CALGARY, Alberta, March 07, 2018 (GLOBE NEWSWIRE) -- TransGlobe Energy Corporation (“TransGlobe” or the
“Company”) is pleased to announce its financial and operating results for the three months and year-ended December 31, 2017.
All dollar values are expressed in United States dollars unless otherwise stated. TransGlobe's Consolidated Financial
Statements together with the notes related thereto, as well as TransGlobe's Management's Discussion and Analysis for the years
ended December 31, 2017 and 2016, are available on TransGlobe's website at www.trans-globe.com.
2017:
- Produced an average of 15,506 Boepd and sold 16,849 Boepd as compared to 12,105 Boepd and 11,165 Boepd in 2016, a
28% and 51% increase year over year;
- Funds Flow from Operations increased to $55.6 million ($0.77/share), up from negative $8.4 million in 2016, best
result since 2014;
- Net loss of $78.7 million ($1.09/share) which includes a non-cash impairment charge of $79.0 million and a
non-cash mark-to-market loss on derivative instruments of $8.0 million;
- Refinanced the Convertible Debentures with a $75 million Prepayment Agreement and reduced the outstanding amount
to $60 million by year-end 2017;
- Reduced inventoried entitlement crude oil in Egypt from 1.3 million barrels to less than 0.8 million barrels,
which made a positive contribution to Funds Flow from Operations during the year;
- Ended the year with positive working capital of $50.6 million (including cash and cash equivalents of $47.4
million) at December 31, 2017;
- Spent $38.1 million on exploration and development activities in both Egypt and Canada;
- Drilled fifteen wells in Egypt (nine exploration, six development), resulting in two discoveries and four
development oil wells;
- Completed eastern desert exploration commitments;
- Three additional development leases approved at NWG;
- Drilled three Hz multi-stage Cardium oil wells in Canada to validate the development Cardium model; and
- Ended the year with 45.9 MMBoe of 2P reserves, down from 2016 year-end of 50.0 MMboe.
2018:
- January production of 14.2 MBoepd, February production of 14.5 MBoepd and estimated Q1 production of 14.3
MBoepd;
- Drilled a successful oil well at Arta 48 which will be placed on production in April following stimulation;
- Drilled a successful oil well at K-46 which will be placed on production in March;
- Reached agreement in principal with GPC to drill additional wells in the M-field buffer-zone, which are expected
to be drilled and put on production in Q2;
- Confirmed with EGPC four cargo liftings in 2018, including the first in late March; and
- Finalizing Canadian drilling program for six Cardium wells in 2018 which could include a two mile horizontal well
to evaluate extended reach horizontals in the Harmattan area.
A conference call to discuss TransGlobe’s 2017 fourth quarter and year-end results presented in this news
release will be held Wednesday, March 7, 2018 at 8:00 AM Mountain Time (10:00 AM Eastern Time) and is accessible to all interested
parties by dialing 416-340-2218 or toll free at 800-377-0758. The webcast may be accessed at
http://www.gowebcasting.com/9152.
FINANCIAL AND OPERATING RESULTS
(US$000s, except per share, price, volume amounts and % change)
|
Three months ended December 31 |
|
Year ended December 31 |
Financial |
2017 |
|
2016 |
|
%
Change |
|
2017 |
|
2016 |
|
% Change |
Petroleum and natural gas sales |
72,954 |
|
|
24,501 |
|
|
198 |
|
|
252,591 |
|
|
122,360 |
|
|
106 |
|
Petroleum and natural gas sales, net of royalties |
40,725 |
|
|
5,217 |
|
|
681 |
|
|
148,464 |
|
|
63,134 |
|
|
135 |
|
Realized derivative loss on commodity contracts |
(2,496 |
) |
|
— |
|
|
— |
|
|
(2,871 |
) |
|
(956 |
) |
|
200 |
|
Unrealized derivative loss on commodity contracts |
(7,584 |
) |
|
— |
|
|
— |
|
|
(7,970 |
) |
|
— |
|
|
— |
|
Production and operating expense |
10,856 |
|
|
5,617 |
|
|
93 |
|
|
50,212 |
|
|
40,323 |
|
|
25 |
|
Transportation costs |
227 |
|
|
12 |
|
|
— |
|
|
793 |
|
|
12 |
|
|
6,508 |
|
Selling costs |
569 |
|
|
— |
|
|
— |
|
|
2,495 |
|
|
875 |
|
|
185 |
|
General and administrative expense |
3,636 |
|
|
5,813 |
|
|
(37 |
) |
|
15,253 |
|
|
17,555 |
|
|
(13 |
) |
Depletion, depreciation and amortization expense |
10,401 |
|
|
4,639 |
|
|
124 |
|
|
40,036 |
|
|
29,177 |
|
|
37 |
|
Income taxes |
5,715 |
|
|
4,718 |
|
|
21 |
|
|
21,819 |
|
|
12,446 |
|
|
75 |
|
Cash flow generated by (used in) operating activities |
44,263 |
|
|
6,355 |
|
|
597 |
|
|
59,450 |
|
|
(1,065 |
) |
|
5,682 |
|
Funds flow from operations1 |
17,018 |
|
|
(9,904 |
) |
|
272 |
|
|
55,592 |
|
|
(8,361 |
) |
|
765 |
|
Basic per share |
0.24 |
|
|
(0.14 |
) |
|
|
|
0.77 |
|
|
(0.12 |
) |
|
|
Diluted per share |
0.24 |
|
|
(0.12 |
) |
|
|
|
0.77 |
|
|
(0.12 |
) |
|
|
Net loss |
(2,382 |
) |
|
(33,997 |
) |
|
93 |
|
|
(78,736 |
) |
|
(87,665 |
) |
|
10 |
|
Net loss - diluted |
(2,382 |
) |
|
(38,641 |
) |
|
94 |
|
|
(78,736 |
) |
|
(87,665 |
) |
|
10 |
|
Net loss per share |
|
|
|
|
|
|
|
|
|
|
|
Basic |
(0.03 |
) |
|
(0.49 |
) |
|
|
|
(1.09 |
) |
|
(1.21 |
) |
|
|
Diluted |
(0.03 |
) |
|
(0.49 |
) |
|
|
|
(1.09 |
) |
|
(1.21 |
) |
|
|
Capital expenditures |
9,078 |
|
|
8,864 |
|
|
2 |
|
|
38,159 |
|
|
26,658 |
|
|
43 |
|
Dividends paid |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Dividends paid per share |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Corporate acquisition |
— |
|
|
59,475 |
|
|
(100 |
) |
|
— |
|
|
59,475 |
|
|
(100 |
) |
Working capital |
50,639 |
|
|
(16,764 |
) |
|
402 |
|
|
50,639 |
|
|
(16,764 |
) |
|
402 |
|
Long-term debt |
69,999 |
|
|
— |
|
|
— |
|
|
69,999 |
|
|
— |
|
|
— |
|
Convertible debentures |
— |
|
|
72,655 |
|
|
(100 |
) |
|
— |
|
|
72,655 |
|
|
(100 |
) |
Note payable |
— |
|
|
11,162 |
|
|
(100 |
) |
|
— |
|
|
11,162 |
|
|
(100 |
) |
Common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
Basic (weighted average) |
72,206 |
|
|
72,206 |
|
|
— |
|
|
72,206 |
|
|
72,206 |
|
|
— |
|
Diluted (weighted average) |
72,206 |
|
|
79,377 |
|
|
(9 |
) |
|
72,206 |
|
|
72,206 |
|
|
— |
|
Total assets |
327,702 |
|
|
406,142 |
|
|
(19 |
) |
|
327,702 |
|
|
406,142 |
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
|
|
|
|
|
Average production volumes (boepd) |
13,952 |
|
|
13,148 |
|
|
6 |
|
|
15,506 |
|
|
12,105 |
|
|
28 |
|
Average sales volumes (boepd) |
16,249 |
|
|
7,305 |
|
|
122 |
|
|
16,849 |
|
|
11,165 |
|
|
51 |
|
Inventory (MBbls) |
777 |
|
|
1,265 |
|
|
(39 |
) |
|
777 |
|
|
1,265 |
|
|
(39 |
) |
Average sales price ($ per boe) |
48.80 |
|
|
36.45 |
|
|
34 |
|
|
41.07 |
|
|
29.94 |
|
|
37 |
|
Operating expense ($ per boe) |
7.26 |
|
|
8.36 |
|
|
(13 |
) |
|
8.16 |
|
|
9.87 |
|
|
(17 |
) |
1 Funds flow from
operations (before finance costs) is a measure that represents cash generated from operating activities before changes in
non-cash working capital and may not be comparable to measures used by other companies. |
MESSAGE TO THE SHAREHOLDERS
TransGlobe and the oil industry in general, faced another turbulent year associated with commodity price
volatility (3 years and counting). Energy fundamentals appear to be slowly improving as global inventories continue to reduce
against the backdrop of increasing demand. Brent oil prices strengthened during the year and firmed up to above $60.00 per barrel
in the fourth quarter, providing optimism as TransGlobe begins again to focus on growth over simply meeting our commitments and
surviving. Despite the macro environment that has persisted through most of the year, we had a significant year of
accomplishments: the integration of the Canadian assets, refinancing the convertible debentures, repaying the vendor-take-back note
("VTB"), continued discipline over G&A and operating expenditures, the reduction of Egypt crude oil inventory and the incident
free, safe execution of the 2017 plan in both Canada and Egypt. The increased oil sales during 2017 resulted in a significant
improvement to funds flow from operations and net earnings before impairments, and we are thrilled to have posted our highest
results since 2014.
TransGlobe’s production during 2017 averaged 15,506 barrels of oil equivalent per day ("boepd") with Egypt
averaging 12,822 barrels of oil per day ("bopd"), and Canada contributing an additional 2,684 boepd. Production was impacted
in the fourth quarter by delays in well servicing in Egypt during August/September and Canadian gas production shut-in during
September due to low gas prices. Production was lower than we had originally forecast due to a number of factors, including
lower than anticipated results in the development drilling in NW Gharib in the first half of the year and lowering our capital
expenditures to live within cash flow as lower commodity prices persisted until late in the third quarter.
Our 2017 drilling program included drilling fifteen wells in Egypt and three wells in Canada - our first
drilling activities in Canada since 2007. TransGlobe fulfilled all of our remaining exploration commitments in NW Gharib and
SW Gharib, through the drilling of nine wells, yielding two new oil discoveries in NW Gharib. The 2017 exploration program at
South Alamein, the Boraq 5 well, was a major disappointment for the Company with the well failing to recover oil on test. We
do plan to drill another exploration well in South Alamein in 2018, and a successful result will allow us to develop the existing
discovery at Boraq 2 (which was tested at 1,140 bopd in the fourth quarter). In addition to the exploration program, the Company
drilled nine development/appraisal wells resulting in seven oil wells (four in Egypt and three in Canada).
In Egypt, we drilled four development oil wells (one in K-South, one in the Arta Red Bed pool, and two in the NW
Gharib Red Bed pool) during the year. In addition, we filed for and received our second, third and fourth development leases
in NW Gharib during 2017. One additional Arta Red Bed development well and one K South development well were drilled and rig
released subsequent to December 31, 2017. In Canada, the Company successfully drilled three development oil wells in the
Harmattan area, which came in below our estimated cost and within or above type-curve expectations.
Reserves at year-end 2017 were lower than 2016 primarily due to 2017 production and negative revisions related
to our undeveloped Canadian Mannville gas locations which are uneconomic at current gas prices. Positive technical revisions
and new discoveries totaling approximately 4.7 MMBoe (2P) were partially offset by negative technical revisions of approximately
3.1 MMBoe (2P) of undeveloped Mannville gas in Canada, due principally to lower AECO pricing.
Despite the significant drop in Canadian gas prices at year end 2017 and associated negative technical
revisions, we are very pleased with our Canadian acquisition after one year. The validation of our undeveloped Cardium oil
potential, combined with significant reductions in operating costs and future development capital (per well), increased the present
value of future net revenues by 81% year over year on a total proved basis (discounted at 10%) and 57% year over year on a total
proved plus probable basis (discounted at 10%) as prepared by the Company’s independent reserves evaluators.
We were very pleased with our success in reducing inventoried crude oil during the year which resulted in total
sales of 16,849 Boepd versus production of 15,506 Boepd during 2017. Although we had hoped to reduce our inventory even more,
we did manage to reduce it by almost 0.5 million barrels in 2017 from year-end 2016. As a result we ended the year with under
0.8 million barrels of inventoried crude oil, which is approximately five months of entitlement oil production. This
achievement came through a combination of selling three cargo liftings marketed by Mercuria Energy Trading SA (“Mercuria”) and
additional monthly sales to the Egyptian Government Petroleum Company ("EGPC"). The Company has scheduled four liftings with EGPC
in 2018, with the first lifting scheduled for end of March 2018.
The Company generated positive funds flow from operations of $55.6 million ($0.77 per share), compared with
negative funds flow from operations of $8.4 million in 2016 (negative $0.12 per share). This large improvement in funds flow from
operations was due to a number of factors including higher production, sales (including reduction in crude oil inventory) and oil
prices and lower operating and G&A costs.
We ended 2017 with positive working capital of $50.6 million (which includes cash and cash equivalents of $47.4
million) compared to a working capital deficiency of $16.8 million at the end of 2016. This large year over year positive
change was due in part to improved operating results but also due to refinancing the convertible debentures with the proceeds from
the Prepayment Agreement which is long term debt, whereas the convertible debenture was classed as short term debt at the end of
2016.
TransGlobe experienced a net loss of $78.7 million inclusive of a $79.0 million non-cash impairment loss on the
Company's exploration and evaluation assets and an $8.0 million unrealized derivative loss on commodity contracts (mark-to-market
loss on the Company's hedging contracts). Excluding the impairment charge and the unrealized loss on derivative commodity
contracts, TransGlobe would have achieved net earnings of $8.3 million for 2017. The Company recognized impairments on SW
Gharib and NW Gharib principally due to the lack of, or scale of exploration results to date as compared to investments to
date. In South Alamein we determined that the Boraq discovery is smaller than anticipated and expenditures on that play
concept were impaired. In the case of both NW Gharib and South Alamein, the impairments do not imply we will cease exploring
these areas in the future - in fact, we have wells planned for both areas in 2018. SW Gharib was fully relinquished in the
year.
As mentioned, the Company completed a $75 million crude oil Prepayment Agreement between its wholly owned
subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria. The initial advance under the Prepayment Agreement was
used to repay the 6.0% convertible debentures of the Company which matured on March 31, 2017. The Company repaid $15.0
million of the amount outstanding under the Prepayment Agreement during 2017, exiting the year with $60 million outstanding under
the Prepayment Agreement. During the second quarter of 2017, the Company also entered into a revolving Canadian reserves-based
lending facility ("RBL") with Alberta Treasury Branches ("ATB") totaling C$30.0 million ($24.0 million). The Company repaid the
C$15.0 million ($11.0 million) VTB with the RBL and cash on hand.
Overall operating expenses per barrel decreased by approximately 17% to $8.16 during 2017 compared to $9.87 in
2016. In Egypt, operating costs were reduced by 12% to $8.65 from $9.88 in 2016. This reduction was achieved through a
number of factors, the chief of which was the significant efficiencies gained through merging our two eastern desert joint venture
companies. In addition, our team executed a strong optimization program during 2017, resulting in reduced operating
expenses. In Canada the Company focused on taking over the operations of the fields safely and then on increasing operational
efficiencies and field optimization work, including competitive tendering of service contracts. Ultimately we achieved an operating
cost per barrel in Canada of $5.62 versus 2016 costs per barrel of $8.14 representing a 31% reduction.
Gross G&A costs, excluding stock-based compensation, were $16.0 million in 2017 (2016 - $18.7 million),
representing a 14% decrease from prior year. This brought gross G&A per produced barrel down to $2.83/bbl, versus
$4.22/bbl in 2016. The decrease in G&A costs was mostly attributable to reduced staffing and office expenditures.
For 2018, the Company is planning to continue to focus on our two core areas of operations and look for
opportunities to expand our footprint in both of those areas, as well as regionally. As usual, our focus will be on
increasing our cash flow and long term development opportunity set within the Company. In Canada, we will be looking to
expand through land acquisitions and renegotiations of existing freehold leases. In Egypt we will be commencing exploration
drilling on our western desert concessions (NW Sitra, S. Ghazalat and S. Alamein), working to extend our existing development PSCs
which have expiries within the next ten years, and looking for synergistic acquisitions.
In 2017 management began to focus more of its investor relations efforts in the UK, Europe, the Middle East and
Africa (principally South Africa). This was driven by a lack of interest in our shares in North America which can be clearly
seen by the lack of recovery in our share price despite the recovery in oil prices since Q3 of 2017. During 2017 we met with
many institutional accounts in these areas and have come to understand that our current North American listings do not provide
adequate access for many of these geographically focused investors. Since September, we have been investigating the
possibility of listing TransGlobe common shares on an additional stock exchange to provide better access for these investors and we
expect to update our shareholders shortly on that matter.
I have stewarded TransGlobe as President & CEO for 22 years through several commodity price cycles. I am proud
of our people, our achievements and the survival of the Company through what I feel is the worst down cycle in my 42 years in the
industry. There are indications we are turning the corner on this cycle and I plan to devote more of my future time to
long-term corporate growth strategies during this rebound. As part of the refocus on growth, Randy Neely was promoted to President
and Edward Ok was promoted to VP Finance and CFO. Prior to his promotion, Randy served as TransGlobe’s VP Finance and CFO after
joining the Company in 2012. Eddie initially joined the Company as Deputy Finance Manager in the Company’s Cairo office in 2012 and
became the Company Controller based in Calgary in January 2015. They both have demonstrated the leadership, initiative and ability
to drive the future growth of the Company.
Signed by:
“Ross G. Clarkson”
Ross G. Clarkson
Chief Executive Officer
March 5, 2018
OPERATIONS UPDATE
ARAB REPUBLIC OF EGYPT
EASTERN DESERT
West Gharib, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
No wells were drilled during the fourth quarter. Subsequent to quarter-end, the drilling rig mobilized to
Arta 48, targeting the northern extension of the main Arta Red Bed pool in the boundary area between the Arta pool and the
offsetting new development lease (“DL”) in the NW Gharib concession (DL #3). The Arta 48 well is the first well drilled in the
buffer zone and encountered 45 feet of Red Bed formation with an internally estimated 20 feet of net oil pay. The Red Bed
conglomerate section encountered in Arta 48 will require a frac stimulation prior to placing on production. It is expected
that Arta 48 will be stimulated and placed on production in April. Additional stimulation work is planned for cased
Nukhul/Red Bed wells in NW Gharib DL 2 & 3 in March/April. A second well (Arta 54) in the buffer zone is scheduled for
drilling in March/April.
Production
Production from West Gharib averaged 5,015 Bopd during the fourth quarter, a 13% (726 bopd) decrease from the
previous quarter. Fourth quarter production was negatively impacted by well servicing delays. The Company has resumed servicing
operations and has contracted a second workover rig for the Eastern Desert to accelerate well workovers. The second rig began
operations in early December.
Production was 4,884 Bopd during January and increased to 5,223 Bopd during February. Production variances
during January and February were primarily due resumption of well servicing activities, offset by natural declines.
Sales
TransGlobe sold 163,924 barrels of inventoried entitlement crude oil (after royalties and tax) to EGPC for $8.4
million in the fourth quarter of 2017 to cover in-country expenditures.
Quarterly West Gharib Production (bopd) |
|
2017 |
|
|
Q-4 |
|
Q-3 |
|
Q-2 |
|
Q-1 |
Gross production rate |
|
5,015 |
|
|
5,741 |
|
|
6,389 |
|
|
6,683 |
|
TransGlobe working interest |
|
5,015 |
|
|
5,741 |
|
|
6,389 |
|
|
6,683 |
|
TransGlobe inventory held (lifted) |
|
774 |
|
|
(5,715 |
) |
|
(92 |
) |
|
3 |
|
Total sales |
|
4,241 |
|
|
11,456 |
|
|
6,481 |
|
|
6,680 |
|
Government share (royalties and tax) |
|
2,459 |
|
|
2,826 |
|
|
3,155 |
|
|
3,304 |
|
TransGlobe sales (after royalties and
tax)1 |
|
1,782 |
|
|
8,630 |
|
|
3,326 |
|
|
3,376 |
|
1 Under the terms of the
West Gharib Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing
oil. |
West Bakr, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
Due to the backlog of well workovers and the impact of well service delays; low cost, behind-pipe opportunities
in the K and H fields were delayed. These opportunities are scheduled as part of the 2018 production uplift program.
No wells were drilled during the fourth quarter. Subsequent to year-end, the Company drilled K 46
targeting the main Asl A sand in an up dip position in the south K-field pool. The well was drilled to a total depth of 4,510
feet and encountered an internally estimated 111 ft of total net oil pay in the Asl A and Asl B formations. The Asl A
formations (A1, A2 and A3) were encountered above the oil water contact with an internally estimated 96 feet of net oil pay.
The Asl B formation encountered approximately 15 feet of internally estimated net oil pay at the top of the Asl B formation.
The K 46 oil well will be completed and placed on production in March. A second well is planned in the south K field (K45) in the
second quarter.
In addition, an agreement in principal has been reached with GPC to drill two additional wells each, inside the
500 meter buffer zone between M field and the GPC Mesada field (M field extension) to the west. It is expected that the two new M
field wells, targeting the main Asl A formation, will be drilled and placed on production in late second quarter upon receipt of
military and EGPC approvals.
As part of the 2018 production uplift program, the Company recompleted the K47 and K 48 Asl A oil wells in the
south K field during February. The wells had originally been completed in the Upper A1 formations due to potential fluid
handling constraints at the K central production facility (“CPF”) associated with planned upgrades to the CPF. Both wells
(K47 and K48) were perforated in the Asl A2 formation, commingled with the Asl A1 formation, and placed back on production. K 47
production increased from approximately 50 Bopd to an initial rate of 125 Bopd. K 48 production increased from approximately 70
Bopd to an initial rate of 330 Bopd. A third potential recompletion candidate (K51) continues to produce approximately 330 Bopd
from the A1.
In September/October of 2017, the Phase 1 of the K station upgrade was completed. The Phase 2 expansion
scheduled for completion at the end of March will double the K station CPF fluid handling capacity to 30,000 Bpd. The third
production train (Phase 3) is scheduled for mid-2018 and will increase the total fluid handling capacity to 45,000 Bpd. The
remainder of the 2018 production uplift program in K field will be implemented during the year to coincide with the facility
expansions.
Production
Production from West Bakr averaged 5,024 bopd to TransGlobe during the fourth quarter, an 11% (627 bopd)
decrease from the previous quarter. The Company has resumed servicing operations and contracted a second workover rig to accelerate
well workovers for the Eastern Desert. The second rig began operations in early December.
Production increased to 5,121 Bopd during January and to 5,422 Bopd during February. Production increases
during January and February were primarily due resumption of well servicing activities and recompletions in February which were
partially offset by natural declines.
Sales
TransGlobe lifted and sold 510,148 barrels of Ras Gharib blend in November, all of which was allocated to West
Bakr entitlement crude inventory (after royalties and tax). The Company received $27.4 million ($24.8 million net of hedging) for
the November lifting in December.
Quarterly West Bakr Production (bopd) |
|
2017 |
|
|
Q-4 |
|
Q-3 |
|
Q-2 |
|
Q-1 |
Gross production rate |
|
5,024 |
|
|
5,651 |
|
|
6,085 |
|
|
6,284 |
|
TransGlobe working interest |
|
5,024 |
|
|
5,651 |
|
|
6,085 |
|
|
6,284 |
|
TransGlobe inventory held (lifted) |
|
(3,511 |
) |
|
2,288 |
|
|
(3,202 |
) |
|
2,545 |
|
Total sales |
|
8,535 |
|
|
3,363 |
|
|
9,287 |
|
|
3,739 |
|
Government share (royalties and tax) |
|
2,990 |
|
|
3,363 |
|
|
3,621 |
|
|
3,739 |
|
TransGlobe sales (after royalties and
tax)1 |
|
5,545 |
|
|
— |
|
|
5,666 |
|
|
— |
|
1 Under the terms of the West Bakr Production
Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil. |
North West Gharib, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
Two wells were drilled during fourth quarter resulting in one Red Bed oil well and one dry hole. NWG 3A ST1 was
a dry hole. Following NWG 3A ST1, the drilling rig moved to the NWG 38A2 appraisal well offsetting the NWG 38 A discovery
well which is currently producing 260 Bopd. The NWG 38 A2 appraisal well was drilled to a total depth of 5,315 feet and
encountered approximately 112 feet of Red Bed formation with an internally estimated 20 feet of net oil pay based on open-hole logs
and MDT samples. The well was completed and put on production late December, with a current production rate of ~460 bopd.
NWG 38 A2 is located approximately 0.4 km west of the NWG 38 A discovery well and intersected the NWG 38 red bed
pool in a structurally lower position (~43 feet lower) increasing the known “oil down to” for the 38A pool, which is currently
producing ~1,010 Bopd from three wells. The NWG-38A1 appraisal well drilled in the third quarter was stimulated and
placed on production in late October. The well is currently producing approximately 290 bopd.
Based on NWG 38A2 pressure data, the Company has initiated permitting to drill a structurally down-dip injector
and commence a pressure maintenance scheme (water flood) in the first half of 2018 to increase recoveries similar to the Arta Red
Bed pool in the adjacent West Gharib Concession.
Following receipt of approval for three development leases at NWG in September, the Company began production
during the fourth quarter at NWG DL 2 and 3. The NWG 1 (DL 3) and NWG 5 (DL 2) discovery wells were placed on production in
October.
The NWG 5 discovery is an Upper Nukhul discovery similar to and located immediately south of the Arta Upper
Nukhul pool in the West Gharib concession. The NWG 5 discovery wells (one discovery well and one appraisal well) are expected to
produce at similar rates to TransGlobe’s Arta Nukhul wells which typically have an initial 30 day production rate (IP 30) of
150-180 bopd with ultimate recoveries of 120-150 MBbls per well on primary production. The NWG 5x well came on production late
October following fracture stimulation with an IP30 production rate of 180 Bopd.
The NWG 1 discovery is located immediately North of the Arta Red Bed (Lower Nukhul) pool in the West Gharib
concession. The NWG 1 wells (one discovery well and one appraisal well) encountered a tight Red Bed conglomerate sequence which
requires stimulation to produce. Longer-term production from the NWG 1 wells will be required to establish expected per well
recoveries and the associated reserve assignments. NWG 1X came on production in late October following fracture stimulation with an
IP30 production rate of 90 Bopd.
The NWG 1B and NWG 5b, drilled in 2014, are scheduled for completion and stimulation in the second quarter along
with the newly drilled Arta 48 well in West Gharib. In parallel, the Company is evaluating the Nukhul formation (West Gharib
and NW Gharib) for horizontal multi-stage frac development potential, to increase recoveries and improve economics, similar to the
technology being used in the Canadian operations.
Production
Production from NWG averaged 1,212 bopd to TransGlobe during the fourth quarter, a 38% (336 bopd) decrease from
the previous quarter, primarily due to well servicing delays at NWG 3.
Production averaged 1,616 bopd during January, and 1,345 bopd during February. The increase in current
production levels from the fourth quarter is primarily due to the new wells (NWG 38A-2) NWG 1x and NWG 5x) being placed on
production during the quarter. February production levels decreased due to well servicing requirements.
Sales
TransGlobe did not sell its entitlement share of production (after royalties and tax) from NWG during the
quarter.
Quarterly North West Gharib Production (bopd) |
|
2017 |
|
|
Q-4 |
|
Q-3 |
|
Q-2 |
|
Q-1 |
Gross production rate |
|
1,212 |
|
|
876 |
|
|
1,377 |
|
|
982 |
|
TransGlobe working interest |
|
1,212 |
|
|
876 |
|
|
1,377 |
|
|
982 |
|
TransGlobe inventory held (lifted) |
|
439 |
|
|
318 |
|
|
499 |
|
|
356 |
|
Total sales |
|
773 |
|
|
558 |
|
|
878 |
|
|
626 |
|
Government share (royalties and tax) |
|
773 |
|
|
558 |
|
|
878 |
|
|
626 |
|
TransGlobe sales (after royalties and
tax)1 |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
1 Under the terms of the North West Gharib
Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil. |
WESTERN DESERT
South Alamein, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
Based on the Boraq 5 test results, the Boraq 2 discovery (which was flowed at an average rate of 1,140 Bopd of
35 API oil on a 64/64 inch choke over an 8 hour flow period prior to being shut-in for buildup in October of 2017) does not have
sufficient scale to proceed with development without additional exploration success on the South Alamein Concession. The
Company has approved an exploration well for South Alamein in the 2018 capital plan to test one of several exploration prospects
identified on 3D seismic, which if successful, could provide the additional reserves and productivity to bring forward a South
Alamein development.
South Ghazalat and North West Sitra, Arab Republic of Egypt (100% working interest,
operated)
Operations and Exploration
The Company is targeting to test four independent structures on South Ghazalat and N.W. Sitra during 2018.
The two South Ghazalat and two N.W. Sitra exploration wells are basin-opening wells, which could also de-risk 13 of the 21
additional prospects mapped on 3-D seismic. No production is budgeted from the Western Desert exploration assets in 2018.
CANADA
Operations and Exploration
In Canada, the Company equipped and tied in the three new Cardium horizontal wells during October. In
aggregate, the wells have exceeded TransGlobe’s internal IP90 estimate of 153 boepd. With one well producing above the curve,
one well on the curve and one well below the curve. The poorer performing well experienced pressure communication with an offset
well during fracking and subsequently only 85% of the planned frac sand tonnage was placed in formation. Based on the results
to date and the stronger oil prices, the Company approved an initial 6 well drilling program for 2018 targeting undeveloped Cardium
oil in the Harmattan area. The Company is currently finalizing its 2018 plans, which could include one two-mile horizontal well to
evaluate the merits of extended reach horizontals that have had success in the Ferrier/Willesden Green Cardium areas north of
Harmattan.
The Company continues to evaluate properties for acquisition in the greater Harmattan area.
Production
Production from Canada averaged 2,741 boepd to TransGlobe during the fourth quarter, a 4% (97 boepd) increase
from the previous quarter. Oil production increased to 775 bopd during the quarter representing a 50% (257 bopd) increase from the
previous quarter. The increased oil production is attributed to the three new Cardium horizontal wells, which were tied
in and placed on production during October.
Production averaged 2,563 boepd (62% oil and liquids) in January and 2,509 boepd (62% oil and liquids) in
February. Cold weather during January and February negatively impacted total production by approximately 100 boepd due to
freeze offs and equipment issues on smaller producers.
Quarterly Canada Production (boepd) |
|
2017 |
|
|
Q-4 |
|
Q-3 |
|
Q-2 |
|
Q-1 |
Canada crude oil (bbls/d) |
|
775 |
|
|
518 |
|
|
496 |
|
|
565 |
|
Canada NGLs (bbls/d) |
|
915 |
|
|
1,081 |
|
|
919 |
|
|
1,037 |
|
Canada natural gas (mcf/d) |
|
6,058 |
|
|
6,268 |
|
|
7,191 |
|
|
7,075 |
|
Total production (boe/d) |
|
2,700 |
|
|
2,644 |
|
|
2,613 |
|
|
2,782 |
|
SELECTED ANNUAL INFORMATION
($000s, except per share, price and volume
amounts) |
|
2017 |
|
|
% Change |
|
2016 |
|
|
% Change |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
|
|
|
|
Average production volumes |
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
13,411 |
|
|
11 |
|
|
12,033 |
|
|
(17 |
) |
|
14,511 |
|
NGLs and condensate (bbls/d) |
|
988 |
|
|
28065 |
|
|
34 |
|
|
100 |
|
|
— |
|
Natural gas (mcf/d) |
|
6,644 |
|
|
27895 |
|
|
230 |
|
|
100 |
|
|
— |
|
Total (boe/d) |
|
15,506 |
|
|
28 |
|
|
12,105 |
|
|
(17 |
) |
|
14,511 |
|
Average sales volumes |
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
14,754 |
|
|
33 |
|
|
11,093 |
|
|
(7 |
) |
|
11,977 |
|
NGLs and condensate (bbls/d) |
|
988 |
|
|
28065 |
|
|
34 |
|
|
100 |
|
|
— |
|
Natural gas (mcf/d) |
|
6,644 |
|
|
27895 |
|
|
230 |
|
|
100 |
|
|
— |
|
Total (boe/d) |
|
16,849 |
|
|
51 |
|
|
11,165 |
|
|
(7 |
) |
|
11,977 |
|
Average realized sales prices |
|
|
|
|
|
|
|
|
|
|
Crude oil ($/bbl) |
|
44.71 |
|
|
49 |
|
|
30.05 |
|
|
(30 |
) |
|
42.93 |
|
NGLs and condensate ($/bbl) |
|
21.31 |
|
|
24 |
|
|
17.20 |
|
|
100 |
|
|
— |
|
Natural gas ($/mcf) |
|
1.70 |
|
|
(6 |
) |
|
1.81 |
|
|
100 |
|
|
— |
|
Total oil equivalent ($/boe) |
|
41.07 |
|
|
37 |
|
|
29.94 |
|
|
(30 |
) |
|
42.93 |
|
Inventory (Mbbl) |
|
777 |
|
|
(39 |
) |
|
1,265 |
|
|
37 |
|
|
923 |
|
Petroleum and natural gas sales |
|
252,591 |
|
|
106 |
|
|
122,360 |
|
|
(35 |
) |
|
187,665 |
|
Petroleum and natural gas sales, net of royalties |
|
148,464 |
|
|
135 |
|
|
63,134 |
|
|
(32 |
) |
|
92,212 |
|
Cash flow from operating activities |
|
59,450 |
|
|
5,682 |
|
|
(1,065 |
) |
|
(101 |
) |
|
77,526 |
|
Funds flow from operations1 |
|
55,592 |
|
|
765 |
|
|
(8,361 |
) |
|
6 |
|
|
(8,902 |
) |
- Basic per share |
|
0.77 |
|
|
|
|
(0.12 |
) |
|
|
|
(0.12 |
) |
- Diluted per share2 |
|
0.77 |
|
|
|
|
(0.12 |
) |
|
|
|
(0.12 |
) |
Net loss |
|
(78,736 |
) |
|
10 |
|
|
(87,665 |
) |
|
17 |
|
|
(105,600 |
) |
Net loss - diluted |
|
(78,736 |
) |
|
10 |
|
|
(87,665 |
) |
|
17 |
|
|
(105,600 |
) |
Net loss per share |
|
|
|
|
|
|
|
|
|
|
- Basic |
|
(1.09 |
) |
|
|
|
(1.21 |
) |
|
|
|
(1.44 |
) |
- Diluted2 |
|
(1.09 |
) |
|
|
|
(1.21 |
) |
|
|
|
(1.44 |
) |
Capital expenditures |
|
38,159 |
|
|
43 |
|
|
26,658 |
|
|
(41 |
) |
|
44,902 |
|
Property expenditures |
|
— |
|
|
(100 |
) |
|
59,475 |
|
|
— |
|
|
— |
|
Dividends paid |
|
— |
|
|
|
|
— |
|
|
(100 |
) |
|
12,865 |
|
Dividends paid per share |
|
— |
|
|
|
|
— |
|
|
(100 |
) |
|
0.18 |
|
Total assets |
|
327,702 |
|
|
(19 |
) |
|
406,142 |
|
|
(11 |
) |
|
455,500 |
|
Cash and cash equivalents |
|
47,449 |
|
|
51 |
|
|
31,468 |
|
|
(75 |
) |
|
126,910 |
|
Working capital |
|
50,639 |
|
|
402 |
|
|
(16,764 |
) |
|
(111 |
) |
|
153,835 |
|
Convertible debentures |
|
— |
|
|
(100 |
) |
|
72,655 |
|
|
14 |
|
|
63,848 |
|
Note payable |
|
— |
|
|
(100 |
) |
|
11,162 |
|
|
100 |
|
|
— |
|
Total long-term debt, including current portion |
|
69,999 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Net debt-to-funds flow ratio3 |
|
0.3 |
|
|
|
|
(12.0 |
) |
|
|
|
10.1 |
|
Reserves |
|
|
|
|
|
|
|
|
|
|
Total Proved (MMboe)4 |
|
27.5 |
|
|
(8 |
) |
|
29.9 |
|
|
71 |
|
|
17.5 |
|
Total Proved plus Probable
(MMboe)4 |
|
45.9 |
|
|
(8 |
) |
|
50.0 |
|
|
74 |
|
|
28.7 |
|
1 Funds flow from operations
(before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working
capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures". |
2 Funds flow from operations per
share (diluted) and net loss per share (diluted) was not impacted by the convertible debentures for the years ended December
31, 2017, December 31, 2016 and December 31, 2015, as the convertible debentures were not dilutive in these years. |
3 Net debt-to-funds flow from
operations ratio is a measure that represents total long-term debt (including the current portion), plus convertible debentures
and working capital, over funds flow from operations for the trailing 12 months, and may not be comparable to measures used by
other companies. See "Non-GAAP Financial Measures". |
4 As
determined by the Company's 2017 independent reserves evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), in their report dated
January 9, 2018, with an effective date of December 31, 2017. As determined by the Company's, 2016 and 2015 independent
reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports dated January
18, 2017, and January 15, 2016 with effective dates of December 31, 2016, and December 31, 2015. The reports of GLJ and
DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared
jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy &
Petroleum (Petroleum Society), as amended from time to time and National Instrument 51-101. |
5 The 2016 information includes
the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12
days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016 (effective December 1,
2016). |
In 2017 compared with 2016, TransGlobe:
- Reported a net loss of $78.7 million, versus $87.7 million in 2016. The 2017 net loss includes a $79.0 million non-cash
impairment loss on the Company's exploration and evaluation assets and a $8.0 million unrealized derivative loss on commodity
contracts (mark-to-market loss on the Company's hedging contracts). Excluding the impairment charge and the unrealized loss on
derivative commodity contracts, the Company would have achieved net earnings for 2017 of $8.3 million;
- Reported a 28% increase in production volumes as compared to 2016, which translates into an additional 3,401 boepd. The
recently acquired Canadian assets contributed 2,684 boepd of additional production, and increased Egypt production accounted for
the remaining variance. The increased Egypt production was primarily from NW Gharib, which contributed 1,112 bopd;
- Experienced a 106% increase in petroleum and natural gas sales compared to 2016, which was principally due to a 37% increase
in realized prices along with a 51% increase in sales volumes;
- Achieved positive funds flow from operations of $55.6 million, compared with negative funds flow from operations of $8.4
million in 2016;
- Repaid the $73.4 million (C$97.8 million) convertible debentures on March 31, 2017 with the proceeds from the prepayment
agreement entered into with Mercuria Energy Trading S.A. ("Mercuria") in Q1 of 2017;
- Repaid the $11.0 million (C$15.0 million) vendor take-back note with the revolving reserves-based lending facility ("RBL"),
obtained from Alberta Treasury Branches ("ATB") in Q2 of 2017 and cash;
- Repaid $15.0 million of the amount outstanding under the prepayment agreement with cash on hand;
- Sold three tanker liftings of entitlement crude oil totaling 1,468,726 barrels and sold an additional 1,121,391 barrels of
inventoried entitlement crude oil to EGPC, resulting in a net decrease in crude oil inventory of 0.5 million barrels from
2016;
- Spent $38.2 million on capital programs, which was funded from funds flow from operations and cash on hand; and
- Ended the year with positive working capital of $50.6 million (including cash and cash equivalents of $47.4 million) at
December 31, 2017.
OPERATING RESULTS AND NETBACK
Daily Volumes, Working Interest before Royalties (Boepd)
Production Volumes
|
|
2017 |
|
|
2016 |
|
Egypt crude oil (bbls/d) |
|
12,822 |
|
|
12,015 |
|
Canada crude oil (bbls/d) |
|
589 |
|
|
18 |
|
Canada NGLs (bbls/d) |
|
988 |
|
|
34 |
|
Canada natural gas (mcf/d) |
|
6,644 |
|
|
230 |
|
Total Company
(boe/d) |
|
15,506 |
|
|
12,105 |
|
Sales Volumes (excludes volumes held as inventory)
|
|
2017 |
|
|
2016 |
|
Egypt crude oil (bbls/d) |
|
14,165 |
|
|
11,075 |
|
Canada crude oil (bbls/d) |
|
589 |
|
|
18 |
|
Canada NGLs (bbls/d) |
|
988 |
|
|
34 |
|
Canada natural gas (mcf/d) |
|
6,644 |
|
|
230 |
|
Total Company
(boe/d) |
|
16,849 |
|
|
11,165 |
|
Netback
Consolidated netback |
|
|
|
|
|
|
|
|
|
|
2017 |
|
2016 |
(000s, except per boe
amounts)1 |
|
$ |
|
|
$/boe |
|
|
$ |
|
|
$/boe |
|
Petroleum and natural gas sales |
|
252,591 |
|
|
41.07 |
|
|
122,360 |
|
|
29.94 |
|
Royalties |
|
104,127 |
|
|
16.93 |
|
|
59,226 |
|
|
14.49 |
|
Current taxes |
|
21,819 |
|
|
3.55 |
|
|
15,455 |
|
|
3.78 |
|
Operating expenses |
|
50,212 |
|
|
8.16 |
|
|
40,323 |
|
|
9.87 |
|
Transportation |
|
793 |
|
|
0.13 |
|
|
12 |
|
|
— |
|
Selling costs |
|
2,495 |
|
|
0.41 |
|
|
875 |
|
|
0.21 |
|
Netback |
|
73,145 |
|
|
11.89 |
|
|
6,469 |
|
|
1.59 |
|
1 The Company achieved the netbacks
above on sold barrels of oil equivalent for the year ended December 31, 2017 and December 31, 2016 (these figures do not
include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2017 and December 31, 2016). |
2 Royalties and taxes are settled on a
production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement
oil. |
Egypt |
|
|
|
|
|
|
|
|
|
|
2017 |
|
2016 |
(000s, except per bbl
amounts)1 |
|
$ |
|
|
$/bbl |
|
|
|
$ |
|
|
$/bbl |
|
Oil sales |
|
230,323 |
|
|
44.55 |
|
|
121,728 |
|
|
30.03 |
|
Royalties |
|
99,336 |
|
|
19.21 |
|
|
|
59,094 |
|
|
14.58 |
|
Current taxes |
|
21,819 |
|
|
4.22 |
|
|
15,455 |
|
|
3.81 |
|
Production and operating expenses |
|
44,705 |
|
|
8.65 |
|
|
40,054 |
|
|
9.88 |
|
Selling costs |
|
2,495 |
|
|
0.48 |
|
|
875 |
|
|
0.22 |
|
Netback |
|
61,968 |
|
|
11.99 |
|
|
6,250 |
|
|
1.54 |
|
1 The Company achieved the netbacks
above on sold barrels of oil for the year ended December 31, 2017 and December 31, 2016 (these figures do not include
TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2017 and December 31, 2016). |
2 Royalties and taxes are settled on a
production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement
oil. |
The netback per bbl in Egypt increased 679% in 2017 compared with 2016. The increased netbacks were principally
the result of realized oil prices increasing by 48%, an increase in previously inventoried entitlement barrels sold (488,326
barrels) and a decrease in operating costs per barrel of 12% during 2017 compared with 2016.
Production and operating expenses increased by $4.7 million during 2017 compared to 2016. This is principally
the result of an increase in sales volumes in 2017, resulting in recognizing the capitalized operating costs associated with the
crude oil inventory in the period. On a per bbl basis, production and operating costs have decreased by 12% compared to 2016. The
most significant cost efficiencies were achieved in the areas of labour costs and well servicing. The devaluation of the Egyptian
pound, which occurred in Q4 of 2016, also had a positive impact on operating expenses in the year as compared to 2016. The gains
realized from increased prices and lower operating costs were offset somewhat by higher transportation and marketing fees incurred
on the direct sales of the Company's crude oil. TransGlobe completed three direct sales of crude oil during 2017.
Royalties and taxes as a percentage of revenue were 53% in 2017 compared with 61% for 2016. Royalties and taxes
are settled on a production basis, so the correlation of royalties and taxes to oil sales fluctuates depending on the timing of
inventoried oil sales. As such, in periods when the Company sells less than its entitlement production, royalties and taxes as a
percentage of revenue will be higher and in periods when the Company sells more than its entitlement production, royalties and
taxes as a percentage of revenue will be lower.
The average selling price for the year-ended December 31, 2017 was $44.55/bbl, which was $9.70/bbl lower than
the average Dated Brent oil price of $54.25/bbl for 2017 (2016 - $43.55/bbl). Generally the difference in the average Dated Brent
price and the Company's realized selling price is due to a gravity/quality differential and is impacted by the timing of direct
sales.
Canada |
|
|
|
|
|
|
|
|
|
|
2017 |
|
2016 |
(000s, except per boe amounts) |
|
$ |
|
|
$/boe |
|
|
$ |
|
|
$/boe |
|
Crude oil sales |
|
10,464 |
|
|
48.67 |
|
|
266 |
|
|
40.38 |
|
Natural gas sales |
|
4,120 |
|
|
10.19 |
|
|
152 |
|
|
10.83 |
|
NGL sales |
|
7,684 |
|
|
21.31 |
|
|
214 |
|
|
17.20 |
|
Total sales |
|
22,268 |
|
|
22.73 |
|
|
632 |
|
|
19.12 |
|
Royalties |
|
4,791 |
|
|
4.89 |
|
|
132 |
|
|
3.99 |
|
Operating expenses |
|
5,507 |
|
|
5.62 |
|
|
269 |
|
|
8.14 |
|
Transportation |
|
793 |
|
|
0.81 |
|
|
12 |
|
|
0.36 |
|
Netback |
|
11,177 |
|
|
11.41 |
|
|
219 |
|
|
6.63 |
|
The Canadian financial information presented in the table above represent 2017 full year activity and 12 days of
activity for 2016, following the closing of the Harmattan acquisition on December 20, 2016.
Netbacks in Canada for 2017 were $11.41 per boe, which represents an increase of $4.78 per boe as compared to
2016. The increased netback was primarily attributable to increased average commodity prices and as a result of cost containment
efforts in 2017 which focused on increased operational efficiencies, field optimization work, and competitive tendering of service
contracts. The Company executed a strong optimization program during 2017, resulting in minimal downtime and reduced operating
expenses.
TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with an established
royalty regime. In Alberta, crown royalty rates are based on reference commodity prices, production levels and well depths
and are offset by certain incentive programs (which typically have a finite period of time and are in place to promote drilling
activity by reducing overall royalty expense).
For the year-ended December 31, 2017, the Company incurred $4.8 million in royalty costs. Royalties
amounted to 22% of petroleum and natural gas sales revenue in 2017.
MANAGEMENT STRATEGY AND OUTLOOK
The 2018 outlook provides information as to management’s expectation for results of operations for 2018. Readers
are cautioned that the 2018 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to
fluctuations in the business environment, including disruptions caused by the ongoing political changes and civil unrest occurring
in the jurisdictions that the Company operates in, and may vary accordingly. This outlook contains forward-looking
statements that should be read in conjunction with the Company’s disclosure under “Forward-Looking Statements”, outlined on the
first page of this Management's Discussion & Analysis ("MD&A").
2018 Outlook
The 2018 production outlook for the Company is provided as a range to reflect timing and performance
contingencies.
Total corporate production is expected to range between 14,200 and 15,600 boepd for 2018 (mid-point of 14,900
boepd) with a 94% weighting to oil and liquids. Egypt oil production is expected to range between 12,000 and 13,000 bopd in 2018.
Canadian production is expected to range between 2,200 and 2,600 boepd in 2018, adjusting for a one month shut-in for plant and
facility turnarounds scheduled for May in the Harmattan area. The May shut-in is expected to reduce corporate production by
approximately 200 boepd on an annualized basis.
Funds flow from operations in any given period will be dependent upon the timing of crude oil tanker liftings in
Egypt and the market price of the crude sold. Because these factors are difficult to accurately predict, the Company has not
provided funds flow from operations guidance for 2018. Funds flow from operations and inventory levels in Egypt are expected
to fluctuate significantly from quarter to quarter due to the timing of liftings.
2018 Capital Budget
The Company’s 2018 budgeted capital program of $41.3 million (before capitalized G&A) includes $29.1 million
for Egypt and $12.2 million (C$15.3 million) for Canada. The 2018 capital program is balanced to anticipated funds flow from
operations using a $55/bbl Brent oil price forecast. The capital program may be increased if the recent run-up in Brent prices is
sustained.
Egypt
The $29.1 million capital program for Egypt has $11.7 million (40%) allocated to exploration and $17.4 million
(60%) to development. The $11.7 million 2018 exploration program is focused entirely on the Western Desert with 5 exploration wells
planned (2 wells in South Ghazalat, 2 wells in NW Sitra and 1 well in South Alamein). The $17.4 million 2018 development program,
focused entirely on the Eastern Desert includes: 8 development wells (5 in West Bakr, 2 in NW Gharib and 1 in West Gharib) and
development/maintenance projects in West Bakr, NW Gharib and West Gharib.
The primary focus of the 2018 Egypt capital plan is to sustain/grow Eastern Desert production and to evaluate
the Company’s 1 million + acres of exploration lands. The exploration program is designed to test an independent structure at South
Alamein to prove up additional oil reserves on the concession and to test four independent structures on South Ghazalat and N.W.
Sitra. The South Ghazalat and N.W. Sitra exploration wells are basin opening prospects which could also de-risk 13 of the 21
additional prospects mapped on 3-D seismic. No production is budgeted from the Western Desert exploration assets in 2018.
Canada
The $12.2 million (C$15.3 million) budgeted program for Canada consists of 6 (5.5 net) horizontal (multi-stage
frac) wells targeting the Cardium light oil resource at Harmattan and additional maintenance/development capital. The Cardium
drilling program in 2018 provides growth in oil and liquids production. The development program is expected to increase the
Canadian oil and liquids production weighting to approximately 67% from 60% in 2017.
The well design for the 2018 development program will be similar to the 2017 which targeted one mile horizontal
laterals with multi-stage facture stimulations placing ~600 tonnes of proppant per well. The final 2018 completion design will
incorporate lessons learned and results from the 2017 program. Based on 2017 results, the Company is budgeting ~$2.0 million (C$2.5
million) per well to drill, complete, equip and tie-in for the 2018 program. In addition the Company is evaluating a potential two
mile horizontal Cardium well as part of the 2018 program.
The 2018 capital program is summarized in the following table:
|
|
TransGlobe 2018 Capital
($MM) |
|
|
|
Gross Well
Count |
|
|
Development |
|
Exploration |
|
Total |
|
Drilling |
Concession |
|
Wells* |
|
Other |
|
Wells* |
|
Other |
|
|
Devel |
|
Explor |
|
Total |
West Gharib |
|
2.6 |
|
1.1 |
|
|
— |
|
— |
|
|
3.7
|
|
1
|
|
—
|
|
1
|
West Bakr |
|
7.3 |
|
3.1 |
|
|
— |
|
— |
|
|
10.4
|
|
5
|
|
—
|
|
5
|
NW Gharib |
|
2.4 |
|
0.9 |
|
|
— |
|
— |
|
|
3.3
|
|
2
|
|
—
|
|
2
|
NW Sitra |
|
— |
|
— |
|
|
5.2 |
|
0.2 |
|
|
5.4
|
|
—
|
|
2
|
|
2
|
South Ghazalat |
|
— |
|
— |
|
|
3.3 |
|
0.2 |
|
|
3.5
|
|
—
|
|
2
|
|
2
|
South Alamein |
|
— |
|
— |
|
|
2.8 |
|
— |
|
|
2.8
|
|
—
|
|
1
|
|
1
|
Egypt |
|
$12.3 |
|
$5.1 |
|
|
$11.3 |
|
$0.4 |
|
|
$29.1
|
|
8
|
|
5
|
|
13
|
Canada |
|
$11.2 |
|
$1.0 |
|
|
— |
|
— |
|
|
$12.2
|
|
6
|
|
—
|
|
6
|
2018 Total |
|
$23.5 |
|
$6.1 |
|
|
$11.3 |
|
$0.4 |
|
|
$41.3
|
|
14
|
|
5
|
|
19
|
Splits (%) |
|
72%
|
|
28%
|
|
100%
|
|
74%
|
|
26%
|
|
100%
|
*Wells includes new wells, completions,
workovers, recompletions and equipping. |
READER ADVISORIES
Forward-Looking Statements
This news release may include certain statements that may be deemed to be “forward-looking statements”
within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Such statements relate to possible future events.
All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often,
but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”,
“will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions.
These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ
materially from those anticipated in such forward-looking statements. Although TransGlobe’s forward-looking statements are based on
the beliefs, expectations, opinions and assumptions of the Company’s management on the date the statements are made, such
statements are inherently uncertain and provide no guarantee of future performance. In particular, this press release contains
forward-looking statements regarding the Company's appraisal, development and evaluation plans and the focus of the Company's
exploration and development budget. In addition, information and statements relating to “resources” are deemed to be
forward-looking information and statements, as they involve the implied assessment, based on certain estimates and assumptions,
that the resources described exist in the quantities predicted or estimated, and that the resources described can be profitably
produced in the future. Actual results may differ materially from TransGlobe’s expectations as reflected in such forward-looking
statements as a result of various factors, many of which are beyond the control of the Company. These factors include, but are not
limited to, unforeseen changes in the rate of production from TransGlobe’s oil and gas properties, changes in price of crude oil
and natural gas, adverse technical factors associated with exploration, development, production or transportation of TransGlobe’s
crude oil and natural gas reserves, changes or disruptions in the political or fiscal regimes in TransGlobe’s areas of activity,
changes in tax, energy or other laws or regulations, changes in significant capital expenditures, delays or disruptions in
production due to shortages of skilled manpower, equipment or materials, economic fluctuations, and other factors beyond the
Company’s control. With respect to forward-looking statements contained in this press release, assumptions have been made
regarding, among other things: the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner;
the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts
and will conduct its business; future capital expenditures to be made by the Company; future sources of funding for the Company’s
capital programs; geological and engineering estimates in respect of the Company’s reserves and resources; and the geography of the
areas in which the Company is conducting exploration and development activities. TransGlobe does not assume any obligation to
update forward-looking statements if circumstances or management’s beliefs, expectations or opinions should change, other than as
required by law, and investors should not attribute undue certainty to, or place undue reliance on, any forward-looking statements.
Please consult TransGlobe’s public filings at www.sedar.com and www.sec.gov/edgar.shtml for further, more detailed information
concerning these matters, including additional risks related to TransGlobe's business.
For further information, please contact:
Investor Relations
Telephone: (403) 264-9888
Email: investor.relations@trans-globe.com
Web site: www.trans-globe.com
OR
Public Relations
FTI Consulting
+44 (0) 203 727 1000
Ben Brewerton / Ed Westropp / Emerson Clarke
energy@fticonsulting.com