Madison Petrogas Ltd. The Company incurred US$0.5 million of transaction costs in relation to the business combination.
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
22. Net finance income/(expense)
Twelve months ended December 31
2015
2016
Interest and bank charges (95) 273
Amortization of acility costs - (378)
Expiry of warrants 99 -
Accretion of decommissioning provisions - 9
Net finance income/(expense) 4 (96)
The amortization of Facility costs relates to the release of the deferred BNP Facility transaction costs as a result of the repayment of the outstanding
balance and the cancellation of the Facility, see note 13.
23. (Loss)/income per share
Twelve months ended December 31
December 31
2015
$000’s
Net (loss)/income before other comprehensive income for the year (28,200) 10,047
December 31
2016
Weighted average number of shares (000’s)
Basic 71,509 51,633
Diluted 71,557 51,633
Per share amount
Basic $(0.394) $0.195
Diluted $(0.394) $0.195
Basic (loss)/income 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.
At December 31, 2015 the strike price of such instruments was above the average market share price, therefore they became anti-dilutive, resulting in a
diluted EPS equal to the basic EPS. For the year ended December 31, 2016 a net loss before other comprehensive income was recorded and thus these
instruments became anti-dilutive, resulting in a diluted EPS equal to the basic EPS.
24. Segmental reporting
The Company is engaged in the business of exploration for and production of oil and gas only, which represents a single operating segment.
The executive directors are the Company’s chief operating decision maker within the meaning of IFRS 8.
Non-current assets other than financial instruments by country are as follows:
December 31 December 31
$000’s
2016 2015
Cameroon - 18,795
Egypt
25,707 25,145
United Kingdom 24 40
25,731 43,980
Total
Carrying amount
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25. Commitments and contingencies
Pursuant to the concession and production service fee agreements in Egypt, 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.
The commitments are for the drilling of one exploration well for South Disouq (US$1.3 million) and the drilling of one development well and facilities
upgrade for South Ramadan (US$2.9 million).
The development well for Block-H Meseda, is secured by a deposit of US$0.1 million withheld from the Company’s service fee revenue.
Currently the commitments as part of the concession agreements are as follows:
December 31 December 31
$000’s
2016 2015
Less than one year 1,340 13,677
Between one and five years 2,933 2,933
4,273 16,610
Total
The Company has a lease commitment for its office premises in Calgary and London under non-cancellable operating leases expiring within two to five years.
Commitments for minimum lease payments in relation to non-cancellable operating leases are payable as follows:
December 31 December 31
$000’s
2016 2015
Less than one year 318 302
Between one and five years 499 813
817 1,115
Total
26. 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
Name
Percentage operation registration
Sea Dragon Holdings Ltd. (Alberta) 100% Canada Canada
Sea Dragon Energy (UK) Ltd. 100% U.K. U.K.
SDX Energy Investments (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
Islands
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
Brentford Oil Tools 50% Egypt Egypt
SDX Energy Inc.
2016 Annual Report 73
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Notes to the Consolidated Financial Statements
For the years ended December 31, 2016 and 2015
(tabular amounts are in thousands of United States dollars except where stated)
27. Compensation of key management personnel
The remuneration of directors and other key management personnel during the years ended December 31, 2016 and 2015 was as follows:
Twelve months ended December 31
2015
2016
Salaries, incentives and short term benefits 1,087 2,271
Director’s fees 153 124
Stock based compensation (114) 642
1,126 3,037
Total
In the year ended December 31, 2015, termination benefits of US$377k were paid to Said Arrata, the former Chairman of the Company and
US$433k were paid to Olivier Serra, the former CFO of the Company.
28. Post balance sheet events
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$40.0 million before costs.
COEL holds a 40% interest in the NW Gemsa concession, Eastern Desert, Egypt. Prior to the acquisition, SDX held a 10% interest in this concession,
bringing the post-acquisition holding to 50%.
COML holds 75% interest and operatorship in certain licences, onshore Morocco, with L’Office National des Hydrocurbures et des Mines (“ONHYM”)
holding a 25% interest.
The acquisition is in accordance with the Company's strategy to pursue distressed production and development opportunities in North Africa alongside
organic growth.
The provisional fair value of the identifiable assets and liabilities of COEL and COML as at the date of acquisition were:
Fair value as at
January 27, 2017
US$ million
Non-current assets
Property, plant & equipment 43.2
Current assets
Cash and cash equivalents 3.1
Trade and other receivables 36.0
Inventory
1.2
Current tax 0.1
Non-current liabilities
Decommissioning liability (2.8)
Deferred income (0.7)
Current liabilities
Trade and other payables (18.9)
Decommissioning liability (1.2)
Deferred income (0.4)
Total identifiable net assets at fair value 59.6
Total consideration (28.1)
Excess of fair value over cost (bargain purchase) 31.5
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$31.5 million will be recognised in the Consolidated Statement of Comprehensive Income for the three months to March 31, 2017 and
twelve months to December 31, 2017. No provision has been made against the value of the acquired receivables.
COEL and COML contributed US$nil revenue and US$nil profit/loss to the Consolidated Financial Statements for year to December 31,2016.
74
SDX Energy Inc.
2016 Annual Report
Financial Statements
Corporate information
Executive Officers
Paul Welch
President &
Chief Executive Officer &
Chief Operating Officer
Mark Reid
Chief Financial Officer
Ahmed Farid Moaaz
Egypt Country Manager
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)
Capita Registrars (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
Cantor Fitzgerald Europe
Sarah Wharry/Craig Francis
One Churchill Place, Canary Wharf
London, E14 5RB, United Kingdom
T: +44 (0)20 7894 7000
Joint Broker
GMP FirstEnergy
Jonathan Wright/David van Erp
85 London Wall, London, EC2M 7AD
United Kingdom
T: +44 (0)20 7448 0200
Independent Engineers
Gaffney, Cline & Associates
London, United Kingdom
Auditors
PricewaterhouseCoopers LLP
431 Union Street, Aberdeen, AB11 6DA
United Kingdom
Public Relations
Celicourt Communications
Mark Antelme/Joanna Boon
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, 5203rd Avenue SW
Calgary, Alberta, Canada T2P 0R3
T: +1 (403) 457 5035
F: +1 (403) 457 5420
Egypt
Building #12, Al Nahda Street,
El-Maadi, Kornish El Nile, Cairo, Egypt
T: +20 2 2358 2172
F: +20 2 2750 8534
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.
2016 Annual Report 75
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High Margin Growth
www.sdxenergy.com