EX-7 7 a2017q-1interimreport.htm EXHIBIT 7 Exhibit

image0a78.jpg
 
 
 
2017 FIRST QUARTER INTERIM REPORT
 
Financial and Operating Results
For the three-month period ended March 31, 2017
All dollar values are expressed in United States dollars unless otherwise stated
 
 
 
ø
 
First quarter production averaged 16,731 Boepd (13,826 Boepd sales) versus 12,058 Bopd (14,126 Bopd sales) in Q1-2016;
 
 
 
ø
 
Positive first quarter funds flow of $2.5 million (Q1-2016 - negative $2.8 million) despite selling only 54% of Egypt entitlement crude oil production in a depressed oil price environment;
 
 
 
ø
 
Finalized $75 million crude oil prepayment facility and marketing arrangement with Mercuria Energy Trading S.A. ("Mercuria"), the proceeds of which were used to repay the convertible debentures;
 
 
 
ø
 
Sold 303,817 barrels of inventoried entitlement crude oil to EGPC for $12.7 million to cover in-country expenditures for Q1/Q2;
 
 
 
ø
 
First full quarter of production from NW Gharib development block, which averaged 982 Bopd;
 
 
 
ø
 
Inventory of 1,528,295 barrels of entitlement crude oil at quarter-end (valued at cost). Next lifting to sell inventory scheduled for June 19th to 20th;
 
 
 
ø
 
First quarter net loss of $12.9 million;
 
 
 
ø
 
Ended the quarter with positive working capital of $42.8 million, which includes cash and cash equivalents of $37.7 million (including restricted cash);
 
 
 
ø
 
Spent $10.7 million on exploration and development during the quarter;
 
 
 
ø
 
Took over field operations of the acquired Canadian assets February 1st and initiated surface land acquisition/permitting for up to eight wells in the Harmattan area. The Company is targeting mid-year to commence the drilling program;
 
 
 
ø
 
Drilled seven wells in Egypt (six exploration and one development), resulting in three oil wells and four dry holes;
 
 
 
ø
 
Drilled the second of two infill development oil wells at West Gharib in the Arta Red Bed pool;
 
 
 
ø
 
Subsequent to quarter-end drilling rig mobilized to South Alamein concession, with drilling expected to begin in the first half of May; and
 
 
 
ø
 
Completed NW Sitra 600 km2 3-D seismic acquisition.

A conference call to discuss TransGlobe's 2017 first quarter results as presented was held on Thursday, May 11, 2017 and can be accessed on the Company's website at http://www.trans-globe.com/investors/presentations-and-events/index.php

www.trans-globe.com
TSX: TGL NASDAQ: TGA

 


CONTENTS
Financial and Operating Results
Page 3
Corporate Summary
Page 4
Operations Update
Page 5
Management's Discussion and Analysis
Page 9
Condensed Consolidated Interim Financial Statements
Page 24
Notes to Condensed Consolidated Interim Financial Statements
Page 28



















Annual General Meeting of Shareholders

Thursday, May 11, 2017

3:00 p.m. Mountain Time

Centennial Place West Conference Centre

Bow River Room

3rd Floor, 250 5th Street S.W.

Calgary, Alberta, Canada


2
 
Q1-2017
 


FINANCIAL AND OPERATING RESULTS
(US$000s, except per share, price, volume amounts and % change)
 
 
Three months ended March 31
Financial
 
2017

 
2016

 
% Change
Petroleum and natural gas sales
 
46,553

 
29,022

 
60
Petroleum and natural gas sales, net of royalties
 
22,461

 
17,427

 
29
Realized derivative gain (loss) on commodity contracts
 
—

 
(258
)
 
100
Unrealized derivative gain (loss) on commodity contracts
 
(3,729
)
 
—

 
(100)
Production and operating expense
 
10,123

 
13,121

 
(23)
Transportation costs
 
198

 
—

 
100
Selling costs
 
—

 
828

 
(100)
General and administrative expense
 
4,446

 
3,523

 
26
Depletion, depreciation and amortization expense
 
8,512

 
10,016

 
(15)
Income taxes
 
5,420

 
978

 
454
Cash flow generated by (used in) operating activities
 
(2,497
)
 
1,426

 
(275)
Funds flow from operations1
 
2,502

 
(2,830
)
 
—
Basic per share
 
0.03

 
(0.04
)
 

Diluted per share
 
0.03

 
(0.04
)
 

Net earnings (loss)
 
(12,877
)
 
(16,249
)
 
21
   Basic per share
 
(0.18
)
 
(0.23
)
 

   Diluted per share
 
(0.18
)
 
(0.23
)
 

Capital expenditures
 
10,718

 
4,265

 
151
Working capital
 
42,759

 
75,158

 
(43)
Long-term debt, including current portion
 
73,549

 
—

 
100
Convertible debentures
 
—

 
66,506

 
(100)
Note payable
 
11,259

 
—

 
100
Common shares outstanding
 

 

 

   Basic (weighted average)
 
72,206

 
72,206

 
—
   Diluted (weighted average)
 
72,206

 
72,206

 
—
Total assets
 
403,686

 
441,624

 
(9)
 
 
 
 
 
 
 
Operating
 
 
 
 
 
 
Average production volumes (Boepd)
 
16,731

 
12,058

 
39
Average sales volumes (Boepd)
 
13,826

 
14,126

 
(2)
Inventory (Bbls)
 
1,528,295

 
734,872

 
108
Average sales price ($ per Boe)
 
37.41
 
22.58
 
66
Operating expense ($ per Boe)
 
8.14
 
10.21
 
(20)
Notes:
 
 
 
 
 
 
1 Funds flow from operations 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.

 Average reference prices
 
2017

 
2016
 
 
Q-1

 
Q-4

 
Q-3

 
Q-2

 
Q-1

Crude oil
 
 
 
 
 
 
 
 
 
 
Dated Brent average oil price (US$/Bbl)
 
53.68

 
49.19

 
45.79

 
45.52

 
33.70

Edmonton Sweet index (US$/bbl)
 
48.37

 
46.18

 
41.99

 
42.51

 
29.76

Natural gas
 
 
 
 
 
 
 
 
 
 
AECO (C$/mmbtu)
 
2.69

 
3.09

 
2.32

 
1.40

 
1.83

U.S./Canadian Dollar average exchange rate
 
1.323

 
1.334

 
1.305

 
1.289

 
1.375



Q1-2017
 
3
 


CORPORATE SUMMARY
TransGlobe Energy Corporation ("TransGlobe" or the "Company") produced an average of 16,731 barrels of oil equivalent per day ("boepd") during the first quarter of 2017, which was within the full-year 2017 production guidance range of 15,500 to 18,500 boepd. Egypt production was 13,949 barrels of oil per day ("bopd"), and Canada production was 2,782 boepd.
The Company sold 303,817 barrels of inventoried entitlement crude oil to EGPC during the first quarter for $12.7 million. The proceeds will be used to cover in-country expenditures during the first half of 2017. The Company's next cargo lifting from Egypt is scheduled for June 19, 2017, and is expected to be in the range of 500 to 540 Mbbls. All Canadian production was sold during the quarter.
The Company repaid its convertible debentures in full on March 31, 2017, which was the maturity date of the debentures. The convertible debentures were denominated in Canadian dollars, and the aggregate face value of all outstanding convertible debentures was C$97.8 million ($73.4 million). The repayment was made using the funds received by drawing on the $75 million prepayment agreement with Mercuria.
Dated Brent oil prices averaged $53.68 per barrel in the first quarter of 2017. TransGlobe's Gulf of Suez crude is sold at a quality discount to Dated Brent and received a blended price of $41.29 per barrel during the quarter. TransGlobe's Canadian production received an average of $48.82 per barrel of oil and $1.96 per mcf of natural gas during the first quarter. The Company had funds flow of $2.5 million and ended the quarter with positive working capital of $42.8 million, which includes cash and cash equivalents of $37.7 million (including restricted cash).
The Company experienced a net loss in the quarter of $12.9 million, which included a $1.2 million impairment loss on the Company's SW Gharib concession and a $3.7 million unrealized loss on derivative commodity contracts. The $3.7 million loss on derivative commodity contracts represents a fair value adjustment on the Company's hedging contracts as at March 31, 2017.
The Company had two drilling rigs operating in Egypt for the duration of the first quarter. During the quarter, the Company drilled seven wells (six exploration and one development), resulting in three oil wells and four dry holes. One drilling rig will remain in the Eastern Desert and continue drilling at NW Gharib during the second quarter, and the other drilling rig was moved in early May from the Eastern Desert to the South Alamein concession in the Western Desert. The initial drilling program at South Alamein will consist of one well (Boraq 5) on the Boraq structural complex plus re-entering the Boraq 2 discovery well for additional testing. At NW Sitra, the Company completed the 600 km2 seismic acquisition program at the end of March. The newly acquired data is being processed with prospect mapping planned for the second half of 2017.
In Canada, the Company initiated surface land acquisition/permitting for up to eight wells in the Harmattan area in 2017. The Company is targeting mid-year to commence the drilling program of horizontal (multi-stage frac) wells targeting the Cardium light oil resource. It is expected that wells will cost ~C$2.5 to C$2.7 million per well to drill, complete and place on production.
The Company appointed two new directors to its Board of Directors during the first quarter. Mr. Matthew Brister and Mr. Steve Sinclair took positions as independent directors on the Company's Board effective March 15, 2017. Mr. Geoff Chase, a long-term director with TransGlobe, will retire in May 2017.




























4
 
Q1-2017
 


OPERATIONS UPDATE
ARAB REPUBLIC OF EGYPT
EASTERN DESERT
West Gharib, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
During the first quarter, the second of two infill development wells in the Arta Red Bed pool was drilled. Each infill well was completed and put on production in the first quarter producing at a combined rate of 800 Bopd. Realized costs to drill and equip for production averaged less than $0.8 million per well.

Production
Production from West Gharib averaged 6,683 Bopd to TransGlobe during the first quarter, a 1% (82 Bopd) increase from the previous quarter. Production additions from the infill development wells in the Arta Red Bed pool were offset by natural declines and well servicing of high volume producers.
Production averaged 6,449 Bopd during April.
Sales
TransGlobe sold 303,817 barrels of inventoried entitlement crude oil to EGPC for $12.7 million in the first quarter of 2017 to cover in-country expenditures for Q1/Q2. As at the end of the first quarter, TransGlobe had an inventory position (under-lift) of 643,744 barrels at West Gharib.
Quarterly West Gharib Production (Bopd)
 
2017

 
2016
 
 
Q-1

 
Q-4

 
Q-3

 
Q-2

Gross production rate
 
6,683

 
6,601

 
6,629

 
7,264

TransGlobe working interest
 
6,683

 
6,601

 
6,629

 
7,264

TransGlobe production inventoried (lifted)
 
3


3,339


(1,819
)

3,665

Total sales
 
6,680

 
3,262

 
8,448

 
3,599

Government share (royalties and tax)
 
3,304

 
3,262


3,277


3,599

TransGlobe sales (after royalties and tax)1
 
3,376

 
—

 
5,171

 
—

Note:
 
 
 
 
 
 
 
 
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
No wells were drilled during the first quarter. Subsequent to quarter-end, the K-47 development well was drilled and cased as an Asl A oil well in the South-K field. K-47 was drilled to a total depth of 1,372 meters (4,500 feet) and encountered an internally estimated 23.5 meters (77 feet) of net oil pay in the targeted Asl A formation. The well is scheduled for completion and initial production in the second quarter. An additional South-K development well is planned for the second half of 2017.

Further, the Company has identified additional low cost, behind-pipe opportunities in the K and H fields. Scheduling of these recompletions is underway, with related production volumes projected in the second or third quarter of 2017.

Production
Production from West Bakr averaged 6,284 Bopd to TransGlobe during the first quarter, a 2% (150 Bopd) increase from the previous quarter, primarily due to well servicing and reliability offset by natural declines.
Production averaged 6,098 Bopd during April.
Sales
TransGlobe did not sell its entitlement share of production (after royalties and tax) from West Bakr during the quarter which resulted in an ending inventory position (under-lift) of 850,655 barrels.

Q1-2017
 
5
 


Quarterly West Bakr Production (Bopd)
 
2017

 
2016
 
 
Q-1

 
Q-4

 
Q-3

 
Q-2

Gross production rate
 
6,284

 
6,134

 
5,104

 
4,208

TransGlobe working interest
 
6,284

 
6,134

 
5,104

 
4,208

TransGlobe production inventoried (lifted)
 
2,545


2,484


2,067


(3,976
)
Total sales
 
3,739

 
3,650

 
3,037

 
8,184

Government share (royalties and tax)
 
3,739


3,650


3,037


2,504

TransGlobe sales (after royalties and tax)1
 
—

 
—

 
—

 
5,680

Note:
 
 
 
 
 
 
 
 
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
During the first quarter, the Company drilled four wells resulting in two oil discoveries (NWG 26 and NWG 27) and two dry holes (NWG 39 and NWG 42). Subsequent to the quarter, the Company drilled one dry hole (NWG 40), thereby completing the first phase work program.
NWG 39 was drilled to a total depth of 5,650 feet targeting a Red Bed prospect immediately north of the NWG Development lease 1. The well encountered thick Red Bed reservoir, which was wet and subsequently abandoned. Subsequent to the quarter, NWG 40 was drilled to 5,322 feet. The well encountered Red Bed reservoir, which was wet and subsequently abandoned. NWG 40 was the final exploration commitment well in the first exploration phase of the NWG concession. The rig was moved to the Western Desert to drill Boraq 5, an appraisal well at South Alamein.
NWG 42 was drilled to a total depth of 6,400 feet targeting a separate Red Bed prospect north of the NWG Development lease 1. The well encountered thick Red Bed reservoir, which was wet and subsequently abandoned. Subsequent to the quarter, the drilling rig moved to the West Bakr concession to drill the K-47 development oil well in the South-K field. Following K-47 the rig has moved back to NWG to drill appraisal wells in the NWG #1 development lease. The appraisal wells will offset the NWG 3 and NWG 38 Red Bed oil producers.
Concurrently, the Company completed and stimulated one well on each of the NWG 1 and NWG 5 discoveries (discovered in 2014). Both wells were put on short term pump production tests to partially recover the stimulation fluid and establish new oil production from the discoveries. The wells produced ~150 to 180 Bopd. Following the short production tests the wells were shut in pending approval of the respective development leases. The Company filed development lease applications for the NWG 1 and NWG 5 discoveries prior to May 6th, which was the expiry date of the first exploration phase on NWG. It is expected that new development leases could receive approval in 1 to 3 months from the application date.
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 (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 1 discovery is located immediately north of the Arta Red Bed (Lower Nukhul) pool in the West Gharib concession. The NWG 1 wells (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.
In addition, the Company filed a development lease application for the area immediately north of the NWG development lease #1 on May 3 which includes the NWG 26 and 27 wells.
The NWG exploration lands have been fully evaluated and all commitments have been met at the end of the first exploration phase (May 6, 2017). The Company has elected not to enter the second exploration period and has filed development lease applications on the discovery areas. The Company has relinquished the remaining exploration lands that are not covered by development lease applications.
Production

Production from NW Gharib averaged 982 Bopd to TransGlobe during the first quarter. Following receipt of approval of the NWG development plan on December 10, 2016, NWG 3 was placed on production in late December under natural flow at 600-1,000 Bopd from the Red Bed formation. NWG 3 was equipped with tubing and a downhole pump in late March, and is currently producing 1,000 Bopd. NWG 38 was completed and placed on production at an initial pumping rate of ~750 Bopd in January and is currently producing at a rate of ~600 Bopd.

Production has averaged 1,722 Bopd during April.

Sales
TransGlobe did not sell its entitlement share of production (after royalties and tax) from NW Gharib during the quarter, which resulted in an ending inventory position (under-lift) of 33,896 barrels.



6
 
Q1-2017
 

Quarterly North West Gharib Production (Bopd)
 
2017

 
2016
 
 
Q-1

 
Q-4

 
Q-3

 
Q-2

Gross production rate
 
982

 
55

 
—

 
—

TransGlobe working interest
 
982

 
55

 
—

 
—

TransGlobe production inventoried (lifted)
 
356

 
20

 
—

 
—

Total sales
 
626

 
35

 
—

 
—

Government share (royalties and tax)
 
626

 
35

 
—

 
—

TransGlobe sales (after royalties and tax)1
 
—

 
—

 
—

 
—

Note:
 
 
 
 
 
 
 
 
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.

South West Gharib, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration
At SW Gharib the Company drilled two exploration wells during the first quarter. The Company fulfilled the work program at SW Gharib following the drilling of SWG 2 and SWG 4. The wells were drilled to 8,382 feet and 7,537 feet, respectively, and subsequently abandoned. The Company elected to relinquish the concession following completion of the first phase exploration commitment work program.
WESTERN DESERT
South Alamein, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

At South Alamein, the initial drilling campaign will consist of one well (Boraq 5) on the Boraq structural complex plus re-entering the Boraq 2 discovery well for additional testing. A drilling rig was moved to Boraq 5 in early May. The Boraq 5 appraisal well is targeting the Cretaceous oil pools discovered at Boraq 2X. Successful appraisal wells could lead to filing a Boraq development plan as early as Q2/Q3-2017 with first production targeted to year-end 2017/early 2018. In parallel, the Company is evaluating the remaining exploration prospects on the concession, targeting an exploration drilling program commencing in late 2017 and extending into 2018. The South Alamein concession was acquired in July 2012 and contains the Boraq 2X discovery (see May 1, 2012 press release for more details) and several additional exploration targets. The Boraq 2X discovery tested approximately 1,600 Bopd from two zones. The primary Cretaceous zone tested at a rate of 800 to 1,323 Bopd of 34 API oil with no water and a 13% pressure drawdown during a 28 hour drill stem test (DST). A secondary Cretaceous zone tested at a rate of 274 Bopd of 32-35 API oil and 4% water during a 23 hour DST. Test rates are not necessarily indicative of long-term performance or ultimate recovery but it is anticipated that the well should be capable of producing approximately 1,600 Bopd.

South Ghazalat, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

At South Ghazalat, the Company has met all financial commitments for the first exploration phase, and is targeting to have a drill-ready prospect
inventory prepared during 2017. South Ghazalat could be drilled (two wells) in conjunction with North West Sitra in the 2018 exploration program.

North West Sitra, Arab Republic of Egypt (100% working interest, operated)

At NW Sitra, the Company completed the 600 km2 seismic acquisition program at the end of March. The new data is being processed with prospect mapping planned for the second half of 2017.
CANADA
Operations and Exploration
No wells were drilled during the first quarter.
TransGlobe took over field operations on February 1st and initiated surface land acquisition/permitting for up to eight wells in the Harmattan area. The initial 2017 program consists of up to eight horizontal (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan. The Company is targeting June/July to commence the drilling program. The wells are expected to cost C$2.5 - C$2.7 million per well to drill, complete and place on production.
The Company continues to evaluate properties for acquisition in the greater Harmattan area.

Q1-2017
 
7
 

Production
Production from Canada averaged 2,782 Boepd to TransGlobe during the first quarter.
Production has averaged 2,670 Boepd during April.
Quarterly Canada Production (Boepd)
 
2017

 
2016
 
 
Q-1

 
Q-4

 
Q-3

 
Q-2

Canada crude oil (bbls/d)
 
565

 
18

 
—

 
—

Canada NGLs (bbls/d)
 
1,037

 
34

 
—

 
—

Canada natural gas (mcf/d)
 
7,075

 
230

 
—

 
—

Total production (boe/d)
 
2,782

 
90

 
—

 
—



8
 
Q1-2017
 


MANAGEMENT'S DISCUSSION AND ANALYSIS
May 9, 2017
The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the unaudited Condensed Consolidated Interim Financial Statements of the Company for the three months ended March 31, 2017 and 2016 and the audited Consolidated Financial Statements and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2016 included in the Company's annual report. The Condensed Consolidated Interim Financial Statements are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board in the currency of the United States (except where otherwise noted). Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The Company’s annual report on Form 40-F may be found on EDGAR at www.sec.gov.
READER ADVISORIES
Forward-Looking Statements
Certain statements or information contained herein may constitute forward-looking statements or information under applicable securities laws, including, but not limited to, management’s assessment of future plans and operations, anticipated changes to the Company's reserves and production, collection of accounts receivable from the Egyptian Government, timing of directly marketed crude oil sales, drilling plans and the timing thereof, commodity price risk management strategies, adapting to the current political situation in Egypt, reserve estimates, management’s expectation for results of operations for 2017, including expected 2017 average production, funds flow from operations, the 2017 capital program for exploration and development, the timing and method of financing thereof, the terms of drilling commitments under the Egyptian PSCs and the method of funding such drilling commitments, the Company's beliefs regarding the reserve and production growth of its assets and the ability to grow with a stable production base, and commodity prices and expected volatility thereof. Statements relating to "reserves" are deemed to be forward‑looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
Forward-looking statements or information relate to the Company’s future events or performance. All statements other than statements of historical fact may be forward-looking statements or information. Such statements or information 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.
Forward-looking statements or information necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, economic and political instability, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals, failure to collect the remaining accounts receivable balance from EGPC, ability to access sufficient capital from internal and external sources and the risks contained under "Risk Factors" in the Company's Annual Information Form which is available on www.sedar.com. The recovery and reserve estimates of the Company's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company.
In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on the Company's future operations. Such statements and information may prove to be incorrect and readers are cautioned that such statements and information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements or information because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market and receive payment for its oil and natural gas products.
Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian and U.S. securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) and at the Company's website (www.trans-globe.com). Furthermore, the forward-looking statements or information contained herein are made as at the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
The reader is further cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

Q1-2017
 
9
 

All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. The actual crude oil and natural gasreserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of crude oil and natural gas reserves does not represent the fair market value of these reserves.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent(boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.


10
 
Q1-2017
 


MANAGEMENT STRATEGY AND OUTLOOK
The 2017 outlook provides information as to management’s expectation for results of operations for 2017. Readers are cautioned that the 2017 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 MD&A.
2017 Outlook
It is expected that 2017 production will average between 15,500 and 18,500 boepd, representing a 30% to 55% increase over 2016 production (production in Q1-2017 was 16,761 boepd).  The 2017 production outlook is provided as a range to reflect the firm and contingent budget. Funds flow 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 guidance for 2017. Funds flow and inventory levels in Egypt are expected to fluctuate significantly from quarter to quarter due to the timing of liftings.
2017 Capital Budget
The Company's 2017 capital program of $56.4 million (before capitalized G&A) consists of a $35.2 million firm budget and a $21.2 million contingent budget, and includes $40.2 million for Egypt and $16.2 million (C$22.4 million) for Canada.
Egypt
The $25.8 million Egypt firm program has $14.4 million (56%) allocated to exploration and $11.4 million (44%) to development. The $14.4 million exploration program includes drilling up to six wells in the Eastern Desert, two Boraq wells (one new drill and one re-entry) at South Alamein and a large (600 km²) 3-D seismic acquisition program at NW Sitra in the Western Desert. The $11.4 million 2017 development program includes one development well in the West Bakr K-South field, and development/maintenance projects at West Gharib, West Bakr and NW Gharib.
The $14.4 million Egypt contingent program has $2.0 million (14%) allocated to exploration and $12.2 million (86%) allocated to development. The program includes nine additional wells (two exploration and seven development) focused primarily in NW Gharib to appraise/develop the NW Gharib discoveries and to increase West Bakr production. The $14.4 million budget is contingent upon timing of cargo/inventory sales, oil prices and drilling results in the first half of the year.
Canada
The $9.4 million (C$12.5 million) Canada firm program consists of four horizontal (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan and additional maintenance/development capital for potential workover/refracs. The initial Cardium well program is designed to provide a current benchmark for well costs and improved frac design/performance in the Harmattan area (no drilling has been conducted on the acquired lands since 2013). Based on historical offset wells and third party engineering estimates, it is expected that the horizontal wells will cost approximately $2.0 million (C$2.7 million) per well targeting a one mile lateral with approximately 600 tonnes of sand (30 stages) per well. It is expected that drilling will commence in the third quarter with all wells completed and on production prior to year-end to provide updated information for 2017 year-end reserves.
The $6.8 million (C$9.0 million) Canada contingent program consists of an additional four horizontal wells in the Harmattan area, to accelerate production growth in the Canadian operations. The $6.8 million budget is contingent on results of the initial drilling program and commodity prices.
The 2017 capital program is summarized in the following table:
 
 
TransGlobe 2017 Firm & Contingent Capital ($MM)
 
 
 
Gross Well Count
 
 
Development
 
Exploration
 
Total
 
(Wells)
Concession
 
Wells
 
Maint
 
Projects
 
Wells
 
Bonus
 
Seismic
 
 
Devel
 
Explor
 
Total
West Gharib
 
2.4
 
1.3
 
2.6
 
—
 
—
 
—
 
6.3
 
—
 
—
 
—
West Bakr
 
6.7
 
1.0
 
2.1
 
—
 
—
 
—
 
9.8
 
2
 
—
 
2
NW Gharib
 
7.6
 
—
 
—
 
6.9
 
0.1
 
—
 
14.6
 
6
 
8
 
14
SW Gharib
 
—
 
—
 
—
 
1.2
 
0.2
 
—
 
1.4
 
—
 
1
 
1
South Alamein
 
—
 
—
 
—
 
3.1
 
0.6
 
—
 
3.7
 
—
 
1
 
1
South Ghazalat
 
—
 
—
 
—
 
—
 
0.2
 
—
 
0.2
 
—
 
—
 
—
NW Sitra
 
—
 
—
 
—
 
—
 
0.2
 
4.0
 
4.2
 
—
 
—
 
—
Egypt
 
$16.7
 
$2.3
 
$4.7
 
$11.2
 
$1.3
 
$4.0
 
$40.2
 
8
 
10
 
18
Canada
 
$14.7
 
$1.5
 
—
 
—
 
—
 
—
 
$16.2
 
8
 
—
 
8
2017 Total
 
$31.4
 
$3.8
 
$4.7
 
$11.2
 
$1.3
 
$4.0
 
$56.4
 
16
 
10
 
26
Splits (%)
 
70%
 
30%
 
100%
 
62%
 
38%
 
100%




Q1-2017
 
11
 


NON-GAAP FINANCIAL MEASURES
Funds Flow from Operations
This document contains the term “funds flow from operations”, which should not be considered an alternative to or more meaningful than “cash flow from operating activities” as determined in accordance with IFRS. Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital. Management considers this a key measure as it demonstrates TransGlobe’s ability to generate the cash flow necessary to fund future growth through capital investment. Funds flow from operations does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.
Reconciliation of Funds Flow from Operations
 
 
Three months ended March 31
 
($000s)
 
2017

 
2016

Cash flow from operating activities
 
(2,497
)
 
1,426

Changes in non-cash working capital
 
4,999

 
(4,256
)
Funds flow from operations1
 
2,502

 
(2,830
)
Note:
 
 
 
 
   1  Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Condensed Consolidated Interim
     Statements of Earnings and Comprehensive Income. Cash interest paid is reported as a financing activity on the Condensed Consolidated Interim
     Statements of Cash Flows.
Debt-to-Funds Flow ratio
Debt-to-funds flow is a measure that is used to set the amount of capital in proportion to risk. The Company’s debt-to-funds flow ratio is computed as long-term debt, including the current portion, plus convertible debentures over funds flow from operations for the trailing twelve months. Debt-to-funds flow does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.
Netback
Netback is a measure that represents sales net of royalties (all government interests, net of income taxes), operating expenses, current taxes and selling costs. Management believes that netback is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.
TRANSGLOBE’S BUSINESS
TransGlobe is a Canadian-based, publicly-traded oil and gas exploration and development company whose activities are concentrated in two geographic areas: the Arab Republic of Egypt (“Egypt”) and Alberta, Canada.



12
 
Q1-2017
 

SELECTED QUARTERLY FINANCIAL INFORMATION
 
 
2017

 
2016
 
2015
($000s, except per share,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
price and volume amounts)
 
Q-1

 
Q-43

 
Q-3

 
Q-2

 
Q-1

 
Q-4

 
Q-3

 
Q-2

Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average production volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (bbls/d)
 
14,514

 
12,861

 
11,733

 
11,472

 
12,058

 
13,425

 
14,683

 
15,064

NGLs (bbls/d)
 
1,037

 
134

 
—

 
—

 
—

 
—

 
—

 
—

Natural gas (mcf/d)
 
7,075

 
916

 
—

 
—

 
—

 
—

 
—

 
—

Total (boe/d)
 
16,731

 
13,148

 
11,733

 
11,472

 
12,058

 
13,425

 
14,683

 
15,064

Average sales volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (bbls/d)
 
11,610

 
7,018

 
11,485

 
11,783

 
14,126

 
7,205

 
13,620

 
14,251

NGLs (bbls/d)
 
1,037

 
134

 
—

 
—

 
—

 
—

 
—

 
—

Natural gas (mcf/d)
 
7,075

 
916

 
—

 
—

 
—

 
—

 
—

 
—

Total (boe/d)
 
13,826

 
7,305

 
11,485

 
11,783

 
14,126

 
7,205

 
13,620

 
14,251

Average realized sales prices
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil ($/Bbl)
 
41.66

 
37.38

 
34.43

 
30.27

 
22.58

 
32.38

 
39.35

 
48.31

NGLs ($/Bbl)
 
19.08

 
12.33

 
—

 
—

 
—

 
—

 
—

 
—

Natural gas ($/Mcf)
 
1.96

 
1.80

 
—

 
—

 
—

 
—

 
—

 
—

Total oil equivalent ($/boe)
 
37.41

 
36.45

 
34.43

 
30.27

 
22.58

 
32.38

 
39.35

 
48.31

Inventory (Bbl)
 
1,528,295

 
1,265,080

 
729,403

 
706,577

 
734,872

 
923,106

 
350,869

 
253,325

Petroleum and natural gas sales
 
46,553

 
24,501

 
36,376

 
32,461

 
29,022

 
21,460

 
49,307

 
62,647

Petroleum and natural gas sales, net of royalties
 
22,461

 
5,217

 
20,704

 
19,786

 
17,427

 
3,979

 
24,700

 
33,960

Cash flow from operating activities
 
(2,497
)
 
6,355

 
(14,857
)
 
6,011

 
1,426

 
6,414

 
28,741

 
24,323

Funds flow from operations1
 
2,502

 
(9,904
)
 
2,347

 
2,026

 
(2,830
)
 
(11,108
)
 
(1,497
)
 
6,991

Funds flow from operations per share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
- Basic
 
0.03

 
(0.14
)
 
0.03

 
0.03

 
(0.04
)
 
(0.15
)
 
(0.02
)
 
0.09

- Diluted
 
0.03

 
(0.14
)
 
0.03

 
0.03

 
(0.04
)
 
(0.15
)
 
(0.02
)
 
0.09

Net earnings (loss)
 
(12,877
)
 
(33,997
)
 
(25,369
)
 
(12,050
)
 
(16,249
)
 
(35,255
)
 
(46,568
)
 
(12,580
)
Net earnings (loss) - diluted
 
(12,877
)
 
(38,641
)
 
(25,369
)
 
(12,050
)
 
(16,249
)
 
(35,255
)
 
(54,159
)
 
(12,580
)
Net earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
- Basic
 
(0.18
)
 
(0.47
)
 
(0.35
)
 
(0.17
)
 
(0.23
)
 
(0.49
)
 
(0.64
)
 
(0.17
)
- Diluted
 
(0.18
)
 
(0.49
)
 
(0.35
)
 
(0.17
)
 
(0.23
)
 
(0.49
)
 
(0.68
)
 
(0.17
)
Capital expenditures
 
10,718

 
8,863

 
8,692

 
4,838

 
4,265

 
4,877

 
3,587

 
22,337

Dividends paid
 
—

 
—

 
—

 
—

 
—

 
1,805

 
3,594

 
3,703

Dividends paid per share
 
—

 
—

 
—

 
—

 
—

 
0.025

 
0.05

 
0.05

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
403,686

 
406,142

 
414,363

 
433,013

 
441,624

 
455,500

 
501,808

 
599,744

Cash and cash equivalents
 
21,324

 
31,468

 
100,405

 
124,308

 
122,031

 
126,910

 
126,874

 
122,961

Convertible debentures
 
—

 
72,655

 
74,854

 
70,639

 
66,506

 
63,848

 
65,682

 
74,421

Note payable
 
11,259

 
11,162

 
—

 
—

 
—

 
—

 
—

 
—

Total long-term debt, including
     current portion
 
73,549

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Debt-to-funds flow ratio2
 
(28.0
)
 
(10.0
)
 
(7.8
)
 
(5.3
)
 
(7.9
)
 
(7.2
)
 
3.6

 
1.5

  1 Funds flow from operations 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  Debt-to-funds flow ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
  3  The Q4-2016 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.
During the first quarter of 2017, TransGlobe:
•
Reported positive working capital of $42.8 million (including $21.3 million in cash and cash equivalents) at March 31, 2017;
•
Reported a net loss of $12.9 million , which includes a $1.2 million non-cash impairment loss on the Company's exploration and evaluation assets at SW Gharib and a $3.7 million unrealized derivative loss on commodity contracts (mark-to-market loss on the Company's hedging contracts). The Company's SW Gharib exploration and evaluation assets were written down to nil as no commercially viable quantities of oil have been discovered on these lands;
•
Experienced a 60% increase in petroleum and natural gas sales compared to Q1-2016, which was principally due to a 66% increase in realized prices and the addition of sales from the recently acquired Canadian assets of $5.5 million. Realized pricing for the Company's petroleum and natural gas products are market driven;

Q1-2017
 
13
 

•
Recorded positive funds flow from operations of $2.5 million compared with negative funds flow of $2.8 million in Q1-2016. The increase is primarily the result of a 66% increase in realized oil prices combined with a 23% reduction in operating costs. These positive variances were partially offset by an increase to royalties and current income taxes of $14.7 million;
•
Reported a 39% increase in production volumes as compared to Q1-2016, which translates into an additional 4,673 boepd. The recently acquired Canadian assets contributed 2,782 boepd of additional production, and increased Egypt production accounted for the remaining variance. The increased Egypt production was the result of the production recovery plan undertaken in the second half of 2016, along with the first full quarter of production from NW Gharib, which contributed 982 bopd.
•
Repaid $73.4 million (C$97.8 million) convertible debentures on March 31, 2017 with the proceeds from the prepayment agreement;
•
Sold 303,817 barrels of inventoried entitlement crude oil to EGPC, resulting in a build in crude oil inventory of 0.3 million barrels; and
•
Spent $10.7 million on capital programs, which was funded entirely with funds flow and cash on hand.



14
 
Q1-2017
 


2017 TO 2016 NET EARNINGS VARIANCES
 
 
 
 
$ Per Share

 
 
 
 
$000s

 
Diluted

 
% Variance

Q1-2016 net earnings (loss)
 
(16,249
)
 
(0.23
)
 

Cash items
 

 

 

Volume variance
 
(1,536
)
 
(0.02
)
 
9

Price variance
 
19,065

 
0.26

 
(117
)
Royalties
 
(12,496
)
 
(0.17
)
 
77

Expenses:
 
 
 
 
 
 
Production and operating
 
2,998

 
0.04

 
(18
)
Transportation
 
(198
)
 
—

 
1

Selling costs
 
828

 
0.01

 
(5
)
Cash general and administrative
 
(1,111
)
 
(0.02
)
 
7

Current income taxes
 
(2,245
)
 
(0.03
)
 
14

Realized foreign exchange gain (loss)
 
(20
)
 
—

 
—

Realized derivative gain (loss)
 
258

 
—

 
(2
)
Interest on long-term debt
 
(227
)
 
—

 
1

Other income
 
(212
)
 
—

 
1

Total cash items variance
 
5,104

 
0.07

 
(32
)
Non-cash items
 
 
 
 
 
 
Unrealized derivative loss
 
(3,729
)
 
(0.05
)
 
23

Unrealized foreign exchange gain (loss)
 
5,426

 
0.08

 
(33
)
Depletion and depreciation
 
1,504

 
0.02

 
(9
)
Asset retirement obligation accretion
 
(60
)
 
—

 
—

Unrealized gain (loss) on financial instruments
 
(1,782
)
 
(0.02
)
 
11

Impairment loss
 
(1,191
)
 
(0.02
)
 
7

Stock-based compensation
 
193

 
—

 
(1
)
Deferred income taxes
 
(2,197
)
 
(0.03
)
 
14

Deferred lease inducement
 
(5
)
 
—

 
—

Amortization of deferred financing costs
 
109

 
—

 
(1
)
Total non-cash items variance
 
(1,732
)
 
(0.02
)
 
11

Q1-2017 net earnings (loss)
 
(12,877
)
 
(0.18
)
 
(21
)
TransGlobe recorded a net loss of $12.9 million in Q1-2017 compared to a net loss of $16.2 million in Q1-2016. The average realized sales price in Q1-2017 was $37.41 per boe, versus $22.58 per bbl in the same period of the prior year. This 66% increase resulted in a positive cash variance of $19.1 million, which was the single largest earnings variance item. The positive sales price variance was partially offset by increased royalties and current income taxes, which created a negative earnings variance of $14.7 million in aggregate. The Company achieved cost reductions of $3.0 million on operating expenses in Q1-2017, which was primarily as a result of a decrease in oil treating fees, fuel costs and well services in Egypt, along with the impact of the devaluation of the Egyptian pound. Cash general and administrative expenses increased in Q1-2017 compared to Q1-2016, resulting in a negative earnings variance of $1.1 million. This increase was principally due to staffing alignment expenditures, along with staff additions associated with the Canadian acquisition in December 2016. The Company did not have a cargo lifting to sell TransGlobe's entitlement crude oil in Egypt in Q1-2017, resulting in no selling costs during the period. In Q1-2016, the Company completed one cargo lifting in Egypt, resulting in selling costs of $0.8 million.
The largest non-cash earnings variance item in Q1-2017 compared to Q1-2016 relates to the unrealized foreign exchange gain/loss. The fluctuation is mainly the result of a significant foreign exchange loss on the convertible debentures in Q1-2016 ($4.3 million). The convertible debentures were repaid during the first quarter of 2017. A reduction in future development costs of 38% created a lower depletable cost base and therefore lower depletion expense, resulting in a $1.5 million positive earnings variance for Q1-2017. The largest non-cash negative earnings variance in Q1-2017 compared to Q1-2016 related to the unrealized derivative loss on commodity contracts recorded in Q1-2017. The Company recorded a $3.7 million non-cash loss on its outstanding hedging contracts as at March 31, 2017, which was a result of marking the contracts to their respective market values. In Q1-2016, there were no such contracts outstanding. The mark-to-market adjustment on the convertible debentures created a negative earnings swing of $1.7 million, while a further $1.2 million negative variance was caused by a impairment loss recorded on the Company's exploration and evaluation assets at South West Gharib.


Q1-2017
 
15
 

BUSINESS ENVIRONMENT
The Company’s financial results are influenced by fluctuations in commodity prices, including price differentials. The following table shows select market benchmark prices and foreign exchange rates:
 Average reference prices
 
2017

 
2016
 
 
Q-1

 
Q-4

 
Q-3

 
Q-2

 
Q-1

Crude oil
 
 
 
 
 
 
 
 
 
 
Dated Brent average oil price (US$/Bbl)
 
53.68

 
49.19

 
45.79

 
45.52

 
33.70

Edmonton Sweet index (US$/bbl)
 
48.37

 
46.18

 
41.99

 
42.51

 
29.76

Natural gas
 
 
 
 
 
 
 
 
 
 
AECO (C$/mmbtu)
 
2.69

 
3.09

 
2.32

 
1.40

 
1.83

U.S./Canadian Dollar average exchange rate
 
1.323

 
1.334

 
1.305

 
1.289

 
1.375


The price of Dated Brent oil averaged 9% higher in Q1-2017 compared with Q4-2016. Egypt production is priced based on Dated Brent and shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total revenue. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSC, the Contractor's share of excess ranges between 0% and 30%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost recovery or cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (production sharing oil). Depending on the contract, the Egyptian government receives 70% to 86% of the production sharing oil or profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of production sharing oil increases when production exceeds pre-set production levels in the respective contracts. During times of increased oil prices, the Company receives less cost oil and may receive more production sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. For reporting purposes, the Company records the government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production) which will increase during times of rising oil prices and will decrease in times of declining oil prices. If oil prices are sufficiently low and the Ras Gharib/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSC and any eligible extension periods.
Egypt has been experiencing significant political changes over the past six years. While this has had an impact on the efficient operations of the government in general, business processes and the Company’s drilling and field operations have generally proceeded as normal. While exploration and development activities have generally been uninterrupted, the Company experienced delays in the collection of accounts receivable from the Egyptian government up to the end of 2013. Since the end of 2013, the Company has collected a total of $344.1 million from EGPC, reducing the balance due from EGPC to $18.6 million as at March 31, 2017. The Company's credit risk, as it relates to accounts receivable from EGPC, has now been reduced due to the significant collections from EGPC. EGPC owns the storage and export facilities where the Company's inventory is delivered, and the Company requires EGPC approval to schedule liftings. Once liftings are approved and scheduled, the Company now enjoys a 30-day collection cycle as a result of direct marketing to third party international buyers who are generally required to post irrevocable letters of credit to support the sales prior to the cargo liftings.
On December 20, 2016, the Company acquired producing oil and gas assets in the Harmattan area of west central Alberta, Canada. The Harmattan acquisition provides the Company with a meaningful re-entry into Canada with concentrated, high working interest assets in proven, low risk development light oil and liquid-rich gas play types. The acquisition provides ample drilling locations and running room to increase reserves and production through horizontal drilling and multi-stage frac technology. The Harmattan acquisition meets the Company's strategy to diversify and expand operations into lower political risk OECD countries with attractive netbacks to support growth in the current oil price environment and plays to the Company's core strength of value creation through development drilling and reservoir management.
The price of Edmonton Sweet index oil averaged 5% higher in Q1-2017 compared with Q4-2016. The price of AECO averaged 13% lower in Q1-2017 compared with Q4-2016.


16
 
Q1-2017
 

OPERATING RESULTS AND NETBACK
Daily Volumes, Working Interest before Royalties (Boepd)
Production Volumes
 
 
Three months ended March 31
 
 
 
2017

 
2016

Egypt crude oil (bbls/d)
 
13,948

 
12,058

Canada crude oil (bbls/d)
 
566

 
—

Canada natural gas (mcf/d)
 
7,075

 
—

Canada NGLs (bbls/d)
 
1,037

 
—

Total Company (boe/d)
 
16,731

 
12,058


Sales Volumes (excludes volumes held as inventory)
 
 
Three months ended March 31
 
 
 
2017

 
2016

Egypt crude oil (bbls/d)
 
11,044

 
14,126

Canada crude oil (bbls/d)
 
566

 
—

Canada natural gas (mcf/d)
 
7,075

 
—

Canada NGLs (bbls/d)
 
1,037

 
—

Total Company (boe/d)
 
13,826

 
14,126


Netback
Consolidated netback
 
 
 
 
 
 
 
 
 
 
Three months ended March 31
 
 
2017
 
2016
(000s, except per Boe amounts)1
 
$

 
$/Boe

 
$

 
$/Bbl

Petroleum and natural gas sales
 
46,553

 
37.41

 
29,022

 
22.58

Royalties and other
 
24,092

 
19.36

 
11,595

 
9.02

Current taxes
 
5,420

 
4.36

 
3,175

 
2.47

Production and operating expenses
 
10,123

 
8.14

 
13,121

 
10.21

Transportation
 
198

 
0.16

 
—

 
—

Selling costs
 
—

 
—

 
828

 
0.64

Netback
 
6,720

 
5.39

 
303

 
0.24

1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended March 31, 2017 and March 31, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at March 31, 2017).
Canada
 
 
 
 
 
 
 
 
 
 
Three months ended March 31
 
 
2017
 
2016
(000s, except per Boe amounts)
 
$

 
$/Boe

 
$

 
$/Boe

Crude oil sales
 
2,487

 
48.82

 
—

 
—

Natural gas sales
 
1,245

 
11.73

 
—

 
—

NGL sales
 
1,781

 
19.08

 
—

 
—

Total sales
 
5,513

 
22.02

 


 


Royalties
 
1,177

 
4.70

 
—

 
—

Production and operating expenses
 
1,577

 
6.30

 
—

 
—

Transportation
 
198

 
0.79

 
—

 
—

Netback
 
2,561

 
10.23

 
—

 
—

The Canadian financial information presented in the table above represents the first full quarter activity in for the Company's newly acquired Canadian assets.
Netbacks in Canada were $10.23 per Boe for the first quarter of 2017, which represents an increase of $3.60 per Boe as compared to the 12-day period that TransGlobe owned the Canadian assets in 2016. This increase is mainly due to an increase in realized sales prices of $2.90 per Boe combined with a 17% decrease in production and operating expenses on a per Boe basis.
TransGlobe pays royalties to the Alberta provincial governments and landowners in accordance with the 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 usually have a finite period of time and are in place to promote drilling activity by reducing overall royalty expense.

Q1-2017
 
17
 

For the three months ended March 31, 2017, the Company incurred $1.2 million in royalty costs. Royalties amounted to 22% of petroleum and natural gas sales revenue in the three months ended March 31, 2017.
Egypt
 
 
 
 
 
 
 
 
 
 
Three months ended March 31
 
 
2017
 
2016
(000s, except per Bbl amounts)1
 
$

 
$/Bbl

 
$

 
$/Bbl

Oil sales
 
41,040

 
41.29

 
29,022

 
22.58

Royalties
 
22,915

 
23.05

 
11,595

 
9.02

Current taxes
 
5,420

 
5.45

 
3,175

 
2.47

Production and operating expenses
 
8,546

 
8.60

 
13,121

 
10.21

Selling costs
 
—

 
—

 
828

 
0.64

Netback
 
4,159

 
4.19

 
303

 
0.24

1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended March 31, 2017 and March 31, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at March 31, 2017).
Netbacks in Egypt increased by $3.95 per Bbl in Q1-2017 compared with Q1-2016. The increased netback was principally the result of an 83% increase in realized oil prices in Q1-2017 compared to Q1-2016.
Production and operating expenses decreased by $4.6 million in Q1-2017 compared with Q1-2016. This is principally the result of lower sales volumes in Q1-2017, causing more operating costs to be capitalized as crude oil inventory in the period. On a per Bbl basis, production and operating costs have decreased by 16% in Q1-2017 compared with Q1-2016. The most significant cost efficiencies were achieved in the areas of labour costs and equipment rentals. The devaluation of the Egyptian pound also had a significant positive impact on operating expenses in the quarter. The Company did not incur selling costs in Q1-2017 as all entitlement oil sold was purchased by EGPC.
Royalties and taxes as a percentage of revenue increased from 51% in Q1-2016 to 69% in Q1-2017. 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 entitlement oil sales. If sales volumes had been equal to production volumes in Q1-2017, the Q1-2017 royalties and taxes as a percentage of revenue would have been 55%. In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of the PSCs dictate. In periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower than the terms of the PSCs dictate.
The average selling price in Q1-2017 was $41.29/Bbl, which was $12.39/Bbl lower than the average Dated Brent oil price of $53.68/Bbl for the period (March 31, 2016 - $33.70/Bbl). The difference is due to a gravity/quality adjustment and is also impacted by the timing of direct sales.
GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)
 
 
Three months ended March 31
 
 
2017
 
 
2016
 
(000s, except Boe amounts)
 
$

 
$/Boe

 
$

 
$/Boe

G&A (gross)
 
4,749

 
3.82

 
4,132

 
3.21

Stock-based compensation
 
229

 
0.18

 
422

 
0.33

Capitalized G&A and overhead recoveries
 
(532
)
 
(0.43
)
 
(1,031
)
 
(0.80
)
G&A (net)
 
4,446

 
3.57

 
3,523

 
2.74

G&A expenses (net) increased 26% in Q1-2017 compared with Q1-2016 (30% on a per boe basis). G&A (gross) was elevated in Q1-2017 primarily due to staffing alignment expenditures incurred in the first quarter, along with staff additions associated with the Canadian acquisition in December 2016.
Capitalized G&A decreased 48% in Q1-2017 compared with Q1-2016 (46% on a per boe basis). In 2016, the Company's capital spending commitments in Egypt were secured by letters of credit drawn on the Company's borrowing base facility. Banking fees associated with these letters of credit in the amount of $0.4 million were capitalized in Q1-2016. In December 2016 the Company terminated its borrowing base facility, and the spending commitments are now secured by a cash collateralized letter of credit facility.

FINANCE COSTS
Finance costs for the three-month period ended March 31, 2017 increased to $1.5 million compared with $1.4 million in the same period in 2016.
 
 
Three months ended March 31
 
(000s)
 
2017

 
2016

Convertible debentures
 
$
1,089

 
$
1,053

Long-term debt
 
128

 
—

Note payable
 
282

 
—

Borrowing base facility
 
—

 
218

Amortization of deferred financing costs
 
49

 
158

Finance costs
 
$
1,548

 
$
1,429


18
 
Q1-2017
 

Convertible Debentures
Interest expense on the convertible debentures for the three-month period ended March 31, 2017 was $1.1 million (Q1-2016 - $1.1 million). Interest on the convertible debentures is paid in Canadian dollars, and and therefore fluctuates from period to period depending on the strength of the Canadian dollar relative to the US dollar. The convertible debentures outstanding at December 31, 2016 were repaid in full on March 31, 2017 using the proceeds of the prepayment agreement.
Prepayment Agreement
On February 10, 2017, the Company completed a $75 million crude oil prepayment agreement between its wholly owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria Energy Trading SA ("Mercuria") of Geneva, Switzerland.
TPI's obligations under the prepayment agreement are guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. The funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of Libor plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75 million and subject to compliance with the other terms and conditions of the prepayment agreement. The prepayment agreement was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. The prepayment agreement is classified as long-term debt in the Company's financial statements. Financing costs of $1.5 million will be amortized over the term of the prepayment agreement using the effective interest rate method.
The prepayment agreement is subject to certain covenants, the details of which are outlined in Note 12 to the Company's Condensed Consolidated Interim Financial Statements.
Note Payable
On December 20, 2016, the Company closed the acquisition of the Harmattan petroleum properties in west central Alberta, Canada. The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.2 million). The note payable has a 24-month term and bears interest at a rate of 10% per annum. Principal repayments must be made on a quarterly basis, and must be equal to or greater than 50% of the net operating income of the acquired assets. The first principal payment was made on May 1, 2017.
DEPLETION AND DEPRECIATION (“DD&A”)
 
 
Three months ended March 31
 
 
2017
 
 
2016
 
(000s, except per Bbl amounts)
 
$

 
$/Bbl

 
$

 
$/Bbl

Egypt
 
6,114

 
6.15

 
9,894

 
7.70

Canada
 
2,302

 
9.19

 
—

 
—

Corporate
 
96

 
—

 
122

 
—

 
 
8,512

 
6.84

 
10,016

 
7.79

In Egypt, DD&A decreased 20% on a per Bbl basis in the three months ended March 31, 2017 compared to the same period in 2016. The decrease is primarily related to a lower depletable cost base, which is the result of a 38% reduction in future development costs.
In Canada, DD&A was $9.19 per Bbl in the three months ended March 31, 2017, which was consistent with the DD&A rate for the 12 day period ended December 31, 2016 after the closing of the Canadian asset acquisition.
IMPAIRMENT LOSS
The Company recorded an non-cash impairment loss of $1.2 million on its exploration and evaluation assets during the first quarter of 2017. The impairment related to the South West Gharib concession in Egypt and represents the entire intangible exploration and evaluation asset balance at South West Gharib as at March 31, 2017. It was determined that an impairment loss was necessary as no commercially viable quantities of oil were discovered at South West Gharib, and no further drilling activities are planned.
CAPITAL EXPENDITURES
 
 
Three months ended March 31
 
($000s)
 
2017

 
2016

Egypt
 
10,670

 
4,265

Canada
 
48

 
—

Total
 
10,718

 
4,265

In Egypt, total capital expenditures in Q1-2017 were $10.7 million (2016 - $4.3 million). During the first quarter, the Company drilled six exploration wells and one development well. Four wells were drilled at NW Gharib resulting in two oil discoveries (NWG 26 and NWG 27) and two dry holes (NWG 39 and NWG 42). At SW Gharib the Company drilled two exploration wells, both of which were dry and abandoned. At West Gharib, the second of two infill development oil wells in the Arta Red Bed pool was drilled. Total capitalized drilling costs in the quarter amounted to $6.1 million.
The Company also spent $4.1 million on seismic acquisition at NW Sitra during the quarter, and capitalized $0.5 million of G&A costs related to capital projects.

Q1-2017
 
19
 

OUTSTANDING SHARE DATA
As at March 31, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,278,153 stock options issued and outstanding, which are exercisable in accordance with their terms into an equal number of common shares of the Company.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and reserves, to acquire strategic oil and gas assets and to repay current liabilities and debt. TransGlobe’s capital programs are funded by its existing working capital and cash provided from operating activities. As a direct result of a continued lower oil price environment, TransGlobe’s debt-to-funds flow from operations ratio has significantly deteriorated and was negative 28.0 at March 31, 2017 (December 31, 2016 - negative 10.0) as a result of negative funds flow for the trailing 12 months. The Company's funds flow from operations varies significantly from quarter to quarter depending on the timing of tanker liftings, and these fluctuations in funds flow impact the Company's debt-to-funds flow from operations ratio. TransGlobe's management will continue to steward capital programs and focus on cost reductions in order to maintain balance sheet strength through the current low oil price environment.
The following table illustrates TransGlobe’s sources and uses of cash during the periods ended March 31, 2017 and 2016:
Sources and Uses of Cash
 
 
 
 
 
 
Three months ended March 31
 
($000s)
 
2017

 
2016

Cash sourced
 

 

Funds flow from operations1
 
2,502

 
(2,830
)
Transfer from restricted cash
 
1,950

 
—

Increase in long-term debt
 
75,000

 
—

Other
 
235

 
—

 
 
79,687

 
(2,830
)
Cash used
 
 
 
 
Capital expenditures
 
10,718

 
4,265

Deferred financing costs
 
1,500

 
—

Transfer to restricted cash
 
—

 
1

Repayment of convertible debentures
 
73,375

 
—

Finance costs
 
2,191

 
2,347

Other
 
—

 
906

 
 
87,784

 
7,519

 
 
(8,097
)
 
(10,349
)
Changes in non-cash working capital
 
(2,047
)
 
5,470

Increase (decrease) in cash and cash equivalents
 
(10,144
)
 
(4,879
)
Cash and cash equivalents – beginning of period
 
31,468

 
126,910

Cash and cash equivalents – end of period
 
21,324

 
122,031

Note:
  1  Funds flow from operations 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.
Funding for the Company’s capital expenditures was provided by funds flow from operations and cash on hand. The Company expects to fund its 2017 exploration and development program of $56.4 million, including contractual commitments, through the use of working capital and funds flow from operations. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources and capital expenditures.
Working capital is the amount by which current assets exceed current liabilities. At March 31, 2017, the Company had a working capital surplus of $42.8 million (December 31, 2016 - deficiency of $16.8 million). The increase to working capital in Q1-2017 is principally due to the repayment of the convertible debt, which was a current liability at year-end 2016, using the proceeds from the prepayment agreement as at March 31, 2017. The Company's working capital continues to be negatively impacted by low oil prices.
The Company now has a receivable balance of $18.6 million due from EGPC. During the first quarter of 2017, the Company sold 303,817 barrels of inventoried entitlement crude oil to EGPC for $12.7 million to cover in-country expenditures for Q1/Q2. As at March 31, 2017 the Company had collected $6.7 million of the $12.7 million in sales to EGPC. Accounts receivable offsets with local operational expenditures totaled $4.7 million and cash collections accounted for $2.9 million. Subsequent to the quarter the Company collected an additional $3.0 million in the form of accounts receivable offsets and $0.5 million in cash from EGPC.
The Company repaid its convertible debentures in full on March 31, 2017, which was the maturity date of the debentures. The convertible debentures were denominated in Canadian dollars, and the aggregate face value of all outstanding convertible debentures was C$97.8 million ($73.4 million). The repayment was made using the funds received by drawing on the $75 million prepayment agreement with Mercuria.
As at March 31, 2017, the Company had restricted cash of $16.4 million (December 31, 2016 - $18.3 million). Restricted cash represents a cash collateralized letter of credit facility that is used to guarantee the Company's commitments on its Egyptian exploration concessions.
The Company has advanced discussions with a Canadian based lender to establish a Canadian borrowing base for capital and operations in Alberta. Upon completion, the facility would initially be used to repay the existing C$15 million vendor-take-back loan outstanding.

20
 
Q1-2017
 

PRODUCT INVENTORY
Product inventory consists of the Company's Egypt entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold entitlement crude oil as determined on a concession by concession basis. All oil produced is delivered to EGPC facilities, and EGPC also owns the storage and export facilities where the Company's product inventory is sold from. The Company requires EGPC approval to schedule liftings and works with EGPC on a continuous basis to schedule tanker liftings. Crude oil inventory levels fluctuate from quarter to quarter depending on EGPC approvals granted and the timing and size of tanker liftings in Egypt. As at March 31, 2017, the Company had 1,528,295 barrels of entitlement oil as inventory, which represents approximately eight months of entitlement oil production. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from quarter to quarter. Throughout 2015 there was a steady increase in crude oil inventory levels, as production outpaced sales. In Q1-2016 and Q2-2016, crude oil inventory levels dropped as a result of crude oil sales being greater than our production. During the second half of 2016 and Q1-2017, crude oil inventory levels once again grew as production was greater than sales. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows. The Company expects to complete both external sales (tanker liftings) and internal sales to EGPC in 2017, and anticipates that 2017 year-end crude oil inventory will be less than 1 million barrels, subject to the current tanker lifting schedule. Three tanker liftings are currently scheduled in 2017, with expected total shipment volumes of 1.5 to 1.6 MMBbl.
 
 
Three months ended

 
Year ended

(bbls)
 
March 31, 2017

 
December 31, 2016

Product inventory, beginning of period
 
1,265,080

 
923,106

TransGlobe entitlement production
 
567,032

 
2,036,483

Tanker liftings
 
—

 
(1,694,509
)
EGPC sales
 
(303,817
)
 
—

Product inventory, end of period
 
1,528,295

 
1,265,080


COMMITMENTS AND CONTINGENCIES
As part of its normal business, the Company entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity. The principal commitments of the Company are as follows:
($000s)
 
 
 
Payment Due by Period 1,2
 
 
Recognized
 
 
 
 
 
 
 
 
 
 
in Financial
 
Contractual

 
Less than

 
 

 
 

 
 
Statements
 
Cash Flows

 
1 year

 
1-3 years

 
4-5 years

Accounts payable and accrued
  liabilities
 
Yes - Liability
 
30,407

 
30,407

 
—

 
—

Long-term debt
 
Yes - Liability
 
75,000

 
—

 
24,966

 
50,034

Note payable
 
Yes - Liability
 
11,259

 
7,037

 
4,222

 
—

Financial derivative instruments
 
Yes - Liability
 
3,729

 
3,729

 
—

 
—

Office and equipment leases3
 
No
 
5,627

 
3,265

 
1,575

 
787

Minimum work commitments4
 
No
 
6,138

 
613

 
5,525

 
—

Total
 
 
 
132,160

 
45,051

 
36,288

 
50,821

Notes:
  1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
  2 Payments denominated in foreign currencies have been translated at March 31, 2017 exchange rates.
  3 Office and equipment leases includes all drilling rig contracts.
  4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.
The Company is subject to certain office and equipment leases.
Pursuant to the PSC for North West Gharib in Egypt, the Company had a minimum financial commitment of $35.0 million ($0.6 million remaining as at March 31, 2017) and a work commitment for 30 wells and 200 square kilometers of 3-D seismic during the initial-three year exploration period, which commenced on November 7, 2013. As at March 31, 2017, the Company had expended $34.4 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, extending the initial exploration period to May 7, 2017. Subsequent to the end of the first quarter, the Company completed the initial exploration period work program and met all financial commitments.
Pursuant to the PSC for South West Gharib in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for four wells and 200 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company received a six month extension, which extended the initial exploration period to May 7, 2017. Since no commercially viable quantities of oil have been discovered at South West Gharib, the Company relinquished its interest in the concession on May 7, 2017. The Company met its financial commitment during the first quarter of 2017.

Pursuant to the PSC for South Ghazalat in Egypt, the Company had a minimum financial commitment of $8.0 million and a work commitment for two wells and 400 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013 and reached its primary term on November 7, 2016. Prior to expiry, the Company elected to enter the first two-year extension period (expiry November 7, 2018). The Company had met its financial commitment for the first phase ($8.0 million) and the first extension ($4.0 million), however the Company had not completed the first phase work program. Prior to entering the first extension the Company posted a $4.0 million performance bond with EGPC to carry forward two exploration commitment wells into the first extension period. The $4.0 million performance bond is supported by a production guarantee from the Company's producing concessions which will be released when the commitment wells have been drilled. In

Q1-2017
 
21
 

accordance with the concession agreement the Company relinquished 25% of the original exploration acreage prior to entering the first extension period. In addition, the first extension period has an additional financial commitment of $4.0 million, which has been met, and two additional exploration wells.
Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($5.5 million remaining) and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three and a half year exploration period, which commenced on January 8, 2015. As at March 31, 2017, the Company had expended $4.5 million towards meeting that commitment.
In the normal course of its operations, the Company may be subject to litigations and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.
The Company is not aware of any material provisions or other contingent liabilities as at March 31, 2017.
ASSET RETIREMENT OBLIGATION
At March 31, 2017, TransGlobe recorded an asset retirement obligation ("ARO") of $12.3 million (December 31, 2016 - $12.1 million) for the future abandonment and reclamation costs associated with the Harmattan assets. The estimated ARO includes assumptions in respect of actual costs to abandon wells and/or reclaim the properties, the time frame in which such costs will be incurred, as well as annual inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 0.75% and 2.31% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates.
DERIVATIVE COMMODITY CONTRACTS
In conjunction with the recently executed prepayment agreement, TPI has also entered into a marketing contract with Mercuria to market nine million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale. In addition, in conjunction with the prepayment and marketing agreements, the Company committed to enter into hedging arrangements for 60% of its 1P forecasted entitlement production.
The nature of TransGlobe’s operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings at each reporting period. TransGlobe has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

There were three outstanding derivative commodity contracts as at March 31, 2017 (December 31, 2016 - nil), the fair values of which have been presented as liabilities on the Condensed Consolidated Interim Balance Sheet.
The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at March 31, 2017:
Financial BRENT Crude Oil Contracts
Term
 
Contract
 
Volume bbl
 
Sold Swap
US$/bbl
 
Bought Put
US$/bbl
 
Sold Call
US$/bbl
28-Mar-2017
 
31-Dec-2017
 
Collar
 
300,000
 
—
 
45.00
 
56.00
24-Mar-2017
 
30-Jun-2017
 
Swap
 
500,000
 
50.65
 
—
 
—
27-Mar-2017
 
30-Sep-2017
 
Swap
 
425,000
 
51.00
 
—
 
—

Subsequent to the first quarter, the Company entered into the following derivative commodity contract positions:
Financial BRENT Crude Oil Contracts
Term
 
Contract
 
Volume bbl
 
Bought Put
US$/bbl
 
Sold Call
US$/bbl
 
Sold Put
US$/bbl
7-Apr-2017
 
31-Mar-2018
 
3-Way Collar
 
250,000
 
53.00
 
61.15
 
44.00
13-Apr-2017
 
30-Jun-2018
 
3-Way Collar
 
250,000
 
54.00
 
63.10
 
45.00
13-Apr-2017
 
30-Sep-2018
 
3-Way Collar
 
250,000
 
54.00
 
64.15
 
45.00
13-Apr-2017
 
31-Dec-2018
 
3-Way Collar
 
250,000
 
54.00
 
65.45
 
45.00

The Company is required to enter into further hedges for 800,000 bbls in 2019 and 600,000 bbls in 2020 in accordance with the commitment to Mercuria.

22
 
Q1-2017
 


INTERNAL CONTROLS OVER FINANCIAL REPORTING
TransGlobe's management designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, of the Canadian Securities Administrators and as defined in Rule 13a-15 under the US Securities Exchange Act of 1934. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS, focusing in particular on controls over information contained in the annual and interim financial statements. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
No changes were made to the Company's internal control over financial reporting during the period ended March 31, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Q1-2017
 
23
 


Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss)
(Unaudited - Expressed in thousands of U.S. Dollars, except per share amounts)
 
 
 
 
Three months ended March 31
 
 
 
Notes
 
2017

 
2016

REVENUE
 
 
 
 
 
 
Petroleum and natural gas sales, net of royalties
 
4
 
$
22,461

 
$
17,427

Finance revenue
 

 
25

 
237

 
 
 
 
22,486

 
17,664

 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
Production and operating
 

 
10,123

 
13,121

Transportation costs
 

 
198

 
—

Selling costs
 

 
—

 
828

General and administrative
 

 
4,446

 
3,523

Foreign exchange (gain) loss
 

 
(15
)
 
5,391

Finance costs
 
5
 
1,548

 
1,429

Depletion, depreciation and amortization
 
10
 
8,512

 
10,016

Accretion
 
11
 
60

 
—

Realized derivative loss on commodity contracts
 

 
—

 
258

Unrealized derivative loss on commodity contracts
 
3
 
3,729

 
—

Unrealized (gain) loss on financial instruments
 
13
 
151

 
(1,631
)
Impairment of exploration and evaluation assets
 
9
 
1,191

 
—

 
 
 
 
29,943

 
32,935

 
 
 
 
 
 
 
Earnings (loss) before income taxes
 

 
(7,457
)
 
(15,271
)
 
 
 
 
 
 
 
Income tax expense (recovery) – current
 

 
5,420

 
3,175

– deferred
 

 
—

 
(2,197
)
 
 
 
 
5,420

 
978

NET EARNINGS (LOSS) FOR THE PERIOD
 
 
 
$
(12,877
)
 
$
(16,249
)
 
 
 
 
 
 
 
OTHER COMPREHENSIVE (LOSS) INCOME
 
 
 
 
 
 
Currency translation adjustments
 

 
(583
)
 
—

COMPREHENSIVE INCOME (LOSS) FOR THE PERIOD
 
 
 
$
(13,460
)
 
$
(16,249
)
 
 
 
 
 
 
 
Earnings (loss) per share
 

 
 
 
 
Basic
 
 
 
$
(0.18
)
 
$
(0.23
)
Diluted
 
 
 
$
(0.18
)
 
$
(0.23
)
See accompanying notes to the Condensed Consolidated Interim Financial Statements.

24
 
Q1-2017
 


Condensed Consolidated Interim Balance Sheets
(Unaudited - Expressed in thousands of U.S. Dollars)
 
 
 
 
As at

 
As at

 
 
Notes
 
March 31, 2017

 
December 31, 2016

ASSETS
 
 
 
 
 
 
Current
 
 
 
 

 
 

Cash and cash equivalents
 
6
 
$
21,324

 
$
31,468

Restricted cash
 
7
 
16,372

 
18,323

Accounts receivable
 

 
21,842

 
14,836

Prepaids and other
 

 
1,865

 
1,772

Product inventory
 
8
 
22,529

 
19,602

 
 
 
 
83,932

 
86,001

Non-Current
 
 
 
 
 
 

Intangible exploration and evaluation assets
 
9
 
115,126

 
105,869

Property and equipment
 

 


 


Petroleum and natural gas assets
 
10
 
200,684

 
210,027

Other assets
 
10
 
3,944

 
4,245

 
 
   
 
$
403,686

 
$
406,142

 
 
 
 
 
 
 
LIABILITIES
 
 
 
 
 
 

Current
 
 
 
 
 
 

Accounts payable and accrued liabilities
 

 
$
30,407

 
$
24,529

Convertible debentures
 
13
 
—

 
72,655

Derivative commodity contracts
 
3
 
3,729

 
—

Current portion of note payable
 
12
 
7,037

 
5,581

 
 
 
 
41,173

 
102,765

Non-Current
 
 
 
 
 
 

Note payable
 
12
 
4,222

 
5,581

Long-term debt
 
12
 
73,549

 
—

Asset retirement obligation
 
11
 
12,308

 
12,099

Other long-term liabilities
 

 
359

 
381

 
 
 
 
131,611

 
120,826

 
 
 
 
 
 
 
SHAREHOLDERS’ EQUITY
 
 
 
 
 
 

Share capital
 
15
 
152,084

 
152,084

Accumulated other comprehensive income
 

 
(583
)
 
—

Contributed surplus
 

 
22,914

 
22,695

Retained earnings
 

 
97,660

 
110,537

 
 
 
 
272,075

 
285,316

 
 
 
 
$
403,686

 
$
406,142

See accompanying notes to the Condensed Consolidated Interim Financial Statements.
Approved on behalf of the Board:
Signed by:
“Ross G. Clarkson”
“Fred J. Dyment”
 
 
Ross G. Clarkson
Fred J. Dyment
President and CEO
Director
Director
 



Q1-2017
 
25
 


Condensed Consolidated Interim Statement of Changes in Shareholders’ Equity
(Unaudited - Expressed in thousands of U.S. Dollars)
 
 
 
 
Three months ended March 31
 
 
 
Notes
 
2017

 
2016

 
 
 
 
 
 
 
Share Capital
 
 
 
 
 
 
Balance, beginning of period
 
15
 
$
152,084

 
$
152,084

Balance, end of period
 
 
 
$
152,084

 
$
152,084

 
 
 
 
 
 
 
Contributed Surplus
 
 
 
 
 
 
Balance, beginning of period
 

 
$
22,695

 
$
21,398

Share-based compensation expense
 
16
 
219

 
426

Balance, end of period
 
                       
 
$
22,914

 
$
21,824

 
 
 
 
 
 
 
Accumulated Other Comprehensive Income
 
 
 
 
 
 
Balance, beginning of period
 

 
$
—

 
$
—

Currency translation adjustment
 

 
(583
)
 
—

Balance, end of period
 
                       
 
$
(583
)
 
$
—

 
 
 
 
 
 
 
Retained Earnings
 
 
 
 
 
 
Balance, beginning of period
 

 
$
110,537

 
$
198,202

Net earnings (loss) and comprehensive income (loss)
 

 
(12,877
)
 
(16,249
)
Balance, end of period
 
 
 
$
97,660

 
$
181,953

See accompanying notes to the Condensed Consolidated Interim Financial Statements.


26
 
Q1-2017
 


Condensed Consolidated Interim Statements of Cash Flows
(Unaudited - Expressed in thousands of U.S. Dollars)
 
 
 
 
Three months ended March 31
 
 
 
Notes
 
2017

 
2016

CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING
 
 
 
 
 
 
Net earnings (loss) for the period
 

 
$
(12,877
)
 
$
(16,249
)
Adjustments for:
 

 

 

Depletion, depreciation and amortization
 
10
 
8,512

 
10,016

Accretion
 
11
 
60

 
—

Deferred lease inducement
 

 
(22
)
 
(27
)
Impairment of exploration and evaluation assets
 

 
1,191

 
—

Stock-based compensation
 
16
 
229

 
422

Finance costs
 
5
 
1,548

 
1,429

Income tax expense
 

 
5,420

 
978

Unrealized (gain) loss on commodity contracts
 
3
 
3,729

 
—

Unrealized (gain) loss on financial instruments
 
13
 
151

 
(1,631
)
Unrealized (gain) loss on foreign currency translation
 

 
(19
)
 
5,407

Income taxes paid
 

 
(5,420
)
 
(3,175
)
Changes in non-cash working capital
 
19
 
(4,999
)
 
4,256

Net cash generated by (used in) operating activities
 
 
 
(2,497
)
 
1,426

 
 
 
 
 
 
 
INVESTING
 
 
 
 
 
 
Additions to intangible exploration and evaluation assets
 
9
 
(10,448
)
 
(1,629
)
Additions to petroleum and natural gas assets
 
10
 
(194
)
 
(2,313
)
Additions to other assets
 
10
 
(76
)
 
(323
)
Changes in restricted cash
 
7
 
1,950

 
(1
)
Changes in non-cash working capital
 
19
 
2,952

 
1,214

Net cash generated by (used in) investing activities
 
 
 
(5,816
)
 
(3,052
)
 
 
 
 
 
 
 
FINANCING
 
 
 
 
 
 
Financing costs
 
5,12
 
(1,500
)
 
—

Interest paid
 

 
(2,191
)
 
(2,347
)
Increase in long-term debt
 
12
 
75,000

 
—

Repayment of convertible debentures
 

 
(73,375
)
 
—

Net cash generated by (used in) financing activities
 
 
 
(2,066
)
 
(2,347
)
Currency translation differences relating to cash and cash equivalents
 
 
 
235

 
(906
)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
 
 
 
(10,144
)
 
(4,879
)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
 
 
 
31,468

 
126,910

CASH AND CASH EQUIVALENTS, END OF PERIOD
 
 
 
$
21,324

 
$
122,031

See accompanying notes to the Condensed Consolidated Interim Financial Statements.


Q1-2017
 
27
 

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
As at March 31, 2017 and December 31, 2016 and for the periods ended March 31, 2017 and 2016
(Unaudited - Expressed in U.S. Dollars)
1. CORPORATE INFORMATION
TransGlobe Energy Corporation is a publicly listed company incorporated in Alberta, Canada and its shares are listed on the Toronto Stock Exchange (“TSX”) and the Global Select Market of the NASDAQ Stock Market (“NASDAQ”). The address of its registered office is 2300, 250 – 5th Street SW, Calgary, Alberta, Canada, T2P 0R4. TransGlobe together with its subsidiaries ("TransGlobe" or the "Company") is engaged primarily in oil and gas exploration, development and production and the acquisition of properties.
2. BASIS OF PREPARATION
Statement of compliance
These Condensed Consolidated Interim Financial Statements have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board effective as of March 31, 2017. These Condensed Consolidated Interim Financial Statements do not contain all the disclosures required for full annual financial statements and should be read in conjunction with the December 31, 2016 Consolidated Financial Statements.
These Condensed Consolidated Interim Financial Statements were authorized for issue by the Board of Directors on May 9, 2017.
Basis of measurement
The accounting policies used in the preparation of these Condensed Consolidated Interim Financial Statements were the same as those used in the preparation of the most recent Annual Financial Statements for the year ended December 31, 2016, with the exception of the change in functional currency of TransGlobe Energy Corporation, as described below.
The Company prepared these Condensed Consolidated Interim Financial Statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. Accordingly, these Condensed Consolidated Interim Financial Statements have been prepared on a historical cost basis, except for cash and cash equivalents that have been measured at fair value.
Functional and presentation currency
In these Condensed Consolidated Interim Financial Statements, unless otherwise indicated, all dollar amounts are presented and expressed in United States (U.S.) dollars. All references to $ are to United States dollars and references to C$ are to Canadian dollars and all values are rounded to the nearest thousand except when otherwise indicated.
Effective January 1, 2017, TransGlobe Energy Corporation's functional currency is the Canadian dollar, and the functional currency of all subsidiaries is the U.S. dollar. It was determined that TransGlobe Energy Corporation's functional currency is now the Canadian dollar mainly because the parent company now owns Canadian producing assets, and therefore generates revenues and incurs costs that are denominated predominantly in Canadian dollars.
Foreign currency translations include the translation of foreign currency transactions and the translation of the Canadian functional currency operation. Foreign currency translations occur when translating transactions in foreign currencies to the applicable functional currency of TransGlobe Energy Corporation and its subsidiaries. Gains and losses from foreign currency transactions are recorded as foreign exchange gains or losses. Translations occur as follows:
• Income and expenses are translated at the prevailing rates on the date of the transaction
• Non-monetary assets or liabilities are carried at the prevailing rates on the date of the transaction
• Monetary items are translated at the prevailing rates at the balance sheet date
Canadian operation translation gains and losses occur when translating the financial statements of TransGlobe Energy Corporation (non-U.S. functional currency) to the U.S. dollar. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss). Translations occur as follows:
• Income and expenses are translated at the average exchange rates for the period
• Assets and liabilities are translated at the prevailing rates on the balance sheet date
3. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Fair Values of Financial Instruments
The Company has classified its cash and cash equivalents as assets at fair value through profit or loss, its convertible debentures and derivative commodity contracts as financial liabilities at fair value through profit or loss, which are both measured at fair value with changes being recognized through earnings. Accounts receivable and restricted cash are classified as loans and receivables; accounts payable and accrued liabilities, long-term debt and note payable are classified as other liabilities, all of which are measured initially at fair value, then at amortized cost after initial recognition. Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument using the effective interest rate method.

28
 
Q1-2017
 

Carrying value and fair value of financial assets and liabilities are summarized as follows:
 
 
March 31, 2017
 
December 31, 2016
 
 
Carrying

 
Fair

 
Carrying

 
Fair

Classification (000s)
 
Value

 
Value

 
Value

 
Value

Financial assets at fair value through profit or loss
 
$
21,324

 
$
21,324

 
$
31,468

 
$
31,468

Loans and receivables
 
38,214

 
38,214

 
33,159

 
33,159

Financial liabilities at fair value through profit or loss
 
3,729

 
3,729

 
72,655

 
72,655

Other liabilities
 
115,215

 
116,666

 
35,691

 
35,691

Assets and liabilities at March 31, 2017 that are measured at fair value are classified into levels reflecting the method used to make the measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement.
The Company’s cash and cash equivalents, convertible debentures and derivative commodity contracts are assessed on the fair value hierarchy described above. TransGlobe’s cash and cash equivalents and convertible debentures are classified as Level 1. Derivative commodity contracts are classified as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. There were no transfers between levels in the fair value hierarchy in the period.
Derivative commodity contracts
In conjunction with the prepayment agreement (Note 12), TPI has also entered into a marketing contract with Mercuria to market nine million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on indexed market prices at the time of sale.
The nature of TransGlobe’s operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings at each reporting period. TransGlobe has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.
There were three outstanding derivative commodity contracts as at March 31, 2017 (December 31, 2016 - nil), the fair values of which have been presented as liabilities on the Condensed Consolidated Interim Balance Sheet.
The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at March 31, 2017:
Financial BRENT Crude Oil Contracts
Term
 
Contract
 
Volume bbl
 
Sold Swap
US$/bbl
 
Bought Put
US$/bbl
 
Sold Call
US$/bbl
28-Mar-2017
 
31-Dec-2017
 
Collar
 
300,000
 
—
 
45.00
 
56.00
24-Mar-2017
 
30-Jun-2017
 
Swap
 
500,000
 
50.65
 
—
 
—
27-Mar-2017
 
30-Sep-2017
 
Swap
 
425,000
 
51.00
 
—
 
—

Credit risk
Credit risk is the risk of financial loss if a customer or counterparty to a financial instrument fails to fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to cash equivalents and accounts receivable, the majority of which are in respect of oil and natural gas operations. The Company generally extends unsecured credit to these parties and therefore the collection of these amounts may be affected by changes in economic or other conditions. The Company has not experienced any material credit losses in the collection of accounts receivable to date.
TransGlobe's accounts receivable related to the Canadian operations are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company currently sells its production to several purchasers under standard industry sale and payment terms. Purchasers of TransGlobe's natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. The Company has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions.
Trade and other receivables are analyzed in the table below. The majority of the overdue receivables are due from the EGPC. The political transition and resultant economic malaise in the country that began in 2011 resulted in irregular collection of accounts receivable from EGPC and generally a larger receivable balance, which increased TransGlobe's credit risk. Despite these factors, the Company expects to collect in full all receivables outstanding from EGPC.
In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company completed three separate direct crude sale shipments to third party buyers in 2016. Buyers are required to post irrevocable letters of credit to support the sales prior to the cargo liftings. During the first quarter of 2017, the Company sold 303,817 barrels of inventoried entitlement crude oil to EGPC for $12.7 million to cover in-country expenditures for Q1/Q2. As at March 31, 2017 the Company had collected $6.7 million of the $12.7 million in sales with EGPC.

Q1-2017
 
29
 

(000s)
 
Trade receivables at March 31, 2017
 
Neither impaired nor past due
$
10,945

Impaired
—

Not impaired and past due in the following period


Within 30 days
4,253

31-60 days
—

61-90 days
—

Over 90 days
6,644

4. PETROLEUM AND NATURAL GAS SALES
 
 
Three months ended March 31
 
(000s)
 
2017

 
2016

Petroleum and natural gas sales
 
$
46,553

 
$
29,022

Less: Royalties
 
24,092

 
11,595

Petroleum and natural gas sales, net of royalties
 
$
22,461

 
$
17,427

5. FINANCE REVENUE AND COSTS
Finance revenue relates to interest earned on the Company’s bank account balances and term deposits.
Finance costs recognized in earnings were as follows:
 
 
Three months ended March 31
 
(000s)
 
2017

 
2016

Interest on convertible debenture
 
$
1,089

 
$
1,053

Interest on long-term debt
 
128

 
—

Interest on note payable
 
282

 
—

Interest on borrowing base facility
 
—

 
218

Amortization of deferred financing costs
 
49

 
158

Finance costs
 
$
1,548

 
$
1,429

6. CASH AND CASH EQUIVALENTS
(000s)
 
March 31, 2017

 
December 31, 2016

Cash
 
$
21,208

 
$
31,392

Cash equivalents
 
116

 
76

 
 
$
21,324

 
$
31,468

As at March 31, 2017 the Company's cash equivalents balance consisted of short-term deposits with an original term to maturity at purchase of three months or less. All of the Company's cash and cash equivalents are on deposit with high credit-quality financial institutions.
7. RESTRICTED CASH
As at March 31, 2017, the Company had restricted cash of $16.4 million (December 31, 2016 - $18.3 million). Restricted cash represents a cash collateralized letter of credit facility that is used to guarantee the Company's commitments on its Egyptian exploration concessions.
8. PRODUCT INVENTORY
Product inventory consists of the Company's Egypt entitlement crude oil barrels, which is valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the crude oil that is held in storage as determined on a concession by concession basis.
As at March 31, 2017, the Company had 1,528,295 barrels of entitlement oil in inventory valued at $14.74 per barrel (December 31, 2016 - 1,265,080 barrels valued at $15.49 per barrel).
9. INTANGIBLE EXPLORATION AND EVALUATION ASSETS
(000s)
 
Balance at December 31, 2016
$
105,869

Additions
10,448

Impairment loss
(1,191
)
Balance at March 31, 2017
$
115,126


30
 
Q1-2017
 

The Company recorded an impairment loss of $1.2 million on its exploration and evaluation assets during the first quarter of 2017. The impairment related to the South West Gharib concession in Egypt and represents the entire intangible exploration and evaluation asset balance at South West Gharib as at March 31, 2017, as the recoverable amount of the South West Gharib cash-generating unit is nil. It was determined that an impairment loss was necessary as no commercially viable quantities of oil have been discovered at South West Gharib, and no further drilling activities are planned.
10. PROPERTY AND EQUIPMENT
 
 
PNG

 
Other

 
 
(000s)
 
Assets

 
Assets

 
Total

Balance at December 31, 2016
 
$
625,893

 
$
14,572

 
$
640,465

Additions
 
194

 
76

 
270

Changes in estimate for asset retirement obligations
 
56

 
—

 
56

Balance at March 31, 2017
 
$
626,143

 
$
14,648

 
$
640,791

 
 
 
 
 
 
 
Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2016
 
$
415,866

 
$
10,327

 
$
426,193

Depletion, depreciation and amortization for the period
 
9,593

 
377

 
9,970

Balance at March 31, 2017
 
$
425,459

 
$
10,704

 
$
436,163

Net Book Value
 
 
 
 
 
 

At December 31, 2016
 
$
210,027

 
$
4,245

 
$
214,272

At March 31, 2017
 
$
200,684

 
$
3,944

 
$
204,628

11. ASSET RETIREMENT OBLIGATION
(000s)
 
Balance at December 31, 2016
$
12,099

Changes in estimates for asset retirement obligations
(6
)
Asset retirement obligation accretion
60

Changes in discount rates
61

Effect of movements in foreign exchange rates
94

Balance at March 31, 2017
$
12,308


TransGlobe has estimated the net present value of its asset retirement obligation to be $12.3 million as at March 31, 2017 (December 31, 2016 - $12.1 million) based on a total undiscounted future liability, after inflation adjustment, of $18.7 million (December 31, 2016 - $19.0 million). These payments are expected to be made between 2017 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 0.75% and 2.31% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimate was 2% per annum.
At March 31, 2017 and December 31, 2016, the entire asset retirement obligation balance related to the Company's Canadian operations.
12. LONG-TERM DEBT
The Company's interest-bearing loans and borrowings are measured at amortized cost. As at March 31, 2017, the only significant interest-bearing loans and borrowings related to the Prepayment Agreement and the Note Payable are described below.
Prepayment Agreement
(000s)
 
March 31, 2017

 
December 31, 2016

Prepayment agreement
 
$
75,000

 
$
—

Deferred financing costs
 
(1,451
)
 
—

 
 
73,549

 
—

Current portion of long-term debt
 
—

 
—

 
 
$
73,549

 
$
—

On February 10, 2017, the Company completed a $75 million crude oil prepayment agreement between its wholly owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria Energy Trading SA ("Mercuria") of Geneva, Switzerland.
The initial advance under the prepayment agreement was used to refinance the 6.0% convertible debentures of the Company, which matured on March 31, 2017 (Note 13).
TPI's obligations under the prepayment agreement are guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. The funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of

Q1-2017
 
31
 

Libor plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75 million and subject to compliance with the other terms and conditions of the prepayment agreement. The prepayment agreement was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Financing costs of $1.5 million will be amortized over the term of the prepayment agreement using the effective interest rate method.
The Company is subject to certain financial covenants in accordance with the terms of the prepayment agreement. These covenants are tested on June 30 and December 31 of each year for the life of the prepayment agreement. The financial covenants are as follows:
•
the ratio of the Company's total consolidated indebtedness (calculated by including any outstanding letters of credit or bank guarantees and adding back any cash held by the Company on a consolidated basis) on each financial covenant test date to the Company's consolidated net cash generated by (used in) operating activities (where net cash generated includes the fair market value of crude oil inventory held as at the financial covenant test date) for the trailing 12 month period period ending on that financial covenant test date will not exceed 4.0:1.0;
•
the ratio of Current Assets of the Company on a consolidated basis (calculated, in the case of crude oil inventory, by adjusting the value to market value) to Current Liabilities of the Company on a consolidated basis on each financial covenant test date will not be less than 1.0:1.0; and
•
the ratio of the parent's non-consolidated asset value to the aggregate amount of indebtedness outstanding under the advance documents on each financial covenant test date will not be less than 2.0:3.0.
The Company is also subject to a cover ratio provision. The cover ratio, defined as the value of forecast entitlement crude oil production on a forward 12 month basis divided by prepayment service obligations, must not be less than 1.25:1.0. In the event the cover ratio falls below 1.25:1.0, TransGlobe must:
•
reimburse in cash the relevant portion of the advances such that the cover ratio becomes equal to or greater than 1.25:1.0; and/or
•
amend the initial commercial contract to extend its duration and amend the maturity date under the agreement.
The estimated future debt payments on long-term debt as of March 31, 2017 are as follows:
(000s)
 
2017
$
—

2018
—

2019
1,195

2020
23,771

2021
50,034

 
$
75,000

Note Payable
On December 20, 2016, the Company closed the acquisition of certain petroleum properties in west central Alberta, Canada. The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.3 million). The note payable has a 24-month term and bears interest at a rate of 10% per annum. Principal repayments must be made on a quarterly basis, and must be equal to or greater than 50% of the net operating income of the acquired assets.
(000s)
 
March 31, 2017

 
December 31, 2016

Note payable
 
$
11,259

 
$
11,162

Current portion of note payable
 
(7,037
)
 
(5,581
)
 
 
$
4,222

 
$
5,581

The estimated future debt payments on the note payable as of March 31, 2017 are as follows:
($000s)
 
2017
5,630

2018
5,629

13. CONVERTIBLE DEBENTURES
(000s)
 
Balance at December 31, 2016
$
72,655

Repayment
(73,375
)
Fair value adjustment
151

Foreign exchange adjustment
569

Balance at March 31, 2017
$
—

The convertible debentures matured on March 31, 2017 and were repaid in full on that date for their aggregate face value of C$97.8 million ($73.4 million). Repayment was made using the proceeds of the prepayment agreement (Note 12).

32
 
Q1-2017
 


14. COMMITMENTS AND CONTINGENCIES
The Company is subject to certain office and equipment leases.
Pursuant to the PSC for North West Gharib in Egypt, the Company had a minimum financial commitment of $35.0 million ($0.6 million remaining as at March 31, 2017) and a work commitment for 30 wells and 200 square kilometers of 3-D seismic during the initial-three year exploration period, which commenced on November 7, 2013. As at March 31, 2017, the Company had expended $34.4 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, extending the initial exploration period to May 7, 2017. Subsequent to the end of the first quarter, the Company completed the initial exploration period work program and met all financial commitments.
Pursuant to the PSC for South West Gharib in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for four wells and 200 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company received a six month extension, which extended the initial exploration period to May 7, 2017. Since no commercially viable quantities of oil have been discovered at South West Gharib, the Company relinquished its interest in the concession on May 7, 2017. The Company met its financial commitment during the first quarter of 2017.

Pursuant to the PSC for South Ghazalat in Egypt, the Company had a minimum financial commitment of $8.0 million and a work commitment for two wells and 400 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013 and reached its primary term on November 7, 2016. Prior to expiry, the Company elected to enter the first two-year extension period (expiry November 7, 2018). The Company had met its financial commitment for the first phase ($8.0 million) and the first extension ($4.0 million), however the Company had not completed the first phase work program. Prior to entering the first extension the Company posted a $4.0 million performance bond with EGPC to carry forward two exploration commitment wells into the first extension period. The $4.0 million performance bond is supported by a production guarantee from the Company's producing concessions which will be released when the commitment wells have been drilled. In accordance with the concession agreement the Company relinquished 25% of the original exploration acreage prior to entering the first extension period. In addition, the first extension period has an additional financial commitment of $4.0 million, which has been met, and two additional exploration wells.
Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($5.5 million remaining) and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three and a half year exploration period, which commenced on January 8, 2015. As at March 31, 2017, the Company had expended $4.5 million towards meeting that commitment.
In the normal course of its operations, the Company may be subject to litigations and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.
The Company is not aware of any material provisions or other contingent liabilities as at March 31, 2017.
15. SHARE CAPITAL
Authorized
The Company is authorized to issue an unlimited number of common shares with no par value.
Issued
 
 
Three months ended
 
 
Year ended
 
 
 
March 31, 2017
 
 
December 31, 2016
 
000’s
 
Shares

 
Amount

 
Shares

 
Amount

Balance, beginning of period
 
72,206

 
$
152,084

 
72,206

 
$
152,084

Balance, end of period
 
72,206

 
$
152,084

 
72,206

 
$
152,084



Q1-2017
 
33
 


16. SHARE-BASED PAYMENTS
The Company operates a stock option plan (the “Plan”) to provide equity-settled share-based remuneration to directors, officers and employees. The number of common shares that may be issued pursuant to the exercise of options awarded under the Plan and all other Security Based Compensation Arrangements of the Company is 10% of the common shares outstanding from time to time. All incentive stock options granted under the Plan have a per-share exercise price equal to the weighted average trading price of the common shares for the five trading days prior to the date of grant. Each tranche of an award with different vesting dates is considered a separate grant for the calculation of fair value and the resulting fair value is amortized over the vesting period of the respective tranches.
The following table summarizes information about the stock options outstanding and exercisable at the dates indicated:
 
 
Three months ended
 
 
Year ended
 
 
 
March 31, 2017
 
 
December 31, 2016
 
 
 
 
 
Weighted-

 
 
 
Weighted-

 
 
Number

 
Average

 
Number

 
Average

 
 
of

 
Exercise

 
of

 
Exercise

(000s except per share amounts)
 
Options

 
Price (C$)

 
Options

 
Price (C$)

Options outstanding, beginning of period
 
6,046

 
6.87

 
5,348

 
9.05

Granted
 
—

 
—

 
1,470

 
2.19

Forfeited
 
(723
)
 
7.71

 
(54
)
 
11.84

  Expired
 
(45
)
 
11.82

 
(718
)
 
12.95

Options outstanding, end of period
 
5,278

 
6.71

 
6,046

 
6.87

Options exercisable, end of period
 
3,493

 
8.10

 
3,527

 
9.14

Share–based compensation
Compensation expense of $0.2 million was recorded in general and administrative expenses in the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss) and Changes in Shareholders’ Equity during the three-month period ended March 31, 2017 (2016 - $0.4 million) in respect of equity-settled share-based payment transactions. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model.
All options granted vest annually over a three-year period and expire five years after the grant date. During the period ended March 31, 2017, no stock options were exercised (2016 – nil). As at March 31, 2017 and December 31, 2016, the entire balance in contributed surplus was related to previously recognized share-based compensation expense on equity-settled stock options.
Restricted share unit, performance share unit and deferred share unit plans
In May 2014, the Company implemented a restricted share unit ("RSU") plan, a performance share unit ("PSU") plan and a deferred share unit ("DSU") plan. RSUs may be issued to directors, officers and employees of the Company, and each RSU entitles the holder to a cash payment equal to the fair market value of a TransGlobe common share on the vesting date of the RSU. All RSUs granted vest annually over a three-year period, and all must be settled within 30 days of their respective vesting dates.
PSUs are similar to RSUs, except that the number of PSUs that ultimately vest is dependent on achieving certain performance targets and objectives as set by the board of directors. Depending on performance, vested PSUs can range between 50% and 150% of the original PSU grant. All PSUs granted vest on the third anniversary of their grant date, and all must be settled within 60 days of their vesting dates.
DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's board of directors.
The number of RSUs, PSUs and DSUs outstanding as at March 31, 2017 are as follows:
 
Restricted

 
Performance

 
Deferred

 
Share

 
Share

 
Share

(000s)
Units

 
Units

 
Units

Units outstanding, beginning of period
546

 
1,366

 
437

Granted
83

 
72

 
—

Forfeited
(38
)
 
(152
)
 
—

Units outstanding, end of period
591

 
1,286

 
437

An immaterial compensation expense was recorded in general and administrative expenses in the Condensed Consolidated Interim Statement of Earnings (Loss) and Comprehensive Income (Loss) and Changes in Shareholders' Equity during the three month periods ended March 31, 2017 and March 31, 2016 in respect of share units granted under the three plans described above. The expense related to the share units granted under these plans is measured at fair value using the lattice-based trinomial pricing model and is recognized over the vesting period, with a corresponding liability recognized on the Condensed Consolidated Interim Balance Sheet. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in earnings.




34
 
Q1-2017
 

17. PER SHARE AMOUNTS
The weighted-average number of common shares outstanding (basic and diluted) for the period ended March 31, 2017 was 72,205,369 (2016 - 72,205,369). These outstanding share amounts were used to calculate earnings (loss) per share in the respective periods.
In determining diluted earnings per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the period ended March 31, 2017, the Company excluded 3,983,300 stock options (2016 – 6,664,353) as their exercise price was greater than the average common share market price in the period.
18. SEGMENTED INFORMATION
The Company has two reportable operating segments for the period ended March 31, 2017: the Arab Republic of Egypt and Canada. The Company, through its operating segments, is engaged primarily in oil and gas exploration, development and production and the acquisition of properties.
In presenting information on the basis of operating segments, segment revenue is based on the geographical location of assets which is also consistent with the location of the segment customers. Segmented assets are also based on the geographical location of the assets. There are no inter-segment sales.
The accounting policies of the operating segments are the same as the Company’s accounting policies.
 
 
   Egypt
 
Canada
 
      Total
 
 
Three months ended
 
 
Three months ended
 
 
Three months ended
 
 
 
March 31
 
 
March 31
 
 
March 31
 
(000s)
 
2017

 
2016

 
2017

 
2016

 
2017

 
2016

Revenue
 
 
 
 
 
 
 
 
 
 
 
 
Oil sales, net of royalties
 
$
18,125

 
$
17,427

 
$
4,336

 
$
—

 
$
22,461

 
$
17,427

Finance revenue
 
2

 
101

 
—

 
—

 
2

 
101

Total segmented revenue
 
18,127

 
17,528

 
4,336

 
—

 
22,463

 
17,528

 
 
 
 
 
 
 
 
 
 
 
 
 
Segmented expenses
 
 
 
 
 
 
 
 
 
 
 
 
Production and operating
 
8,546

 
13,121

 
1,577

 
—

 
10,123

 
13,121

Transportation costs
 
—

 
—

 
198

 
—

 
198

 
—

Selling costs
 
—

 
828

 
—

 
—

 
—

 
828

Finance costs
 
—

 
—

 
282

 
—

 
282

 
—

Depletion, depreciation and amortization
 
6,114

 
9,894

 
2,302

 
—

 
8,416

 
9,894

Accretion
 
—

 
—

 
60

 
—

 
60

 
—

Realized derivative loss on commodity contracts
 
—

 
258

 
—

 
—

 
—

 
258

Unrealized derivative loss on commodity contracts
 
3,729

 
—

 
—

 
—

 
3,729

 
—

Income taxes - current
 
5,420

 
3,175

 
—

 
—

 
5,420

 
3,175

Income taxes - deferred
 
—

 
(2,197
)
 
—

 
—

 
—

 
(2,197
)
Impairment loss
 
1,191

 
—

 
—

 
—

 
1,191

 
—

Total segmented expenses
 
25,000

 
25,079

 
4,419

 
—

 
29,419

 
25,079

Segmented earnings (loss)
 
$
(6,873
)
 
$
(7,551
)
 
$
(83
)
 
$
—

 
(6,956
)
 
(7,551
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-segmented expenses (income)
 
 
 
 
 
 
 
 
 
 
 
 
General and administrative
 
 
 
 
 
 
 
 
 
4,446

 
3,523

Foreign exchange (gain) loss
 
 
 
 
 
 
 
 
 
(15
)
 
5,391

Depreciation and amortization
 
 
 
 
 
 
 
 
 
96

 
122

Unrealized (gain) loss on financial instruments
 
 
 
 
 
 
 
 
 
151

 
(1,631
)
Finance revenue
 
 
 
 
 
 
 
 
 
(23
)
 
(136
)
Finance costs
 
 
 
 
 
 
 
 
 
1,266

 
1,429

Total non-segmented expenses
 
 
 
 
 
 
 
 
 
5,921

 
8,698

 
 
 
 
 
 
 
 
 
 
 
 
 
Net earnings (loss) for the period
 
 
 
 
 
 
 
 
 
$
(12,877
)
 
$
(16,249
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
 
 
 
 
 
 
 
 
 
 
 
Exploration and development
 
$
10,670

 
$
4,265

 
$
48

 
$
—

 
$
10,718

 
$
4,265

Total capital expenditures
 
 
 
 
 
 
 
 
 
$
10,718

 
$
4,265



Q1-2017
 
35
 


The carrying amounts of reportable segment assets and liabilities are as follows:
March 31, 2017
 
 
 
 
 
 
(000s)
 
Egypt

 
Canada

 
Total

Assets
 
 
 
 
 
 
Intangible exploration and evaluation assets
 
$
115,126

 
$
—

 
$
115,126

Property and equipment
 
 
 
 
 
 
Petroleum and natural gas assets
 
131,612

 
69,072

 
200,684

Other assets
 
2,581

 
—

 
2,581

Other
 
44,870

 
5,846

 
50,716

Segmented assets
 
294,189

 
74,918

 
369,107

Non-segmented assets
 
 
 
 
 
34,579

Total assets
 
 
 
 
 
$
403,686

 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
Accounts payable and accrued liabilities
 
$
21,170

 
$
3,044

 
$
24,214

Derivative commodity contracts
 
3,729

 
—

 
3,729

Current and long-term note payable
 
—

 
11,259

 
11,259

Asset retirement obligation
 
—

 
12,308

 
12,308

Segmented liabilities
 
24,899

 
26,611

 
51,510

Non-segmented liabilities
 
 
 
 
 
80,101

Total liabilities
 
 
 
 
 
$
131,611


December 31, 2016
 
 
 
 
 
 
(000s)
 
Egypt

 
Canada

 
Total

Assets
 
 
 
 
 
 
Intangible exploration and evaluation assets
 
$
105,869

 
$
—

 
$
105,869

Property and equipment
 
 
 
 
 
 
Petroleum and natural gas assets
 
138,757

 
71,270

 
210,027

Other assets
 
2,785

 
—

 
2,785

Other
 
35,755

 
620

 
36,375

Segmented assets
 
283,166

 
71,890

 
355,056

Non-segmented assets
 
 
 
 
 
51,086

Total assets
 
 
 
 
 
$
406,142

 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
Accounts payable and accrued liabilities
 
$
14,005

 
$
432

 
$
14,437

Current and long-term note payable
 
—

 
11,162

 
11,162

Asset retirement obligation
 
—

 
12,099

 
12,099

Segmented liabilities
 
14,005

 
23,693

 
37,698

Non-segmented liabilities
 
 
 
 
 
83,128

Total liabilities
 
 
 
 
 
$
120,826


19. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital consisted of the following:
 
 
Three months ended March 31
 
(000s)
 
2017

 
2016

Operating Activities
 
 
 
 
(Increase) decrease in current assets
 
 
 
 
Accounts receivable
 
$
(7,006
)
 
$
527

Prepaids and other
 
(132
)
 
541

Product inventory1
 
(1,470
)
 
1,823

Increase (decrease) in current liabilities
 
 
 
 
Accounts payable and accrued liabilities
 
3,609

 
1,365

 
 
$
(4,999
)
 
$
4,256

Note:
 
 
 
 
  1 The change in non-cash working capital associated with product inventory represents the change in operating costs capitalized as product inventory in the respective periods.

Q1-2017
 
36
 

Investing Activities
 
 
 
 
Increase (decrease) in current liabilities
 
 
 
 
Accounts payable and accrued liabilities
 
$
2,952

 
$
1,214

 
 
$
2,952

 
$
1,214




Q1-2017
 
37

CORPORATE & SHAREHOLDER INFORMATION
 
 
 
DIRECTORS
 
TRANSFER AGENT
 
Computershare Trust Company of Canada
Robert G. Jennings (1)
600, 530 8th Avenue S.W.
Chairman
Calgary, Alberta T2P 3S8
 
 
Ross G. Clarkson
 
President & CEO
LEGAL COUNSEL
 
Burnet, Duckworth & Palmer LLP
Lloyd W. Herrick
Calgary, Alberta
Vice President & COO
 
 
 
Matthew Brister (3)
AUDITORS
 
Deloitte LLP
Geoffrey C. Chase (3)
Calgary, Alberta
 
 
David B. Cook (1)(2)
 
 
EVALUATION ENGINEERS
Fred J. Dyment (1)(2)
DeGolyer and MacNaughton Canada Limited
 
 
G. R. (Bob) MacDougall (3)
 
 
BANKS
Susan M. MacKenzie (2)(3)
Sumitomo Mitsui Banking Corporation Europe Limited
 
London, Great Britain
Steven W. Sinclair (1)
 
 
Alberta Treasury Branch
(1) Audit Committee
Calgary, Alberta, Canada
(2) Compensation Human Resources and Governance Committee
 
(3) Reserves, Health, Safety, Environment and Social Responsibility Committee
 
 
INVESTOR RELATIONS
 
Steve Langmaid
 
 
Telephone: 403-444-4787
 
investor.relations@trans-globe.com
OFFICERS
 
 
 
 
Ross G. Clarkson
WEBSITE
President & Chief Executive Officer
www.trans-globe.com
 
 
Lloyd W. Herrick
 
Vice President & Chief Operating Officer
HEAD OFFICE
 
2300, 250 – 5th Street S.W.
Randy C. Neely
Calgary, Alberta, Canada T2P 0R4
Vice President, Finance, Chief Financial Officer & Corporate Secretary
Telephone: (403) 264-9888
 
Facsimile: (403) 770-8855
Brett Norris
 
Vice President, Exploration
 
 
EGYPT OFFICE
Marilyn A. Vrooman-Robertson
10 Rd 261
Assistant Corporate Secretary
New Maadi, Cairo, Egypt
 
 
www.trans-globe.com
TSX: TGL NASDAQ: TGA