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TransGlobe Energy Corporation Announces Year-End 2017 Financial and Operating Results

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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  
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  
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

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