EX-2 3 a2017q2-mda.htm EXHIBIT 2 Exhibit
 


MANAGEMENT'S DISCUSSION AND ANALYSIS
August 11, 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 for the Company for the three and six months ended June 30, 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 have been 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.


Q2-2017
 
1
 


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 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
At mid-year 2017, the Company has adjusted the 2017 Capital program and production outlook to reflect results to date, commodity prices and the forward plan for the balance of 2017.
The Company’s 2017 adjusted Capital program of $41.5 million (before capitalized G&A) is within original guidance of $35.4 (Firm) and $56.4 million (Firm & Contingent). It is expected that 2017 production will average between 15,500 and 16,500 boepd, representing a 30% to 40% increase over 2016 production (production in Q2-2017 was 16,465 boepd).  The 2017 production mid-year outlook is provided as a range to reflect the timing of projects and the associated results. Funds flow in any given period will be dependent upon the timing of crude oil tanker liftings in Egypt, the amount of entitlement oil sold to EGPC 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. The Company expects positive funds flow for the remainder of 2017 with the two scheduled tanker liftings and additional sales of entitlement oil to EGPC.
Management will continue to steward the balance sheet conservatively and allocate future funds flow between capital expenditures and debt repayments.
2017 Capital Budget
The Company's 2017 capital program of $41.5 million (before capitalized G&A) includes $35.4 million for Egypt and $6.1 million (C$7.9 million) for Canada. The $41.5 million capital program is approximately $14.9 million lower (26%) than the original Firm and Contingent budget of $56.4 million due to lower commodity prices, results to date and the timing of projects in Egypt.
Egypt
The $35.4 million Egypt program has $19.5 million (55%) allocated to exploration and $15.9 million (45%) to development. The $19.5 million exploration program includes drilling up to 10 wells in the Eastern Desert, one Boraq well at South Alamein in the Western Desert and a large (600 km²) 3-D seismic acquisition program at NW Sitra in the Western Desert. The $15.9 million 2017 development program includes drilling up to 6 development wells in the Eastern Desert (2 wells at WG, 1 well at WB and 3 wells at NWG) and development/maintenance projects at West Gharib, West Bakr and NW Gharib.
Canada
The $6.1 million (C$7.9 million) Canada program consists of three 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 (40 stages) per well. The 2017 program was scaled back to a three well program (on an existing pad) due to reduced commodity prices in the 2nd and 3rd quarter. The remaining five wells planned for 2017 will be added to the 2018 program.
The 2017 capital program is summarized in the following table:
 
 
TransGlobe 2017 Capital ($MM)
 
 
 
Gross Well Count
 
 
 
 
 
 
Total
 
(Wells)
Concession
 
Development
 
Exploration
 
 
Development
 
Exploration
 
Total
West Gharib
 
5.4
 
—
 
5.4
 
2
 
—
 
2
West Bakr
 
6.8
 
—
 
6.8
 
1
 
—
 
1
NW Gharib
 
3.7
 
9.9
 
13.6
 
3
 
8
 
11
SW Gharib
 
—
 
1.2
 
1.2
 
—
 
2
 
2
South Alamein
 
—
 
3.1
 
3.1
 
—
 
1
 
1
South Ghazalat
 
—
 
0.2
 
0.2
 
—
 
—
 
—
NW Sitra
 
—
 
5.1
 
5.1
 
—
 
—
 
—
Egypt
 
$15.9
 
$19.5
 
$35.4
 
6
 
11
 
17
Canada
 
$6.1
 
—
 
$6.1
 
3
 
—
 
3
2017 Total
 
$22.0
 
$19.5
 
41.5*
 
9
 
11
 
20
Splits (%)
 
53%
47%
100%
 
45%
 
55%
 
100%
*Before capitalized G&A.


2
 
Q2-2017
 


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 June 30
 
 
Six months ended June 30
 
($000s)
2017

 
2016

 
2017

 
2016

Cash flow from operating activities
(2,753
)
 
6,011

 
(5,250
)
 
7,437

Changes in non-cash working capital
19,608

 
(3,985
)
 
24,607

 
(8,241
)
Funds flow from operations1
16,855

 
2,026

 
19,357

 
(804
)
 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 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.



Q2-2017
 
3
 


SELECTED QUARTERLY FINANCIAL INFORMATION
 
 
2017
 
2016
 
2015
($000s, except per share,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
price and volume amounts)
 
Q-2

 
Q-1

 
Q-43

 
Q-3

 
Q-2

 
Q-1

 
Q-4

 
Q-3

Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average production volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (bbls/d)
 
14,347

 
14,514

 
12,861

 
11,733

 
11,472

 
12,058

 
13,425

 
14,683

NGLs (bbls/d)
 
919

 
1,037

 
134

 
—

 
—

 
—

 
—

 
—

Natural gas (mcf/d)
 
7,191

 
7,075

 
916

 
—

 
—

 
—

 
—

 
—

Total (boe/d)
 
16,465

 
16,731

 
13,148

 
11,733

 
11,472

 
12,058

 
13,425

 
14,683

Average sales volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (bbls/d)
 
17,141

 
11,610

 
7,018

 
11,485

 
11,783

 
14,126

 
7,205

 
13,620

NGLs (bbls/d)
 
919

 
1,037

 
134

 
—

 
—

 
—

 
—

 
—

Natural gas (mcf/d)
 
7,191

 
7,075

 
916

 
—

 
—

 
—

 
—

 
—

Total (boe/d)
 
19,259

 
13,826

 
7,305

 
11,485

 
11,783

 
14,126

 
7,205

 
13,620

Average realized sales prices
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil ($/Bbl)
 
39.46

 
41.66

 
37.38

 
34.43

 
30.27

 
22.58

 
32.38

 
39.35

NGLs ($/Bbl)
 
21.08

 
19.08

 
12.33

 
—

 
—

 
—

 
—

 
—

Natural gas ($/Mcf)
 
2.14

 
1.96

 
1.80

 
—

 
—

 
—

 
—

 
—

Total oil equivalent ($/boe)
 
36.92

 
37.41

 
36.45

 
34.43

 
30.27

 
22.58

 
32.38

 
39.35

Inventory (MBbl)
 
1,274

 
1,528

 
1,265

 
729

 
707

 
735

 
923

 
351

Petroleum and natural gas sales
 
64,711

 
46,553

 
24,501

 
36,376

 
32,461

 
29,022

 
21,460

 
49,307

Petroleum and natural gas sales, net of royalties
 
40,439

 
22,461

 
5,217

 
20,704

 
19,786

 
17,427

 
3,979

 
24,700

Cash flow from operating activities
 
(2,753
)
 
(2,497
)
 
6,355

 
(14,857
)
 
6,011

 
1,426

 
6,414

 
28,741

Funds flow from operations1
 
16,855

 
2,502

 
(9,904
)
 
2,347

 
2,026

 
(2,830
)
 
(11,108
)
 
(1,497
)
Funds flow from operations per share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
- Basic
 
0.23

 
0.03

 
(0.14
)
 
0.03

 
0.03

 
(0.04
)
 
(0.15
)
 
(0.02
)
- Diluted
 
0.23

 
0.03

 
(0.14
)
 
0.03

 
0.03

 
(0.04
)
 
(0.15
)
 
(0.02
)
Net earnings (loss)
 
(56,622
)
 
(12,877
)
 
(33,997
)
 
(25,369
)
 
(12,050
)
 
(16,249
)
 
(35,255
)
 
(46,568
)
Net earnings (loss) - diluted
 
(56,622
)
 
(12,877
)
 
(38,641
)
 
(25,369
)
 
(12,050
)
 
(16,249
)
 
(35,255
)
 
(54,159
)
Net earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
- Basic
 
(0.78
)
 
(0.18
)
 
(0.47
)
 
(0.35
)
 
(0.17
)
 
(0.23
)
 
(0.49
)
 
(0.64
)
- Diluted
 
(0.78
)
 
(0.18
)
 
(0.49
)
 
(0.35
)
 
(0.17
)
 
(0.23
)
 
(0.49
)
 
(0.68
)
Capital expenditures
 
8,229

 
10,718

 
8,863

 
8,692

 
4,838

 
4,265

 
4,877

 
3,587

Dividends paid
 
—

 
—

 
—

 
—

 
—

 
—

 
1,805

 
3,594

Dividends paid per share
 
—

 
—

 
—

 
—

 
—

 
—

 
0.025

 
0.05

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
337,596

 
403,686

 
406,142

 
414,363

 
433,013

 
441,624

 
455,500

 
501,808

Cash and cash equivalents
 
13,780

 
21,324

 
31,468

 
100,405

 
124,308

 
122,031

 
126,910

 
126,874

Convertible debentures
 
—

 
—

 
72,655

 
74,854

 
70,639

 
66,506

 
63,848

 
65,682

Note payable
 
—

 
11,259

 
11,162

 
—

 
—

 
—

 
—

 
—

Total long-term debt, including
     current portion
 
83,725

 
73,549

 
—

 
—

 
—

 
—

 
—

 
—

Debt-to-funds flow ratio2
 
7.1

 
(28.0
)
 
(10.0
)
 
(7.8
)
 
(5.3
)
 
(7.9
)
 
(7.2
)
 
3.6

  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.



4
 
Q2-2017
 


During the second quarter of 2017, TransGlobe:
•
Reported positive working capital of $60.3 million (including cash and cash equivalents of $13.8 million) at June 30, 2017;

•
Reported a net loss of $(56.6) million, which include a $67.5 million non-cash impairment loss on the Company's exploration and evaluation assets at NW Gharib and a $6.6 million unrealized derivative gain on commodity contracts (mark-to-market gain on the Company's hedging contracts). The recoverable amount of the North West Gharib cash-generating unit is $4.4 million. The Company's remaining NW Gharib exploration and evaluation assets were written down to nil;
•
Experienced a 99% increase in petroleum and natural gas sales compared to Q2-2016, which was principally due to a 22% increase in realized prices along with a 63% increase in sales volumes. Realized pricing for the Company's petroleum and natural gas products are market driven. The tanker lifting sale of entitlement crude oil during the quarter and the recently acquired Canadian assets also contributed to the petroleum and natural gas sales increase;
•
Achieved positive funds flow from operations of $16.9 million, which is a significant increase over the previous seven quarters;
•
Reported a 44% increase in production volumes as compared to Q2-2016, which translates into an additional 4,993 boepd. The recently acquired Canadian assets contributed 2,614 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 production from NW Gharib, which contributed 1,377 bopd.
•
Repaid the $11.0 million (C$15.0 million) vendor take-back note with the revolving reserve-based lending facility and cash;
•
Sold 515,526 barrels of entitlement crude oil marketed by Mercuria and an additional 302,648 barrels of inventoried entitlement crude oil to EGPC, resulting in a decrease in crude oil inventory of 0.3 million barrels from Q1-2017; and
•
Spent $8.2 million on capital programs, which was funded entirely from funds flow and cash on hand.


Q2-2017
 
5
 


2017 TO 2016 NET EARNINGS VARIANCES
 
 
 
 
$ Per Share

 
 
 
 
$000s

 
Diluted

 
% Variance

Q2-2016 net earnings (loss)
 
(12,050
)
 
(0.17
)
 
 
Cash items
 
 
 
 
 
 
Volume variance
 
25,275

 
0.35

 
(209
)
Price variance
 
6,978

 
0.10

 
(58
)
Royalties
 
(11,599
)
 
(0.16
)
 
96

Expenses:
 
 
 
 
 
 
Production and operating
 
(4,283
)
 
(0.06
)
 
36

Transportation
 
(156
)
 
—

 
1

Selling costs
 
(1,455
)
 
(0.02
)
 
12

Cash general and administrative
 
63

 
—

 
(1
)
Current income taxes
 
(2,010
)
 
(0.03
)
 
17

Realized foreign exchange gain (loss)
 
(92
)
 
—

 
1

Realized derivative gain (loss)
 
2,227

 
0.03

 
(18
)
Interest on long-term debt
 
(315
)
 
—

 
3

Other income
 
(118
)
 
—

 
1

Total cash items variance
 
14,515

 
0.21

 
(119
)
Non-cash items
 
 
 
 
 
 
Unrealized derivative gain (loss)
 
6,578

 
0.09

 
(55
)
Unrealized foreign exchange gain (loss)
 
(35
)
 
—

 
—

Depletion and depreciation
 
(2,280
)
 
(0.03
)
 
19

Asset retirement obligation accretion
 
(57
)
 
—

 
—

Unrealized gain (loss) on financial instruments
 
4,286

 
0.06

 
(36
)
Impairment loss
 
(67,520
)
 
(0.94
)
 
560

Stock-based compensation
 
703

 
0.01

 
(6
)
Deferred income taxes
 
(812
)
 
(0.01
)
 
7

Deferred lease inducement
 
(3
)
 
—

 
—

Amortization of deferred financing costs
 
53

 
—

 
—

Total non-cash items variance
 
(59,087
)
 
(0.82
)
 
489

Q2-2017 net earnings (loss)
 
(56,622
)
 
(0.78
)
 
370


TransGlobe recorded a net loss of $56.6 million in Q2-2017 compared to a net loss of $12.1 million in Q2-2016. The largest positive earnings variance was a result of a 22% increase in the average realized sales price and a 63% increase in sales volumes totaling $32.3 million in aggregate compared to Q2-2016, which was partially offset by increased royalties and current income taxes of $13.6 million. The Company incurred $1.5 million in selling costs during the period, principally associated with the cargo of entitlement oil sold in June. Operating expenditures increased in Q2-2017 compared to Q2-2016, due principally to recognizing capitalized operating costs associated with the previously inventoried entitlement crude oil barrels sold during the quarter.
The largest non-cash earnings variance item in Q2-2017 compared to Q2-2016 relates to the $67.5 million negative variance caused by an impairment loss recorded on the Company's exploration and evaluation assets at North West Gharib. The $67.5 million impairment loss recognized in the quarter is a result of reducing the overall carrying value of the North West Gharib concession to the discounted present value of the proved plus probable reserves recognized as at the end of the quarter. This impairment was taken after consideration of the uncertainly of the timing of additional exploration and development on the existing and pending development leases and the current forward outlook for Gharib blend pricing. The largest non-cash positive earnings variance in Q2-2017 compared to Q2-2016 related to the unrealized derivative gain on commodity contracts recorded in Q2-2017. The Company recorded a $6.6 million non-cash gain on its outstanding hedging contracts as at June 30, 2017, which was a result of marking the contracts to their respective market values. In Q2-2016, there were no hedging contracts outstanding. The mark-to-market adjustment on the convertible debentures created a positive earnings swing of $4.3 million. The convertible debentures were repaid during the first quarter of 2017.









6
 
Q2-2017
 


BUSINESS ENVIRONMENT
The Company’s financial results can be significantly 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-2

 
Q-1

 
Q-4

 
Q-3

 
Q-2

Crude oil
 
 
 
 
 
 
 
 
 
 
Dated Brent average oil price (US$/Bbl)
 
49.67

 
53.68

 
49.19

 
45.79

 
45.52

Edmonton Sweet index (US$/bbl)
 
46.03

 
48.37

 
46.18

 
41.99

 
42.51

Natural gas
 
 
 
 
 
 
 
 
 
 
AECO (C$/mmbtu)
 
2.78

 
2.69

 
3.09

 
2.32

 
1.40

U.S./Canadian Dollar average exchange rate
 
1.345

 
1.323

 
1.334

 
1.305

 
1.289

The price of Dated Brent oil averaged 7% lower in Q2-2017 compared with Q1-2017. 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 financial challenges over the past six years. 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 $356.4 million from EGPC, reducing the balance due from EGPC to $18.8 million as at June 30, 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 cooperation and approval to schedule liftings. Once liftings are scheduled, the Company now enjoys a 30-day collection cycle as a result of direct marketing to third party international buyers. Depending on the Company's assessment of the credit of crude cargo buyers, buyers may be 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% lower in Q2-2017 compared with Q1-2017. The price of AECO averaged 3% higher in Q2-2017 compared with Q1-2017.




Q2-2017
 
7
 


OPERATING RESULTS AND NETBACK
Daily Volumes, Working Interest before Royalties (Boepd)
Production Volumes
 
Three months ended June 30
 
Six months ended June 30
 
2017
 
2016

 
2017

 
2016

Egypt crude oil (bbls/d)
13,851

 
11,472

 
13,900

 
11,765

Canada crude oil (bbls/d)
496

 
—

 
530

 
—

Canada natural gas (mcf/d)
7,191

 
—

 
7,133

 
—

Canada NGLs (bbls/d)
919

 
—

 
978

 
—

Total Company (boe/d)
16,465

 
11,472

 
16,597

 
11,765


Sales Volumes (excludes volumes held as inventory)
 
Three months ended June 30
 
Six months ended June 30
 
2017

 
2016

 
2017

 
2016

Egypt crude oil (bbls/d)
16,645

 
11,783

 
13,861

 
12,955

Canada crude oil (bbls/d)
496

 
—

 
530

 
—

Canada natural gas (mcf/d)
7,191

 
—

 
7,133

 
—

Canada NGLs (bbls/d)
919

 
—

 
978

 
—

Total Company (boe/d)
19,259

 
11,783

 
16,558

 
12,955


Netback
Consolidated netback
 
 
 
 
 
 
 
 
 
 
Six months ended June 30
 
 
2017
 
2016
(000s, except per Boe amounts)1
 
$

 
$/Boe

 
$

 
$/Bbl

Petroleum and natural gas sales
 
111,265

 
37.13

 
61,483

 
26.08

Royalties and other
 
48,365

 
16.14

 
24,270

 
10.29

Current taxes
 
10,925

 
3.65

 
6,670

 
2.83

Production and operating expenses
 
25,046

 
8.36

 
23,761

 
10.08

Transportation
 
354

 
0.12

 
—

 
—

Selling costs
 
1,502

 
0.50

 
875

 
0.37

Netback
 
25,073

 
8.36

 
5,907

 
2.51

1   The Company achieved the netbacks above on sold barrels of oil equivalent for the six months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).
Consolidated netback
 
 
 
 
 
 
 
 
 
 
Three months ended June 30
 
 
2017
 
2016
(000s, except per Boe amounts)1
 
$

 
$/Boe

 
$

 
$/Bbl

Petroleum and natural gas sales
 
64,711

 
36.92

 
32,461

 
30.27

Royalties and other
 
24,272

 
13.85

 
12,675

 
11.82

Current taxes
 
5,505

 
3.14

 
3,495

 
3.26

Production and operating expenses
 
14,923

 
8.51

 
10,640

 
9.92

Transportation
 
156

 
0.09

 
—

 
—

Selling costs
 
1,502

 
0.86

 
47

 
0.04

Netback
 
18,353

 
10.47

 
5,604

 
5.23

1 The Company achieved the netbacks above on sold barrels of oil equivalent for the three months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).




8
 
Q2-2017
 


Egypt
 
 
 
 
 
 
 
 
 
 
Six months ended June 30
 
 
2017
 
2016
(000s, except per Bbl amounts)1
 
$

 
$/Bbl

 
$

 
$/Bbl

Oil sales
 
100,581

 
40.09

 
61,483

 
26.08

Royalties
 
46,037

 
18.35

 
24,270

 
10.29

Current taxes
 
10,925

 
4.35

 
6,670

 
2.83

Production and operating expenses
 
22,102

 
8.81

 
23,761

 
10.08

Selling costs
 
1,502

 
0.60

 
875

 
0.37

Netback
 
20,015

 
7.98

 
5,907

 
2.51

1   The Company achieved the netbacks above on sold barrels of oil equivalent for the six months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).
Egypt
 
 
 
 
 
 
 
 
 
 
Three months ended June 30
 
 
2017
 
2016
(000s, except per Bbl amounts)1
 
$

 
$/Bbl

 
$

 
$/Bbl

Oil sales
 
59,541

 
39.31

 
32,461

 
30.27

Royalties
 
23,122

 
15.27

 
12,675

 
11.82

Current taxes
 
5,505

 
3.63

 
3,495

 
3.26

Production and operating expenses
 
13,556

 
8.95

 
10,640

 
9.92

Selling costs
 
1,502

 
0.99

 
47

 
0.04

Netback
 
15,856

 
10.47

 
5,604

 
5.23

1   The Company achieved the netbacks above on sold barrels of oil equivalent for the three months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).

The netback per Bbl in Egypt increased 100% and 218%, respectively, in the three and six months ended June 30, 2017 compared with the same periods of 2016. The increased netbacks were principally the result of an increase in realized oil prices of 30% and 54%, respectively, and a decrease in operating costs per barrel of 10% and 13%, respectively, in the three and six months ended June 30, 2017 compared with the same periods of 2016.
Production and operating expenses increased by $2.9 million in the three months ended June 30, 2017 compared to the same period of 2016. This is principally the result of an increase in sales volumes in Q2-2017, resulting in recognizing the capitalized operating costs associated with the crude oil inventory in the period. Operating costs for the six months ended June 30, 2017 are relatively consistent with the same period in 2016. On a per Bbl basis, production and operating costs have decreased by 10% and 13%, respectively, in the three and six months ended June 30, 2017 compared with the same periods of 2016. The most significant cost efficiencies were achieved in the areas of labour costs and equipment rentals. The devaluation of the Egyptian pound, which occurred in Q4 of 2016, also had a significant positive impact on operating expenses in the quarter as compared to Q2 2016. The gains realized from increased prices and lower operating costs were offset somewhat by higher transportation and marketing fees incurred on the direct sale of the Company's crude oil. TransGlobe completed one direct sale of crude oil to third party buyers marketed by Mercuria during Q2-2017.
Royalties and taxes as a percentage of revenue were 48% and 57%, in the three and six month periods ended June 30, 2017 respectively, compared with 50% for each of the same periods of 2016. Royalties and taxes are settled on a production basis, so the correlation of royalties and taxes to oil sales fluctuates depending on the timing of entitlement oil sales. As such, in periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of the PSCs and 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.
The average selling price during the three months ended June 30, 2017 was $39.31/Bbl, which was $10.36/Bbl lower than the average Dated Brent oil price of $49.67/Bbl for the period (Q2-2016 - $45.52/Bbl). The difference was due to a gravity/quality adjustment and was also impacted by the timing of the direct sale.







Q2-2017
 
9
 


Canada
 
 
 
 
 
 
 
 
 
 
Six months ended June 30
 
 
2017
 
2016
(000s, except per Boe amounts)
 
$

 
$/Boe

 
$

 
$/Boe

Crude oil sales
 
4,494

 
46.85

 
—

 
—

Natural gas sales
 
2,645

 
12.29

 
—

 
—

NGL sales
 
3,544

 
20.02

 
—

 
—

Total sales
 
10,683

 
21.89

 
 
 
 
Royalties
 
2,328

 
4.77

 
—

 
—

Production and operating expenses
 
2,944

 
6.03

 
—

 
—

Transportation
 
354

 
0.73

 
—

 
—

Netback
 
5,057

 
10.36

 
—

 
—

Canada
 
 
 
 
 
 
 
 
 
 
Three months ended June 30
 
 
2017
 
2016
(000s, except per Boe amounts)
 
$

 
$/Boe

 
$

 
$/Boe

Crude oil sales
 
2,007

 
44.47

 
—

 
—

Natural gas sales
 
1,400

 
12.84

 
—

 
—

NGL sales
 
1,763

 
21.08

 
—

 
—

Total sales
 
5,170

 
21.74

 
 
 
 
Royalties
 
1,150

 
4.84

 
—

 
—

Production and operating expenses
 
1,367

 
5.75

 
—

 
—

Transportation
 
156

 
0.66

 
—

 
—

Netback
 
2,497

 
10.49

 
—

 
—

The Canadian financial information presented in the tables above represent the three and six months ended June 30, 2017 activity for the Company's newly acquired Canadian assets.
Netbacks in Canada for the three months ended Q2-2017 were $10.49 per Boe, which represents an increase of $0.26 per Boe as compared to the three months ended Q1-2017. This increase in netback is mainly due to a 10% decrease in production and operating expenses on a per Boe basis.
TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with an established royalty regime. In Alberta, crown royalty rates are based on reference commodity prices, production levels and well depths and are offset by certain incentive programs, which typically have a finite period of time and are in place to promote drilling activity by reducing overall royalty expense.
For the three months ended June, 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 June 30, 2017.


GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)
 
Six months ended June 30
 
2017
 
2016
(000s, except per Bbl amounts)
$ 

 
$/Bbl

 
$ 

 
$/Bbl

G&A (gross)
8,380

 
2.80

 
8,041

 
3.41

Stock-based compensation
650

 
0.22

 
1,546

 
0.66

Capitalized G&A
(1,222
)
 
(0.41
)
 
(1,939
)
 
(0.82
)
G&A (net)
7,808

 
2.61

 
7,648

 
3.25

 
Three months ended June 30
 
2017
 
2016
(000s, except per Bbl amounts)
$ 

 
$/Bbl

 
$ 

 
$/Bbl

G&A (gross)
3,631

 
2.07

 
3,909

 
3.65

Stock-based compensation
421

 
0.24

 
1,124

 
1.05

Capitalized G&A
(690
)
 
(0.39
)
 
(908
)
 
(0.85
)
G&A (net)
3,362

 
1.92

 
4,125

 
3.85


10
 
Q2-2017
 


G&A (gross) for the three months ended June 30, 2017 decreased 7% as compared with the same period in 2016 (43% decrease on a per boe basis). Primarily due to slightly lower staff levels and foreign exchange. For the six months ended June 30, 2017 G&A (gross) is relatively flat versus the same period in 2016.
G&A expenses (net) for the three months ended June 30, 2017 decreased 18% as compared with the same period in 2016 (50% decrease on a per boe basis). For the six months ended June 30, 2017 G&A (net) is relatively flat versus the same period in 2016 (20% decrease on a per boe basis).
Capitalized G&A for the three and six months ended June 30, 2017 decreased 24% and 37%, respectively, as compared with the same periods in 2016 (54% and 50% decrease, respectively, 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 $0.3 million and $0.7 million were capitalized for the three and six months ended June 30, 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 and six months ended June 30, 2017 were $1.7 million and $3.3 million, respectively (2016 - $1.5 million and $2.9 million, respectively).
 
 
Three months ended June 30
 
 
Six months ended June 30
 
(000s)
 
2017

 
2016

 
2017

 
2016

Convertible debentures
 
$
—

 
$
1,125

 
$
1,089

 
$
2,178

Long-term debt
 
1,327

 
—

 
1,455

 
—

Note payable
 
250

 
—

 
532

 
—

Borrowing base facility
 
49

 
188

 
49

 
406

Issue costs for convertible debentures
 
—

 
—

 
—

 
—

Amortization of deferred financing costs
 
91

 
143

 
140

 
301

Finance costs
 
$
1,717

 
$
1,456

 
$
3,265

 
$
2,885


Convertible Debentures
Interest expense on the convertible debentures for the three and six month period ended June 30, 2017 was $nil and $1.1 million, respectively (2016 - $1.1 million and $2.2 million, respectively). Interest on the convertible debentures was paid in Canadian dollars, and therefore fluctuated 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 $75.0 million crude oil prepayment agreement between its wholly-owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and 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 $75.0 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. Interest expense on the prepayment agreement for the three and six month period ended June 30, 2017 was $1.3 million and $1.5 million.
The prepayment agreement is subject to certain covenants, the details of which are outlined in Note 13 to the Company's Condensed Consolidated Interim Financial Statements.
Revolving Reserve-Based Lending Facility
As at June 30, 2017, the Company had in place a revolving Canadian reserve-based lending facility with ATB totaling C$30.0 million, of which
C$13.6 million was drawn on May 16, 2017 to repay the remaining outstanding vendor take-back note balance in full.

The facility is extendable on a semi-annual basis on May 31 and November 30 of each year, or as requested by the lender. Unless extended, before May 11, 2018, any unutilized amount of the facility will be cancelled, and the amount of the facility will be reduced to the aggregate borrowings outstanding on that date. The balance of all amounts owing under the facility are due and payable in full on the date falling one year after the term date.The Company may request an extension of the term date by no later than 90 days prior to the then current term date, and lender may in its sole discretion agree to extend the term date for a further period of 364 days. If no extension is granted by the lender, the amounts owing pursuant to the facility are due at the maturity date. The facility bears interest at a rate of either ATB Prime or CDOR (Canadian Dollar Offered Rate) plus applicable margins that vary from 1.25% to 3.25% depending on the Company's net debt to trailing cash flow ratio. The revolving reserve-based lending facility was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Interest expense on the revolving reserve-based lending facility for the three month period ended June 30, 2017 was $0.1 million.

Q2-2017
 
11
 


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 had a 24-month term and bore interest at a rate of 10% per annum. The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017. Repayment was made using the revolving reserve-based lending facility. Interest expense on the note payable for the three and six month period ended June 30, 2017 was $0.2 million and $0.5 million.

DEPLETION AND DEPRECIATION (“DD&A”)
 
Six months ended June 30
 
2017
 
2016
(000s, except per Bbl amounts)
$ 

 
$/Bbl

 
$ 

 
$/Bbl

Egypt
14,208

 
5.66

 
17,855

 
7.57

Canada
4,510

 
9.24

 
—

 
—

Corporate
157

 
—

 
244

 
—

 
18,875

 
6.30

 
18,099

 
7.68


 
Three months ended June 30
 
2017
 
2016
(000s, except per Bbl amounts)
$ 

 
$/Bbl

 
$ 

 
$/Bbl

Egypt
8,094

 
5.34

 
7,961

 
7.42

Canada
2,208

 
9.28

 
—

 
—

Corporate
61

 
—

 
122

 
—

 
10,363

 
5.91

 
8,083

 
7.54

In Egypt, DD&A decreased 28% and 25%, respectively, on a per Bbl basis in the three and six months ended June 30, 2017 compared to the same periods in 2016. The decrease is primarily related to a lower depletable cost base, which is the result of a 29% reduction in future development costs.
In Canada, DD&A was $9.28 and $9.24 per Bbl, respectively, on a per Bbl basis in the three and six months ended June 30, 2017, which was consistent with the DD&A rate for the three months ended Q1-2017.
IMPAIRMENT LOSS
The Company recorded an impairment loss of $68.7 million on its exploration and evaluation assets as at June 30, 2017. The impairment primarily related to the North West Gharib concession in Egypt. The recoverable amount of the North West Gharib cash-generating unit is $4.4 million. The remaining North West Gharib exploration and evaluation assets were written down to nil as at June 30, 2017. The North West Gharib exploration lands have been fully evaluated and all commitments have been met at the end of the first exploration phase. The Company elected not to enter the second exploration period and has filed development lease applications on its discoveries. The Company has relinquished the remaining exploration lands that are not covered by development lease applications.
The impairment was taken after consideration of the uncertainly of the timing of additional exploration and development on the existing and pending development leases and the current forward outlook for Gharib blend pricing. TransGlobe signed the North West Gharib Production Sharing Agreement ("PSC") (won in the EGPC bid round in 2011/2012) on November 7, 2013. The Company entered into these exploration commitments when the oil price environment was significantly stronger. Brent oil prices averaged between $108 bbl to $112 bbl from 2011 to 2013.

CAPITAL EXPENDITURES
 
Six months ended June 30
 
($000s)
2017

 
2016

Egypt
18,597

 
9,102

Canada
324

 
—

Acquisitions
—

 
—

Corporate
27

 
—

Total
18,948

 
9,102

In Egypt, total capital expenditures in the first six months of 2017 were $18.6 million (2016 - $9.1 million). During the first six months of the year, the Company drilled eight exploration wells and four development wells. Six exploration wells were drilled at NW Gharib resulting in two oil discoveries (NWG 26 and NWG 27) and four dry holes (NWG 28, NWG 39, NWG 40 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 and at West Bakr the K-47 development well was drilled and cased as an Asl A oil well in the South-K field. In addition, the Company drilled two appraisal wells, NWG 3A and NWG 38A. The Company spudded Boraq 5 during the second quarter and was still drilling through the end of the quarter. During the six months ended June 30, 2017 the Company spent $10.5 million in drilling, $4.7 million on seismic acquisition in NW Sitra, $1.8 million on completions and $1.6 million on facilities construction and maintenance.

12
 
Q2-2017
 


OUTSTANDING SHARE DATA
As at June 30, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,638,053 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. TransGlobe’s debt-to-funds flow from operations ratio has deteriorated significantly since late 2014 as a direct result of a continued lower oil price environment. As of June 30, 2017 debt-to-funds flow improved to 7.1 (December 31, 2016 - negative 10.0) as a result of positive 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 table below illustrates TransGlobe’s sources and uses of cash during the periods ended June 30, 2017 and 2016:
Sources and Uses of Cash
 
 
 
 
 
 
Six months ended June 30
 
($000s)
 
2017

 
2016

Cash sourced
 
 
 
 
Funds flow from operations1
 
19,357

 
(804
)
Transfer from restricted cash
 
10,465

 
289

Proceeds from corporate dispositions
 
—

 
—

Increase in long-term debt
 
85,140

 
—

Other
 
387

 
—

 
 
115,349

 
(515
)
Cash used
 
 
 
 
Capital expenditures
 
18,948

 
9,102

Deferred financing costs
 
1,555

 
—

Repayment of convertible debentures
 
73,375

 
—

Repayment of note payable
 
11,041

 
—

Finance costs
 
4,027

 
2,530

Other
 
—

 
1,027

 
 
108,946

 
12,659

 
 
6,403

 
(13,174
)
Changes in non-cash working capital
 
(24,091
)
 
10,572

Increase (decrease) in cash and cash equivalents
 
(17,688
)
 
(2,602
)
Cash and cash equivalents – beginning of period
 
31,468

 
126,910

Cash and cash equivalents – end of period
 
13,780

 
124,308

  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 $41.5 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 June 30, 2017, the Company had a working capital surplus of $60.3 million (December 31, 2016 - deficiency of $16.8 million). The increase to working capital in Q2-2017 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's first cargo lifting of the year was completed in June and proceeds from the lifting were received in July. TransGlobe's second and third tanker-liftings of 2017 are scheduled for September and December. The Company now enjoys a 30-day collection cycle as a result of direct marketing to third party international buyers. Depending on the Company's assessment of the credit of crude cargo buyers, buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings, which has significantly reduced the Company's credit risk profile. As at June 30, 2017, the Company held 1,274,057 barrels of entitlement oil as inventory.
The Company now has a receivable balance of $18.8 million due from EGPC. During the first six months of 2017, the Company sold 606,465 barrels of inventoried entitlement crude oil to EGPC for $25.2 million to cover in-country expenditures. The Company collected $19.9 million of accounts receivable from EGPC during the first six months of 2017.

Q2-2017
 
13
 


At June 30, 2017, the Company had in place a revolving Canadian reserve-based lending facility with ATB totaling C$30.0 million, of which C$13.6 million was drawn on May 16, 2017 to repay the remaining outstanding vendor take-back note balance in full for $C13.6 million ($10.0 million).
As at June 30, 2017, the Company had restricted cash of $7.9 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.
To date, the Company has experienced no difficulties with transferring funds abroad.
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 June 30, 2017, the Company had 1,274,057 barrels of entitlement oil as inventory, which represents approximately seven 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. Through 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. Two additional tanker liftings are currently scheduled for the remainder of 2017, with expected total shipment volumes of 1.5 MMBbl to approximate for 2017, inclusive of the June tanker lifting.
 
 
Six months ended

 
Year ended

(bbls)
 
June 30, 2017

 
December 31, 2016

Product inventory, beginning of period
 
1,265,080

 
923,106

TransGlobe entitlement production
 
1,131,068

 
2,036,483

Tanker liftings
 
(515,626
)
 
(1,694,509
)
EGPC sales
 
(606,465
)
 
—

Product inventory, end of period
 
1,274,057

 
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
 
25,116

 
25,116

 
—

 
—

Long-term debt
 
Yes - Liability
 
83,725

 
—

 
10,094

 
73,631

Note payable
 
Yes - Liability
 
—

 
—

 
—

 
—

Office and equipment leases3
 
No
 
4,130

 
1,908

 
2,222

 
—

Minimum work commitments4
 
No
 
5,129

 
5,129

 
—

 
—

Total
 
 
 
118,100

 
32,153


12,316


73,631

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 June 30, 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 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. The Company received a six month extension to the initial exploration period, extending the initial exploration period to May 7, 2017. The Company completed the initial exploration period work program and met all financial commitments during the second quarter of 2017. The Company elected not to enter the second exploration period and has relinquished the remaining exploration lands that are not covered by the four development lease applications.

14
 
Q2-2017
 


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 were 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 ($5.1 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 June 30, 2017, the Company had expended $4.9 million towards meeting the financial and operating commitment, with the acquisition of 600 km2 of 3-D seismic in 2017.
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 June 30, 2017.
ASSET RETIREMENT OBLIGATION
At June 30, 2017, TransGlobe recorded an asset retirement obligation ("ARO") of $12.8 million (December 31, 2016 - $12.1 million) for the future abandonment and reclamation costs associated with the Harmattan assets in Canada. 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 1.09% and 2.13% 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.
Under the terms of the Production Sharing Contracts TransGlobe is not responsible for ARO in Egypt.
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 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 twelve outstanding derivative commodity contracts as at June 30, 2017 (December 31, 2016 - nil), the fair values of which have been presented as assets on the Condensed Consolidated Interim Balance Sheet.
The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at June 30, 2017:


Q2-2017
 
15
 

Financial Brent Crude Oil Contracts
Transaction Date
 
Period Hedged
 
Contract
 
Volume bbl
 
Sold Swap
US$/bbl
 
Bought Put
US$/bbl
 
Sold Call
US$/bbl
 
Sold Put
US$/bbl
27-Mar-2017
 
Sep 2017
 
Swap
 
425,000
 
51.00
 
—
 
—
 
—
28-Mar-2017
 
Dec 2017
 
Collar
 
300,000
 
—
 
45.00
 
56.00
 
—
7-Apr-2017
 
Mar 2018
 
3-Way Collar
 
250,000
 
—
 
53.00
 
61.15
 
44.00
12-Apr-2017
 
Jun 2018
 
3-Way Collar
 
250,000
 
—
 
54.00
 
63.10
 
45.00
12-Apr-2017
 
Sep 2018
 
3-Way Collar
 
250,000
 
—
 
54.00
 
64.15
 
45.00
12-Apr-2017
 
Dec 2018
 
3-Way Collar
 
250,000
 
—
 
54.00
 
65.45
 
45.00
23-May-2017
 
Jul 2020
 
3-Way Collar
 
50,000
 
—
 
54.00
 
63.45
 
45.00
23-May-2017
 
Aug 2020
 
3-Way Collar
 
50,000
 
—
 
54.00
 
63.45
 
45.00
23-May-2017
 
Sep 2020
 
3-Way Collar
 
50,000
 
—
 
54.00
 
63.45
 
45.00
23-May-2017
 
Oct 2020
 
3-Way Collar
 
50,000
 
—
 
54.00
 
63.45
 
45.00
23-May-2017
 
Nov 2020
 
3-Way Collar
 
50,000
 
—
 
54.00
 
63.45
 
45.00
23-May-2017
 
Dec 2020
 
3-Way Collar
 
50,000
 
—
 
54.00
 
63.45
 
45.00

The Company has agreed with Mercuria the counterparty to the prepayment agreement to enter into further hedges for 800,000 bbls in 2019 and 600,000 bbls in 2020.


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 June 30, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

16
 
Q2-2017