EX-99.3 4 exhibit993.htm EXHIBIT 99.3 Exhibit
 

EXHIBIT 99.3
MANAGEMENT'S DISCUSSION AND ANALYSIS
March 6, 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 message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2016 and 2015, together with the notes related thereto (the "Consolidated Financial Statements"). The Consolidated 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. 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 to the United States Securities and Exchange Commission 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.

2016
 
1
 

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.
DIVIDENDS
The Company suspended its quarterly dividend effective March 8, 2016, and will evaluate its ability to reinstate a dividend program on a quarterly basis. During the year ended December 31, 2015, the Company paid quarterly dividends on its common shares of $0.05 per share for the first three quarters and $0.025 per share for the fourth quarter.
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.  The 2017 production outlook is provided as a range to reflect the firm and contingent budget that has been approved. The bottom end of the range is more reflective of the firm budget and the upper end of the range is more reflective of the 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) includes $40.2 million for Egypt and $16.2 million (C$22.4 million) for Canada.
Egypt
The approved $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 approved $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 approved $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 approved $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:

2
 
2016
 

 
 
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
2016 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%
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 prescribed by IFRS and therefore may not be comparable to similar measures used by other companies.
Reconciliation of funds flow from operations
($000s)
 
2016

 
2015

Cash flow from operating activities
 
(1,065
)
 
77,526

Changes in non-cash working capital
 
(7,296
)
 
(86,428
)
Funds flow from operations1
 
(8,361
)
 
(8,902
)
1  Funds flow from operations does not include interest or financing costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings and
    Comprehensive Income. Cash interest paid is reported as a financing activity on the Consolidated 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.
Finding and development costs/finding, development and net acquisition costs
Finding and development ("F&D") costs and finding, development and net acquisition ("FD&A") costs are measures that are used to evaluate the Company's capital costs associated with adding proved and proved plus probable reserves. F&D costs are calculated as the aggregate of exploration costs, development costs and the change in estimated future development costs divided by the applicable reserve additions. FD&A costs incorporate acquisitions, net of any dispositions in the year. Neither F&D costs nor FD&A costs have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.
Recycle ratio
Recycle ratio is a measure that is used to evaluate the efficiency of the Company's capital program by comparing the cost of finding and developing both proved reserves and proved plus probable reserves with the netback from production. The ratio is calculated by dividing the recycle netback by the proved and proved plus probable finding and development cost on a per Bbl basis. Recycle ratio does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.
Recycle netback
Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Bbl of production. Recycle netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

2016
 
3
 

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.
ASSET ACQUISITION
On December 20, 2016, TransGlobe closed the acquisition of production and working interests in certain facilities in the Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west central Alberta for total consideration of $59.5 million after adjustments. The acquisition was effective December 1, 2016, and was funded by $48.4 million cash from the balance sheet and a 10%, 24-month vendor take back loan of $11.2 million.
The acquisition provides the Company with ~3,000 boepd of production (60% liquids weighted) and total Proved plus Probable reserves of 20.7 million boe. The acquisition met the Company's strategic objective to diversify and expand operations into lower political risk OECD countries with attractive netbacks to support growth in the current oil price environment.


4
 
2016
 

SELECTED ANNUAL INFORMATION
($000s, except per share, price and volume amounts)
 
2016

 
% Change
 
2015

 
% Change
 
2014

 
Operations
 
 
 
 
 
 
 
 
 
 
Average production volumes
 
 
 
 
 
 
 
 
 
 
Crude oil (bbls/d)
 
12,033

 
(17)
 
14,511

 
(10)
 
16,103

NGLs and condensate (bbls/d)
 
34

 
100
 
—

 
—
 
—

Natural gas (mcf/d)
 
230

 
100
 
—

 
—
 
—

Total (boe/d)
 
12,105

 
(17)
 
14,511

 
(10)
 
16,103

Average sales volumes
 


 

 


 

 


Crude oil (bbls/d)
 
11,093

 
(7)
 
11,977

 
(26)
 
16,161

NGLs and condensate (bbls/d)
 
34

 
100
 
—

 
—
 
—

Natural gas (mcf/d)
 
230

 
100
 
—

 
—
 
—

Total (boe/d)
 
11,165

 
(7)
 
11,977

 
(26)
 
16,161

Average realized sales prices
 
 
 
 
 
 
 
 
 
 
Crude oil ($/Bbl)
 
30.05

 
(30)
 
42.93

 
(51)
 
86.99

NGLs and condensate ($/Bbl)
 
17.20

 
100
 
—

 
—
 
—

Natural gas ($/Mcf)
 
1.81

 
100
 
—

 
—
 
—

Total oil equivalent ($/boe)
 
29.94

 
(30)
 
42.93

 
(51)
 
86.99

Inventory (Bbl)
 
1,265,080

 
37
 
923,106

 
100
 
—

Petroleum and natural gas sales
 
122,360

 
(35)
 
187,665

 
(63)
 
513,153

Petroleum and natural gas sales, net of royalties
 
63,134

 
(32)
 
92,212

 
(66)
 
274,594

Cash flow from operating activities
 
(1,065
)
 
(101)
 
77,526

 
(47)
 
146,977

Funds flow from operations1
 
(8,361
)
 
6
 
(8,902
)
 
(107)
 
120,489

- Basic per share
 
(0.12
)
 

 
(0.12
)
 

 
1.61

- Diluted per share2
 
(0.12
)
 

 
(0.12
)
 

 
1.46

Net earnings (loss)
 
(87,665
)
 
17
 
(105,600
)
 
(1,020)
 
11,482

Net earnings (loss) - diluted
 
(87,665
)
 
17
 
(105,600
)
 
(6,347)
 
(1,638
)
- Basic per share
 
(1.21
)
 

 
(1.44
)
 

 
0.15

- Diluted per share
 
(1.21
)
 

 
(1.44
)
 

 
(0.02
)
Dividends paid
 
—

 
(100)
 
12,865

 
(31)
 
18,752

Dividends paid per share
 
—

 
(100)
 
0.175

 
(30)
 
0.25

Total assets
 
406,142

 
(11)
 
455,500

 
(30)
 
654,058

Cash and cash equivalents
 
31,468

 
(75)
 
126,910

 
(10)
 
140,390

Convertible debentures
 
72,655

 
14
 
63,848

 
(8)
 
69,093

Note payable
 
11,162

 
100
 
—

 
—
 
—

Debt-to-funds flow ratio3
 
(10.0
)
 

 
(7.2
)
 

 
0.6

Reserves
 
 
 
 
 
 
 
 
 
 
Total Proved (MMBoe)4
 
29.9

 
71
 
17.5

 
(21)
 
22.1

Total Proved plus Probable (MMBoe)4
 
50.0

 
74
 
28.7

 
(14)
 
33.5

 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  Funds flow from operations per share (diluted) was not impacted by the convertible debentures for the years ended December 31, 2016 and December 31, 2015, as the convertible debentures were not dilutive in these years. Funds flow from operations per share (diluted) prior to the dilutive impact of the convertible debentures was $1.59 for the year ended December 31, 2014.
   3   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 for the trailing
       12 months, and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
      4  As determined by the Company's independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports dated January 18, 2017, January 15, 2016, and January 30, 2015 with effective dates of December 31, 2016, December 31, 2015, and December 31, 2014, respectively. The reports of DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time and National Instrument 51-101.
  5  The 2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).

2016
 
5
 


In 2016 compared with 2015, TransGlobe:
•
Experienced a decrease in petroleum and natural gas sales primarily as a result of a 30% decrease in realized oil prices along with a 7% reduction in sales volumes compared to 2015. The Company's sales price is market driven, and Egypt crude oil is a high sulfur heavy oil which is priced at a discount to Dated Brent. Dated Brent averaged $43.55 per bbl in 2016, which was a reduction of $8.81 per bbl from prior year;
•
Reported a 17% decrease in production volumes as compared to 2015. In early 2016, the Company intentionally reduced development/operations investment as a result of low oil prices. Accordingly, production was in decline for the first half of the year. During the second quarter, the Company finalized a production recovery plan ("PRP") as oil prices were strengthening. The Company executed on the PRP, and achieved a year-end exit rate of 13,800 bopd in Egypt;
•
Reported a net loss of $87.7 million, which includes a $33.4 million non-cash impairment loss on the Company's exploration and evaluation assets. Impairment losses related to the SE Gharib and SW Gharib concessions amounted to $15.2 million and $16.4 million, respectively. The exploration and evaluation assets in these concessions were written down to zero as no commercially viable quantities of oil have been discovered on these lands. The Company also recognized a $7.0 million unrealized non-cash loss on the fair value of the convertible debenture in 2016;
•
Recorded negative funds flow from operations of $8.4 million, which was relatively consistent with prior year. The effect of a $19.1 million decrease in revenues net of royalties and current income taxes was offset by decreased operating expenses ($12.4 million), selling costs ($3.7 million) and cash general and administrative costs ($3.4 million);
•
Acquired producing oil and gas assets in Canada for total consideration of $59.5 million in a transaction that closed on December 20, 2016; and
•
Spent $26.7 million on capital programs, which was funded through the use of working capital.

2016 TO 2015 NET EARNINGS VARIANCES
 
 
 
 
$ Per Share

 
 
 
 
$000s

 
Diluted

 
% Variance

2015 net earnings
 
(105,600
)
 
(1.44
)
 

Cash items
 

 

 

Volume variance
 
(8,532
)
 
(0.13
)
 
6

Price variance
 
(56,773
)
 
(0.79
)
 
54

Royalties
 
36,227

 
0.50

 
(34
)
Expenses:
 
 
 
 
 
 
Production and operating
 
12,373

 
0.17

 
(12
)
Transportation
 
(12
)
 
—

 
—

Selling costs
 
3,682

 
0.05

 
(3
)
Cash general and administrative
 
3,421

 
0.05

 
(3
)
Current income taxes
 
10,028

 
0.14

 
(9
)
Realized foreign exchange gain (loss)
 
405

 
0.01

 
—

Realized derivative gain (loss)
 
(268
)
 
—

 
—

Interest on long-term debt
 
112

 
—

 
—

Other income
 
(10
)
 
—

 
—

Total cash items variance
 
653

 
—

 
(1
)
Non-cash items
 
 
 
 
 
 
Unrealized foreign exchange gain (loss)
 
(15,625
)
 
(0.22
)
 
15

Depletion and depreciation
 
13,698

 
0.19

 
(13
)
Unrealized gain (loss) on financial instruments
 
(412
)
 
(0.01
)
 
—

Impairment loss
 
51,947

 
0.72

 
(49
)
Stock-based compensation
 
369

 
0.01

 
—

Deferred income taxes
 
(33,032
)
 
(0.46
)
 
31

Deferred lease inducement
 
(9
)
 
—

 
—

Loss on disposition
 
252

 
—

 
—

Amortization of deferred financing costs
 
94

 
—

 
—

Total non-cash items variance
 
17,282

 
0.23

 
(16
)
2016 net earnings
 
(87,665
)
 
(1.21
)
 
(17
)
The Company recorded a net loss of $87.7 million in 2016 compared to a net loss of $105.6 million in 2015. Realized sales prices in 2016 averaged $29.94 per boe, which was 30% lower than the 2015 average realized price of $42.93 per bbl. This translated into a negative cash earnings impact of $56.8 million in 2016 as compared to 2015, which was the single largest cash variance. Sales volumes declined 7% year over year, which was due to lower production levels and the timing and size of tanker liftings in Egypt. The sales volume decline resulted in a further negative earnings variance of $8.5 million. The negative volume and price variances were partially offset by corresponding reductions in royalties and current income

6
 
2016
 


taxes, which created a positive earnings variance of $46.3 million in aggregate. Production and operating expenses were reduced in 2016 by $12.4 million, which was the result of decreased oil treating fees, fuel costs and well servicing costs in Egypt. The disposal of the Yemen business unit in late 2015 also contributed significantly to the decrease in production and operating expenses, as the Company incurred $4.7 million of operating costs in Yemen in 2015. Furthermore, the Company added to its crude oil inventory during 2016, resulting in $3.2 million of production and operating costs being capitalized to inventory on a net basis during the year. Selling costs and cash general and administrative expenses decreased by $3.7 million and $3.4 million, respectively, from prior year. All 2016 tanker liftings were sold FOB shipping point, whereas one 2015 lifting was sold CIF (cost, insurance and freight) destination, resulting in significantly lower selling costs in 2016. The decrease in cash general and administrative costs is principally attributable to a reduction in payroll and staffing alignment expenditures, as the Company is now realizing cost savings associated with the structural staffing changes made in 2015.
The largest non-cash earnings variance item from 2016 to 2015 relates to the change from year to year in the impairment loss, which created a positive earnings variance. The Company recorded an impairment loss of $85.4 million on its petroleum properties and goodwill in 2015 as a direct result of the decline in oil prices, compared with a $33.4 million impairment loss in 2016. The 2016 impairment loss related mainly to exploration and evaluation costs at SE Gharib and SW Gharib, where no commercially viable quantities of oil have been discovered. The 2015 impairment loss caused a significant reduction in the accounting basis of the Company's petroleum properties, which resulted in a deferred tax recovery of $36.0 million in 2015, which created a $33.0 million negative earnings variance in the current year. The 2015 impairment loss also created a lower depletable cost base and therefore lower depletion expense in 2016. Furthermore, the Company's Q3-2016 positive reserve revisions created further reductions in depletion expense on the Company's petroleum properties, resulting in a substantial positive earnings variance for the year. The Company experienced a $15.6 million negative variance related to foreign exchange translation, which was mainly caused by the weakening of the Canadian dollar in 2015 versus a more stable Canadian dollar in 2016 comparatively.
BUSINESS ENVIRONMENT
The Company’s financial results are significantly influenced by fluctuations in commodity prices, including oil price differentials. The following table shows select market benchmark prices and foreign exchange rates:
 Average reference prices
 
2016

 
2015

Crude oil
 
 
 
 
Dated Brent average oil price (US$/Bbl)
 
43.55

 
52.36

Edmonton Sweet index (US$/bbl)
 
40.11

 
44.91

Natural gas
 
 
 
 
AECO (C$/mmbtu)
 
2.16

 
2.69

U.S./Canadian Dollar average exchange rate
 
1.3256

 
1.2790


The price of Dated Brent oil averaged 17% lower in 2016 compared with 2015. 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). In Egypt, depending on the contract, the 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 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 $336.5 million from EGPC, reducing the balance due from EGPC to $13.5 million as at December 31, 2016. The Company's credit risk, as it relates to EGPC, has now been reduced due to the significant collections from EGPC combined with the 30-day collection cycle that the Company now enjoys 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.


2016
 
7
 


SELECTED QUARTERLY FINANCIAL INFORMATION
 
 
2016
 
2015
($000s, except per share,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
price and volume amounts)
 
Q-43

 
Q-3

 
Q-2

 
Q-1

 
Q-4

 
Q-3

 
Q-2

 
Q-1

Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average production volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (bbls/d)
 
12,861

 
11,733

 
11,472

 
12,058

 
13,425

 
14,683

 
15,064

 
14,886

NGLs (bbls/d)
 
134

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Natural gas (mcf/d)
 
916

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total (boe/d)
 
13,148

 
11,733

 
11,472

 
12,058

 
13,425

 
14,683

 
15,064

 
14,886

Average sales volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (bbls/d)
 
7,018

 
11,485

 
11,783

 
14,126

 
7,205

 
13,620

 
14,251

 
12,876

NGLs (bbls/d)
 
134

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Natural gas (mcf/d)
 
916

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total (boe/d)
 
7,305

 
11,485

 
11,783

 
14,126

 
7,205

 
13,620

 
14,251

 
12,876

Average realized sales prices
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil ($/Bbl)
 
37.38

 
34.43

 
30.27

 
22.58

 
32.38

 
39.35

 
48.31

 
46.82

NGLs ($/Bbl)
 
12.33

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Natural gas ($/Mcf)
 
1.80

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total oil equivalent ($/boe)
 
36.45

 
34.43

 
30.27

 
22.58

 
32.38

 
39.35

 
48.31

 
46.82

Inventory (Bbl)
 
1,265,080

 
729,403

 
706,577

 
734,872

 
923,106

 
350,869

 
253,325

 
179,730

Petroleum and natural gas sales
 
24,501

 
36,376

 
32,461

 
29,022

 
21,460

 
49,307

 
62,647

 
54,251

Petroleum and natural gas sales, net of royalties
 
5,217

 
20,704

 
19,786

 
17,427

 
3,979

 
24,700

 
33,960

 
29,573

Cash flow from operating activities
 
6,355

 
(14,857
)
 
6,011

 
1,426

 
6,414

 
28,741

 
24,323

 
18,048

Funds flow from operations1
 
(9,904
)
 
2,347

 
2,026

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

 
(3,288
)
Funds flow from operations per share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
- Basic
 
(0.14
)
 
0.03

 
0.03

 
(0.04
)
 
(0.15
)
 
(0.02
)
 
0.09

 
(0.04
)
- Diluted
 
(0.14
)
 
0.03

 
0.03

 
(0.04
)
 
(0.15
)
 
(0.02
)
 
0.09

 
(0.04
)
Net earnings (loss)
 
(33,997
)
 
(25,369
)
 
(12,050
)
 
(16,249
)
 
(35,255
)
 
(46,568
)
 
(12,580
)
 
(11,197
)
Net earnings (loss) - diluted
 
(38,641
)
 
(25,369
)
 
(12,050
)
 
(16,249
)
 
(35,255
)
 
(54,159
)
 
(12,580
)
 
(13,577
)
Net earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
- Basic
 
(0.47
)
 
(0.35
)
 
(0.17
)
 
(0.23
)
 
(0.49
)
 
(0.64
)
 
(0.17
)
 
(0.15
)
- Diluted
 
(0.49
)
 
(0.35
)
 
(0.17
)
 
(0.23
)
 
(0.49
)
 
(0.68
)
 
(0.17
)
 
(0.17
)
Dividends paid
 
—

 
—

 
—

 
—

 
1,805

 
3,594

 
3,703

 
3,763

Dividends paid per share
 
—

 
—

 
—

 
—

 
0.025

 
0.05

 
0.05

 
0.05

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
406,142

 
414,363

 
433,013

 
441,624

 
455,500

 
501,808

 
599,744

 
614,345

Cash and cash equivalents
 
31,468

 
100,405

 
124,308

 
122,031

 
126,910

 
126,874

 
122,961

 
126,101

Convertible debentures
 
72,655

 
74,854

 
70,639

 
66,506

 
63,848

 
65,682

 
74,421

 
65,511

Note payable
 
11,162

 
—

 
—

 
—

 
—

 
—

 
—

 
—

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

 
1.5

 
0.8

  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 (effective December 1, 2016).
During the fourth quarter of 2016, TransGlobe:
•
Reported an increase in production volumes of 12% as compared to Q3-2016, which was primarily a result of the Company's PRP. Production increases were achieved mainly in the West Bakr concession, where a 1,030 bopd increase was achieved quarter over quarter;
•
Did not receive a cargo lifting in Egypt, therefore did not sell any Egyptian entitlement crude oil. This resulted in significantly lower sales and sales volumes as compared to previous quarters, along with a build in crude oil inventory of 0.5 million barrels;
•
Reported a net loss of $34.0 million, which includes an $18.5 million non-cash impairment loss on the Company's exploration and evaluation assets; and
•
Recorded negative funds flow from operations of $9.9 million, mainly because the Company did not sell any Egypt entitlement oil during the quarter.


8
 
2016
 


OPERATING RESULTS AND NETBACK
Daily Volumes, Working Interest before Royalties (Boepd)
Production Volumes
 
 
2016

 
2015

Egypt crude oil (bbls/d)
 
12,015

 
14,466

Yemen crude oil (bbls/d)
 
—

 
45

Canada crude oil (bbls/d)
 
18

 
—

Canada NGLs (bbls/d)
 
34

 
—

Canada natural gas (mcf/d)
 
230

 
—

Total Company (boe/d)
 
12,105

 
14,511


Sales Volumes (excludes volumes held as inventory)
 
 
2016

 
2015

Egypt crude oil (bbls/d)
 
11,075

 
11,935

Yemen crude oil (bbls/d)
 
—

 
42

Canada crude oil (bbls/d)
 
18

 
—

Canada NGLs (bbls/d)
 
34

 
—

Canada natural gas (mcf/d)
 
230

 
—

Total Company (boe/d)
 
11,165

 
11,977


Netback
Consolidated netback
 
 
 
 
 
 
 
 
 
 
2016
 
 
2015
 
(000s, except per Boe amounts)1
 
$

 
$/Boe

 
$

 
$/Bbl

Petroleum and natural gas sales
 
122,360

 
29.94

 
187,665

 
42.93

Royalties and other
 
59,226

 
14.49

 
95,453

 
21.83

Current taxes
 
15,455

 
3.78

 
25,483

 
5.83

Operating expenses
 
40,323

 
9.87

 
52,696

 
12.05

Transportation
 
12

 
—

 
—

 
—

Selling costs
 
875

 
0.21

 
4,557

 
1.04

Netback
 
6,469

 
1.59

 
9,476

 
2.18

1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2016 and December 31, 2015 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2016).
Canada
 
 
 
 
 
 
 
 
 
 
2016
 
 
2015
 
(000s, except per Boe amounts)
 
$

 
$/Boe

 
$

 
$/Boe

Crude oil sales
 
266

 
40.38

 
—

 
—

Natural gas sales
 
152

 
10.83

 
—

 
—

NGL sales
 
214

 
17.20

 
—

 
—

Total sales
 
632

 
19.12

 


 


Royalties
 
132

 
3.99

 
—

 
—

Operating expenses
 
269

 
8.14

 
—

 
—

Transportation
 
12

 
0.36

 
—

 
—

Netback
 
219

 
6.63

 
—

 
—

The Canadian financial information presented in the table above represents 12 days of activity in Canada, following the closing of the Harmattan acquisition on December 20, 2016.

2016
 
9
 

Egypt
 
 
 
 
 
 
 
 
 
 
2016
 
 
2015
 
(000s, except per Bbl amounts)1
 
$

 
$/Bbl

 
$

 
$/Bbl

Oil sales
 
121,728

 
30.03

 
187,055

 
42.94

Royalties
 
59,094

 
14.58

 
95,330

 
21.88

Current taxes
 
15,455

 
3.81

 
25,284

 
5.80

Production and operating expenses
 
40,054

 
9.88

 
48,041

 
11.03

Selling costs
 
875

 
0.22

 
4,557

 
1.05

Netback
 
6,250

 
1.54

 
13,843

 
3.18

1 The Company achieved the netbacks above on sold barrels of oil for the year ended December 31, 2016 and December 31, 2015 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2016).

The netback per Bbl in Egypt decreased 52% in 2016 compared with 2015. The decreased netbacks were principally the result of a 30% reduction in realized oil prices in 2016 compared to 2015, along with a build up of 0.3 million barrels of entitlement crude oil inventory in 2016.
Production and operating expenses decreased by $8.0 million in 2016 compared with 2015. This is principally the result of reduced activity levels combined with the Company's efforts to achieve cost efficiencies in a lower oil price environment. These cost savings have translated to a reduction of 10% on a per Bbl basis despite a 7% decrease in sales volumes in the current year. The most significant cost efficiencies were achieved in the areas of oil treating fees, fuel costs and well servicing. Selling costs were 79% lower on a per Bbl basis in 2016 as compared to 2015, creating a positive impact on current year netbacks. In 2015, one lifting was sold CIF (cost, insurance and freight) destination, resulting in significantly higher selling costs in the prior year. In 2016, all lifting were sold FOB shipping point, which results in significantly lower selling costs.
Royalties and taxes as a percentage of revenue were 61% in 2016 compared with 64% for 2015. 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. 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 for the year-ended December 31, 2016 was $30.03/Bbl, which was $13.52/Bbl lower than the average Dated Brent oil price of $43.55/Bbl for the year (December 31, 2015 - $52.36/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”)
 
 
2016
 
 
2015
 
(000s, except per Bbl amounts)
 
$

 
$/Boe

 
$

 
$/Bbl

G&A (gross)
 
18,716

 
4.58

 
24,466

 
5.60

Stock-based compensation
 
2,418

 
0.59

 
2,787

 
0.64

Capitalized G&A and overhead recoveries
 
(3,579
)
 
(0.88
)
 
(5,917
)
 
(1.35
)
G&A (net)
 
17,555

 
4.29

 
21,336

 
4.89

G&A expenses (net) decreased 18% in 2016 compared with 2015 (12% decrease on a per bbl basis). G&A (gross) has decreased $5.7 million in 2016 principally due to a reduction in payroll and staffing alignment expenditures, as the Company is now realizing cost savings associated with the structural staffing changes made in 2015.
Equity-settled stock-based compensation expense decreased $0.8 million in 2016 as compared to 2015, which is mainly the result of a decrease in the fair value of stock options granted in 2016 as compared to 2015. Cash-settled stock-based compensation increased $0.4 million in 2016 compared to 2015, which is principally due to an increase in the number of cash-settled stock-based compensation units granted during 2016 as compared to 2015, along with the relative weakness in the share price in 2015 as compared to 2016.
FINANCE COSTS
Finance costs for the year ended December 31, 2016 decreased to $6.1 million compared with $6.3 million in 2015. Interest expense on the convertible debentures decreased to $4.4 million in 2016, compared with $4.7 million in 2015. The interest on the convertible debenture is paid in Canadian dollars, and therefore fluctuates from period to period depending on the strength of the Canadian dollar relative to the US dollar.
(000s)
 
2016

 
2015

Interest expense
 
$
5,344

 
$
5,425

Amortization of deferred financing costs
 
724

 
849

Finance costs
 
$
6,068

 
$
6,274

Borrowing Base Facility
In December 2016 the Company terminated its Borrowing Base Facility. There were no amounts outstanding under the Borrowing Base Facility at the time of termination; however, the Company was utilizing approximately $16.0 million in the form of letters of credit to support its exploration commitments in Egypt. The letters of credit outstanding under the borrowing base facility were transferred to a bilateral letter of credit facility with Sumitomo Mitsui Banking Corporation ("SMBC"). The issued letters of credit under the bilateral letter of credit facility are secured by cash collateral which is on deposit with SMBC. The exploration commitments are expected to be fulfilled in 2017.

10
 
2016
 


All remaining deferred financing costs related to the Borrowing Base Facility were expensed at the time of termination of the facility.
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 operating income of the acquired assets.
Convertible Debentures
In February 2012, the Company sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$13.63 per common share. The debentures were not redeemable by the Company on or before March 31, 2015 other than in limited circumstances described below or in connection with a change of control of TransGlobe. The conversion price of the convertible debentures is adjusted for any amounts paid out as dividends on the common shares of the Company. Interest of 6% is payable semi-annually in arrears on March 31 and September 30. At maturity or redemption, the Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations. On October 17, 2016, a meeting of the Company's debenture holders was held to approve certain amendments to the outstanding debentures. The amendments were approved, and TransGlobe was granted the right to redeem all outstanding debentures at any point in time at a price equal to the principal amount outstanding, plus accrued and unpaid interest up to (but excluding) the redemption date, plus an interest penalty equal to interest otherwise due up to but excluding the maturity date.
Subsequent to year-end, the Company entered into a $75 million crude oil prepayment agreement, the proceeds of which are intended to be used to redeem the convertible debentures in full.
DEPLETION AND DEPRECIATION (“DD&A”)
 
 
2016
 
 
2015
 
(000s, except per Bbl amounts)
 
$

 
$/Boe

 
$

 
$/Bbl

Egypt
 
28,386

 
7.00

 
42,366

 
9.73

Canada
 
303

 
9.16

 
—

 
—

Corporate
 
488

 
—

 
509

 
—

 
 
29,177

 
7.14

 
42,875

 
9.81

In Egypt, DD&A decreased 28% on a per Bbl basis in 2016 as compared to 2015. The decrease is primarily related to a lower depletable cost base, which is the result of impairment losses booked in 2015, along with a 57% reduction in future development costs. In addition, the Company's third quarter 2016 positive reserve revisions created further reductions in depletion expense on a per bbl basis.
In Canada, the Company booked depletion for 12 days of production following the closing of the Canadian asset acquisition on December 20, 2016.
IMPAIRMENT OF PETROLEUM PROPERTIES
The Company completed an impairment evaluation on all exploration and evaluation ("E&E") assets as at December 31, 2015. E&E assets are tested for impairment when they are reclassified to petroleum properties and also if facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount. Indications of impairment include:
1.
Expiry or impending expiry of lease with no expectation of renewal;
2.
Lack of budget or plans for substantive expenditures on further E&E;
3.
Discontinuance of E&E activities due to a lack of commercially viable discoveries; and
4.
Carrying amount of E&E asset is unlikely to be recovered in full from a successful development project.
As a result of this assessment, the Company recorded an impairment loss of $33.4 million on its exploration and evaluation assets in 2016. The impairment loss was principally related to the South East Gharib and South West Gharib concessions in Egypt. The impairment loss recognized on these two concessions represented the entire intangible exploration and evaluation asset balances on the concessions. The Company relinquished its interest in South East Gharib in November 2016, and intends to relinquish its interest in South West Gharib in the first half of 2017 as no commercially viable quantities of oil have been discovered on either concession. At South West Gharib, the Company drilled two wells subsequent to year-end, both of which were dry and abandoned. An impairment loss will be recorded in the first quarter of 2017 in an amount equal to the capital costs associated with these wells.
In 2015, The Company recorded an impairment loss of $85.4 million in aggregate on its producing properties and goodwill. The impairment loss recorded on the Company's petroleum properties amounted to $77.2 million, which was split between the West Gharib concession ($50.9 million), the West Bakr concession ($23.1 million) and the East Ghazalat concession ($3.2 million). At West Gharib and West Bakr, the impairment losses were recorded to reduce the carrying value of the assets to their recoverable amounts, which were estimated as the net present value of proved plus probable reserves, discounted at 15%. The recoverable amounts of the assets declined from prior year due to the continued decline in oil prices throughout 2015. The East Ghazalat concession was sold in October 2015, and an impairment loss was booked in Q3-2015 to reduce the carrying amount of the assets to the value being paid for the assets in the disposal transaction. An impairment loss of $8.2 million was recognized on the Company's goodwill balance in 2015. The entire goodwill balance was related to the West Gharib acquisition. This impairment loss reduced the carrying value of goodwill to zero. The after-tax cash flows used to determine the recoverable amount of the cash-generating unit to which goodwill was assigned were discounted using an estimated weighted average cost of capital of 15%.


2016
 
11
 


CAPITAL EXPENDITURES
($000s)
 
2016

 
2015

Egypt
 
26,658

 
44,747

Property acquisitions
 
59,475

 
—

Corporate
 
—

 
155

Total
 
86,133

 
44,902

In Egypt, total capital expenditures in 2016 were $26.7 million (2015 - $44.7 million). The Company drilled 17 wells in Egypt in 2016 (ten at NW Gharib, two at SE Gharib, two at SW Gharib, two at West Bakr and one at West Gharib). The West Bakr and West Gharib wells were development oil wells that formed part of the Company's PRP. The remaining wells were exploration wells, which yielded two new oil discoveries. Workovers contributed $2.2 million to the Company's capital spending, and the Company capitalized $3.6 million of G&A costs related to capital projects.
On December 20, 2016, TransGlobe closed the acquisition of production and working interests in certain facilities in the Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west central Alberta for total consideration of $59.5 million after adjustments. The acquisition was effective December 1, 2016, and was funded by $48.3 million cash from the balance sheet and a 10%, 24-month vendor take back loan of $11.2 million.
FINDING AND DEVELOPMENT COSTS/FINDING, DEVELOPMENT AND NET ACQUISITION COSTS
Finding and development (“F&D”) costs are calculated as the aggregate of exploration costs, development costs and the change in estimated future development costs divided by the applicable reserve additions. Finding, development and acquisition (“FD&A”) costs incorporate acquisitions, net of any dispositions during the year.
Proved
 
 
 
 
 
 
($000s, except volumes and $/Boe amounts)
 
2016

 
2015

 
2014

Total capital expenditures
 
26,658

 
42,902

 
107,539

Acquisitions1
 
59,475

 
2,000

 
—

Dispositions
 
—

 
(1,500
)
 
—

Net change from previous year’s future capital
 
60,084

 
(9,024
)
 
(16,447
)
 
 
146,217

 
34,378

 
91,092

Reserve additions and revisions (MBoe)
 
 
 
 
 
 
Exploration and development
 
5,138

 
990

 
(3,619
)
Acquisitions, net of dispositions
 
11,667

 
(300
)
 
—

Total reserve additions (MBoe)
 
16,805

 
690

 
(3,619
)
Average cost per Boe
 
 
 
 
 
 
F&D2
 
4.02

 
34.22

 
—

FD&A2
 
8.70

 
49.83

 
—

Three-year weighted average cost per Boe
 

 

 

F&D2
 
58.03

 
83.93

 
19.93

FD&A2
 
19.58

 
110.07

 
25.34

1   The 2016 Acquisitions figure consists entirely of acquisition costs on the Canadian assets. The 2015 Acquisitions figure relates to acquisition costs on the NW Sitra concession agreement that was awarded to the Company in the 2014 EGPC bid round and ratified into law in 2015.
  2    In 2014, F&D and FD&A costs were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions, most of which relate to the Company's West Gharib concession (specifically, the Lower Nukhul reserves in the Arta/East Arta fields) and the reclassification of Yemen reserves to contingent resources. The Company did not make sufficient new discoveries to offset the negative technical revisions, resulting in negative F&D and FD&A costs which are meaningless on a per Bbl basis.
Note:
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.


12
 
2016
 

Proved Plus Probable
 
 
 
 
 
 
($000s, except volumes and $/Boe amounts)
 
2016

 
2015

 
2014

Total capital expenditure
 
26,658

 
42,902

 
107,539

Acquisitions1
 
59,475

 
2,000

 
—

Dispositions
 
—

 
(1,500
)
 
—

Net change from previous year’s future capital
 
110,102

 
(30,741
)
 
(21,948
)
 
 
196,235

 
12,661

 
85,591

Reserve additions and revisions (MBoe)
 
 
 
 
 
 
Exploration and development
 
4,906

 
1,498

 
(5,919
)
Acquisitions, net of dispositions
 
20,744

 
(936
)
 
—

Total reserve additions (MBbl)
 
25,650

 
562

 
(5,919
)
Average cost per Boe
 
 
 
 
 
 
F&D2
 
3.66

 
8.03

 
—

FD&A2
 
7.65

 
22.53

 
—

Three-year weighted average cost per Boe
 

 

 

F&D3
 
231.05

 
—

 
30.06

FD&A3
 
14.51

 
—

 
39.10

1   The 2016 Acquisitions figure consists entirely of acquisition costs on the Canadian assets. The 2015 Acquisitions figure relates to acquisition costs on the NW Sitra concession agreement that was awarded to the Company in the 2014 EGPC bid round and ratified into law in 2015.
  2    In 2014, F&D and FD&A costs were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions, most of which relate to the Company's West Gharib concession (specifically, the Lower Nukhul reserves in the Arta/East Arta fields) and the reclassification of Yemen reserves to contingent resources. The Company did not make sufficient new discoveries to offset the negative technical revisions, resulting in negative F&D and FD&A costs which are meaningless on a per Bbl basis.
         3     In 2015, the three-year weighted average F&D and FD&A costs on a 2P basis were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions
               in 2014. The Company did not make sufficient new discoveries to offset the negative technical revisions in 2014, resulting in negative F&D and FD&A costs which are meaningless
               on a per Bbl basis.
Note:
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

RECYCLE RATIO
Recycle Ratio
 
 
Three-Year

 
 
 
 
 
 
Proved
 
Weighted

 
 
 
 
 
 
 
 
Average2

 
2016

 
2015

 
2014

Netback ($/Boe)1
 
5.47

 
(3.12
)
 
(3.12
)
 
17.83

Proved F&D costs ($/Boe)3
 
58.03

 
4.02

 
34.22

 
—

Proved FD&A costs ($/Boe)3
 
19.58

 
8.70

 
49.83

 
—

F&D Recycle ratio4
 
0.09

 
—

 
—

 
—

FD&A Recycle ratio4
 
0.28

 
—

 
—

 
—

1   Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange
    (gain) loss, cash finance costs and current income tax expense per Bbl of production.
  2   The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
  3    In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore, the Company has presented these values as nil.
    4    In 2016 and 2015, recycle ratios were negative as a result of negative netbacks. Negative recycle ratios are meaningless and have therefore been presented as nil. The negative netbacks for 2016 and 2015 were included in the three-year weighted average recycle ratios.

 
 
Three-Year

 
 
 
 
 
 
Proved Plus Probable
 
Weighted

 
 
 
 
 
 
 
 
Average2

 
2016

 
2015

 
2014

Netback ($/Boe)1
 
5.47

 
(3.12
)
 
(3.12
)
 
17.83

Proved plus Probable F&D costs ($/Boe)3
 
231.05

 
3.66

 
8.03

 
—

Proved plus Probable FD&A costs ($/Boe)3
 
14.51

 
7.65

 
22.53

 
—

F&D Recycle ratio4
 
0.02

 
—

 
—

 
—

FD&A Recycle ratio4
 
0.38

 
—

 
—

 
—

 1    Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange
   (gain) loss, cash finance costs and current income tax expense per Bbl of production.
 2   The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
 3    In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore, the Company has presented these values as nil.
     4    In 2016 and 2015, recycle ratios were negative as a result of negative netbacks. Negative recycle ratios are meaningless and have therefore been presented as nil. The negative netbacks for 2016 and 2015 were included in the three-year weighted average ratios.


2016
 
13
 


The 2016 recycle ratio is negative as a result of negative recycle ratio netbacks in the year. The negative netbacks were primarily the result of low oil prices, combined with the fact that the Company did not sell all of its entitlement oil in 2016. Since negative recycle ratios are meaningless, they have been presented as nil in the tables above. However, the 2015 and 2016 negative netbacks were used to calculate the three-year weighted average recycle ratios.
The recycle ratio is calculated by dividing the netback by the proved and proved plus probable finding and development costs on a per Boe basis.
Recycle Netback Calculation
 
 
 
 
 
 
($000s, except volumes and per Boe amounts)
 
2016

 
2015

 
2014

Net earnings
 
(87,665
)
 
(105,600
)
 
11,482

Adjustments for non-cash items:
 
 
 
 
 
 
Depletion, depreciation and amortization
 
29,177

 
42,875

 
51,589

Stock-based compensation
 
2,418

 
2,787

 
5,914

Deferred income taxes
 
(3,009
)
 
(36,041
)
 
(9,813
)
Amortization of deferred financing costs
 
724

 
849

 
1,106

Amortization of deferred lease inducement
 
(95
)
 
(104
)
 
442

Realized (gain) loss on commodity contracts
 
956

 
688

 
—

Unrealized foreign exchange (gain) loss
 
4,292

 
(11,333
)
 
(6,476
)
Unrealized (gain) loss on financial instruments
 
7,027

 
6,615

 
(11,589
)
Impairment loss
 
33,426

 
85,373

 
71,373

Loss on corporate disposal
 
—

 
252

 
—

Other adjustments:
 
 
 
 
 
 
Other revenue
 
—

 
—

 
(9,250
)
Recycle netback1
 
(12,749
)
 
(13,639
)
 
104,778

Sales volumes (MBoe)
 
4,086

 
4,372

 
5,878

Recycle netback per Boe1
 
(3.12
)
 
(3.12
)
 
17.83

1 Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange (gain) loss, interest and current income tax expense per Boe of production.
OUTSTANDING SHARE DATA
As at December 31, 2016, the Company had 72,205,369 common shares issued and outstanding and 6,045,953 stock options issued and outstanding, which are exercisable in accordance with their terms into an equal number of common shares of the Company.
As at March 6, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,995,953 stock options issued and outstanding, which are exercisable in accordance with their terms into an equal number of common shares of the Company.
NORMAL COURSE ISSUER BID
On March 25, 2015, the Toronto Stock Exchange ("TSX") accepted the Company's notice of intention to make a Normal Course Issuer Bid ("NCIB") for its common shares. The NCIB, which commenced on March 31, 2015 and terminated on March 30, 2016, provided the Company with the right to acquire up to 6,207,585 common shares, which was equal to 10% of the public float. During 2015, the Company repurchased and cancelled 3,103,792 common shares under the NCIB. No common shares were repurchased under the NCIB during the year ended December 31, 2016. The Company has not renewed the NCIB.
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 debt. TransGlobe’s capital programs are funded by its existing working capital and cash provided from operating activities. As a direct result of a lower oil price environment, TransGlobe’s debt-to-funds flow from operations ratio continued to deteriorate throughout the year and was negative 10.0 at December 31, 2016 (December 31, 2015 - negative 7.2) as a result of negative funds flow for the year. The Company's debt-to-funds flow from operations ratio will continue to experience downward pressure until oil prices improve. Despite the deterioration of this particular ratio, the Company remains in a relatively strong financial position due to prudent capital resource management. 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.



14
 
2016
 


The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2016 and 2015:
Sources and Uses of Cash
 
 
 
 
($000s)
 
2016

 
2015

Cash sourced
 

 

Funds flow from operations1
 
(8,361
)
 
(8,902
)
Transfer from restricted cash
 
—

 
688

Proceeds from corporate dispositions
 
—

 
1,500

Increase in note payable
 
11,162

 
—

Exercise of options
 
—

 
208

 
 
2,801

 
(6,506
)
Cash used
 
 
 
 
Capital expenditures
 
26,658

 
44,902

Dividends paid
 
—

 
12,865

Transfer to restricted cash
 
17,462

 
—

Property acquisitions
 
59,475

 
—

Purchase of common shares
 
—

 
12,221

Finance costs
 
5,288

 
5,779

Other
 
2,212

 
1,635

 
 
111,095

 
77,402

 
 
(108,294
)
 
(83,908
)
Changes in non-cash working capital
 
12,852

 
70,428

Increase (decrease) in cash and cash equivalents
 
(95,442
)
 
(13,480
)
Cash and cash equivalents – beginning of year
 
126,910

 
140,390

Cash and cash equivalents – end of year
 
31,468

 
126,910

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 cash on hand. The Company expects to fund its 2017 exploration and development program 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.
Working capital is the amount by which current assets exceed current liabilities. At December 31, 2016, the Company had a working capital deficiency of $16.8 million (December 31, 2015 - surplus of $153.8 million). The decrease to working capital in 2016 is principally due to the reclassification of the convertible debt to current liabilities. Since the maturation of the convertible debentures is within one year of the balance sheet date, they must now be presented as current liabilities, which has a significant impact on the Company's working capital balance. Subsequent to year-end, the Company entered into a $75 million crude oil prepayment agreement, the proceeds of which are intended to be used to redeem the convertible debentures in full. Working capital was also significantly impacted by the acquisition of the Harmattan assets, as the Company invested $48.4 million of its cash balance in the transaction.
The Company now has a very manageable receivable balance of $13.5 million due from EGPC, and enjoys a 30-day cash collection cycle on directly marketed crude oil sales to third party international buyers who are generally 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. The Company completed three cargo liftings during 2016, and management has arranged for three liftings in 2017.
As at December 31, 2016, the Company held 1,265,080 barrels of entitlement oil as inventory, which represents approximately seven months of entitlement oil production. All oil produced is delivered to EGPC facilities, and the Company works with EGPC on a continuous basis to schedule tanker liftings. Crude oil inventory levels fluctuate from quarter to quarter depending on the timing and size of tanker liftings in Egypt. 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, 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 (offsets) in 2017, and anticipates that 2017 year-end crude oil inventory will be approximately 700,000 barrels.
To date, the Company has experienced no difficulties with transferring funds abroad (see "Risks").
The Company terminated its Borrowing Base Facility in December 2016. There were no amounts drawn on the Borrowing Base Facility at any time in 2016. Subsequent to year-end, the Company entered into a prepayment agreement, which allows for advances up to $75 million.
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:

2016
 
15
 

($000s)
 
 
 
Payment Due by Period1 2
 
 
Recognized
 
 
 
 
 
 
 
 
 
 
 
 
in Financial
 
Contractual

 
Less than

 
 

 
 

 
More than

 
 
Statements
 
Cash Flows

 
1 year

 
1-3 years

 
4-5 years

 
5 years

Accounts payable and accrued liabilities
 
Yes - Liability
 
24,529

 
24,529

 
—

 
—

 
—

Convertible debentures
 
Yes - Liability
 
72,655

 
72,655

 
—

 
—

 
—

Note payable
 
Yes - Liability
 
11,162

 
5,581

 
5,581

 
—

 
—

Office and equipment leases3
 
No
 
3,732

 
1,200

 
1,556

 
976

 
—

Minimum work commitments4
 
No
 
17,986

 
8,335

 
9,651

 
—

 
—

Total
 
 
 
130,064

 
112,300

 
16,788

 
976

 
—

1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at December 31, 2016 exchange rates.
3 Office and equipment leases include all drilling rig contracts.
4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.
Pursuant to the PSC for North West Gharib in Egypt, the Company has a minimum financial commitment of $35.0 million ($5.0 million remaining) and a work commitment for 30 wells and 200 km2 of 3-D seismic during the initial-three year exploration period, which commenced on November 7, 2013. As at December 31, 2016, the Company had expended $30.0 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, which now extends to May 7, 2017.
Pursuant to the PSC for South East Gharib in Egypt, the Company had a minimum financial commitment of $7.5 million and a work commitment for two wells, 200 km2 of 3-D seismic and 300 kilometers of 2-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company met its financial commitment at South East Gharib in 2016, and relinquished its interest in the concession during the fourth quarter as no commercially viable quantities of oil have been discovered.
Pursuant to the PSC for South West Gharib in Egypt, the Company has a minimum financial commitment of $10.0 million ($3.4 million remaining) and a work commitment for four wells and 200 km2 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, which now extends to May 7, 2017. Since no commercially viable quantities of oil have been discovered at South West Gharib, the Company intends to relinquish its interest in the concession during the first half of 2017. As at December 31, 2016, the Company had expended $6.6 million towards meeting its financial commitment.

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 km2 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 ($9.7 million remaining) and a work commitment for two wells and 300 km2 of 3-D seismic during the initial three and a half year exploration period, which commenced on January 8, 2015. As at December 31, 2016, the Company had expended $0.3 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 December 31, 2016.
ASSET RETIREMENT OBLIGATION
At December 31, 2016, TransGlobe recorded an asset retirement obligation ("ARO") of $12.1 million (2015 - nil) 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 0.74% 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.
OFF BALANCE SHEET ARRANGEMENTS
The Company has certain lease arrangements, all of which are reflected in the Commitments and Contingencies table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the Consolidated Balance Sheet as of December 31, 2016.


16
 
2016
 


RISKS
TransGlobe’s results are affected by a variety of business risks and uncertainties in the international petroleum industry including but not limited to:
•
Financial risks;
•
Market risks (such as commodity price, foreign exchange and interest rates);
•
Credit risks;
•
Liquidity risks;
•
Operational risks including capital, operating and reserves replacement risks;
•
Safety, environmental, social and regulatory risks; and
•
Political risks.
Many of these risks are not within the control of management, but the Company has adopted several strategies to reduce and minimize the effects of these risks:
Financial Risk
Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on TransGlobe.
The Company actively manages its cash position and maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flow from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs.
The frequent political changes that have created instability in Egypt since 2011 could present challenges to the Company if the issues persist over an extended period of time. Continued instability could reduce the Company’s ability to access debt, capital and banking markets. To mitigate potential financial risk factors, the Company maintains a strong liquidity position and management regularly evaluates operational and financial risk strategies and continues to monitor the 2017 capital budget and the Company’s long-term plans. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. Going forward, the Company anticipates that direct sales will continue to reduce financial risk in future periods.
Market Risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The market price movements that the Company is exposed to include commodity prices, foreign currency exchange rates and interest rates, all of which could adversely affect the value of the Company’s financial assets, liabilities and financial results.
Commodity price risk
The Company’s operational results and financial condition are dependent on the commodity prices received for its oil and gas production.
Any movement in commodity prices would have an effect on the Company’s financial condition which could result in the delay or cancellation of drilling, development or construction programs, all of which could have a material adverse impact on the Company. Therefore, the Company uses financial derivative contracts from time to time as deemed necessary to manage fluctuations in commodity prices in the normal course of operations. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.
Foreign currency exchange risk
As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would result in an increase in the net loss for the year ended December 31, 2016 of approximately $8.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the net loss by $6.6 million for the same period. The Company has not utilized derivative instruments to manage this risk.
The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2016 was $3.9 million (2015 - $20.8 million) in equivalent U.S. dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the U.S. dollar would result in a decrease in the net loss for the year ended December 31, 2016 of approximately $0.4 million and conversely a 10% decrease in the value of the Egyptian pound against the U.S. dollar would increase the net loss by $0.4 million for the same period. The Company does not currently utilize derivative instruments to manage this risk.

2016
 
17
 


Interest rate risk
Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable-interest, U.S.-dollar-denominated debt. No derivative contracts were entered into during 2016 to mitigate this risk. When assessing interest rate risk applicable to the Company’s variable-interest, U.S.-dollar-denominated debt the Company believes 1% volatility is a reasonable measure. Since the Company did not have any amounts drawn on its variable-interest, U.S.-dollar-denominated debt at any time in 2016, the effect of interest rates increasing or decreasing by 1% would have no impact on the Company's net earnings for the year ended December 31, 2016.
Credit Risk
Credit risk is the risk of loss if counter-parties do not fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to accounts receivable, the majority of which are in respect of oil and gas operations. The Company is and may in the future be exposed to third-party credit risk through its contractual arrangements with its current or future joint interest partners, marketers of its petroleum production and other parties, including the government of Egypt. Significant changes in the oil and gas industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect the Company’s ability to realize the full value of its accounts receivable. The Company historically has had a significant account receivable outstanding from the Government of Egypt. In the past, the timing of payments on these receivables from the Government of Egypt were historically longer than normal industry standard. Despite these factors, the Company expects to collect this account receivable in full, although there can be no assurance that this will occur. In the event the Government of Egypt fails to meet its obligations, or other third-party creditors fail to meet their obligations to the Company, such failures could individually or in the aggregate have a material adverse effect on the Company, its cash flow from operating activities and its ability to conduct its ongoing capital expenditure program. The Company has not experienced any material credit loss in the collection of accounts receivable to date.
TransGlobe entered into a joint marketing arrangement with EGPC in December 2014. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. Buyers are required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Going forward, the Company anticipates that direct sales will continue to reduce credit risk in future periods.
Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. 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 proved reserves, to acquire strategic oil and gas assets and to repay debt.
The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flows from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs. All of the payments received from the lifting and sale of the Company's entitlement crude oil are deposited directly to its accounts held in London, England.
Crude oil inventory levels fluctuate from quarter to quarter depending on the timing and size of tanker liftings in Egypt. 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, 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.
To date, the Company has experienced no difficulties with transferring funds abroad.
Operational Risk
The Company’s future success largely depends on its ability to exploit its current reserve base and to find, develop or acquire additional oil reserves that are economically recoverable. Failure to acquire, discover or develop these additional reserves will have an impact on cash flows of the Company.
To mitigate these operational risks, as part of its capital approval process, the Company applies rigorous geological, geophysical and engineering analysis to each prospect. The Company utilizes its in-house expertise for all international and domestic ventures or employs and contracts professionals to handle each aspect of the Company’s business. The Company retains independent reserve evaluators to determine year-end Company reserves and estimated future net revenues.
The Company also mitigates operational risks by maintaining a comprehensive insurance program according to customary industry practice, but cannot fully insure against all risks.
Safety, Environmental, Social and Regulatory Risk
To mitigate safety, environmental and social risks, TransGlobe conducts its operations in accordance with the Company's Health, Safety, Environmental, and Social Responsibility Policy to ensure compliance with government regulations and guidelines. Monitoring and reporting programs for environmental health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Security risks are managed through security procedures designed to protect TransGlobe's personnel and assets. The Company has a Whistleblower Protection Policy which protects employees if they raise any concerns regarding TransGlobe's operations, accounting or internal control matters.
Regulatory and legal risks are identified and monitored by TransGlobe's corporate team and external legal professionals to ensure that the Company continues to comply with laws and regulations.


18
 
2016
 


Political Risk
TransGlobe operates in countries with political, economic and social systems which subject the Company to a number of risks that are not within the control of the Company. These risks may include, among others, currency restrictions and exchange rate fluctuations, loss of revenue and property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks, increases in taxes and governmental royalties, changes in laws and policies governing operations of companies, economic and legal sanctions and other uncertainties arising from foreign and domestic governments.
Egypt has been experiencing significant political changes over the past six years and while this has had an impact on the efficient operations of the government in general, business processes and the Company’s operations have generally proceeded as normal. The current government has added stability in the Egyptian political landscape, however, the possibility of future political changes exists. Future political changes could have a negative impact on the Company's operations.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with IFRS requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses.
The following is included in the MD&A to aid the reader in assessing the critical accounting policies and practices of the Company. The information will also aid in assessing the likelihood of materially different results being reported depending on management's assumptions and changes in prevailing conditions which affect the application of these policies and practices. Significant accounting policies are disclosed in Note 3 of the Consolidated Financial Statements.
Oil and Gas Reserves
TransGlobe's Proved and Probable oil and gas reserves are 100% evaluated and reported on by independent reserve evaluators to the Reserves, Health Safety Environment and Social Responsibility Committee comprised of independent directors. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.
Property and equipment and intangible exploration and evaluation assets
Recognition and measurement
E&E costs related to each license/prospect are initially capitalized within "intangible exploration and evaluation assets." Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable expenses, including remuneration of production personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not include pre-licensing costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to earnings as they are incurred and presented as exploration expenses on the Consolidated Statements of Earnings and Comprehensive Income.
Intangible E&E assets are not depleted. They are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. The technical feasibility and commercial viability is considered to be determined when proved and/or probable reserves are determined to exist or they can be empirically supported with actual production data or conclusive formation tests. A review of each CGU is carried out at least annually. Intangible E&E assets are transferred to petroleum properties as development and production ("D&P") assets upon determination of technical feasibility and commercial viability. The intangible E&E assets being transferred to D&P assets are subject to impairment testing upon transfer.
Petroleum properties and other assets are measured at cost less accumulated depletion, depreciation, and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, including qualifying E&E costs on reclassification from intangible E&E assets, and for qualifying assets, where applicable, borrowing costs. When significant parts of an item of property and equipment have different useful lives, they are accounted for as separate items.
Gains and losses on disposal of items of property and equipment are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in earnings immediately.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum properties or other assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in earnings as incurred. Such capitalized property and equipment generally represent costs incurred in developing Proved and/or Probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis.
The carrying amount of any replaced or sold component is derecognized.
Depletion, depreciation and amortization
The depletion, depreciation and amortization of petroleum properties and other assets are recognized in earnings.
The net carrying value of D&P assets included in petroleum properties is depleted using the unit of production method by reference to the ratio of production in the year to the related proved and probable reserves using estimated future prices and costs. Costs subject to depletion include estimated future development costs necessary to bring those reserves into production. These estimates are reviewed by independent reserve engineers at least annually.

2016
 
19
 


Proved and probable reserves are estimated using independent reserve evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially viable. The specified degree of certainty must be a minimum 90% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and a minimum 50% statistical probability for proved and probable reserves to be considered commercially viable.
Furniture and fixtures are depreciated at declining balance rates of 20% to 30%, whereas vehicles and leasehold improvements are depreciated on a straight-line basis over their estimated useful lives.
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
Production Sharing Concessions
International operations conducted pursuant to PSCs are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSCs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSC establishes specific terms for the Company to recover these costs ("Cost Recovery Oil") and to share in the production sharing oil. Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each quarter. Production sharing oil is that portion of production remaining after Cost Recovery Oil and is shared between the joint interest partners and the government of each country, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company's share and is recorded net of royalty payments to government and other mineral interest owners. For the Company's international operations, all government interests, except for income taxes, are considered royalty payments. The Company's revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.
Financial instruments
Non-derivative financial instruments
Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, note payable and convertible debentures. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition non-derivative financial instruments are measured as described below.
Financial assets and liabilities at fair value through profit or loss
An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition, such as cash and cash equivalents and convertible debentures. Financial instruments are designated at fair value through profit or loss if the Company makes purchase and sale decisions based on their fair value in accordance with the Company's documented risk management strategy. Upon initial recognition, any transaction costs attributable to the financial instruments are recognized through earnings when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in earnings.
Other
Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities and restricted cash are measured initially at fair value, then at amortized cost using the effective interest method, less any impairment losses.
Derivative financial instruments
The Company enters into certain financial derivative contracts from time to time in order to reduce its exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, the Company's policy is to classify all financial derivative contracts at fair value through profit or loss and to record them on the Consolidated Balance Sheet at fair value. Attributable transaction costs are recognized in earnings when incurred. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.
Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.
CHANGES IN ACCOUNTING POLICIES
Future changes to accounting policies
As at the date of authorization of the Consolidated Financial Statements the following Standards, which have not yet been applied in the Consolidated Financial Statements, have been issued but are not yet effective:
IFRS 9 (revised) "Financial Instruments: Classification and Measurement"
In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments to replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating

20
 
2016
 


impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. The Company does not currently apply hedge accounting. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company does not expect the adoption of IFRS 9 amendments to have a material effect on its Consolidated Financial Statements.

IFRS 15 "Revenue from Contracts with Customers"
In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, replacing IAS 11 Construction Contracts, IAS 18 Revenue, and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. Disclosure requirements have also been expanded. The new standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. The Company does not expect the adoption of IFRS 9 amendments to have a material effect on its Consolidated Financial Statements.

IFRS 16 "Leases"
In January 2016, the IASB issued IFRS 16 Leases, replacing IAS 17 Leases. IFRS 16 establishes a set of principles that both parties to a contract apply to provide relevant information about leases in a manner that faithfully represents those transactions. The current standard (IAS 17) requires lessees and lessors to classify their leases as either finance leases or operating leases, with separate accounting treatment depending on the classification of the lease. Under the new standard, the accounting treatment associated with an operating lease will no longer exist, and lessees will be required to recognize assets and liabilities associated with all leased items. The new standard is effective for annual periods beginning on or after January 1, 2019. The Company is currently evaluating the impact these amendments may have on its Consolidated Financial Statements.
DISCLOSURE CONTROLS AND PROCEDURES
As of December 31, 2016, an evaluation was carried out under the supervision, and with the participation of the Company's management, including the Chief Executive Officer and Chief Financial Officer, on the effectiveness of the Company's disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that all information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.
Disclosure controls and procedures are defined as controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.
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.
Management has assessed the effectiveness of the Company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission framework on Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as at December 31, 2016. No changes were made to the Company's internal control over financial reporting during the year ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

2016
 
21