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GRAN TIERRA ENERGY INC. - Quarter Report: 2019 June (Form 10-Q)



 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)

 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended June 30, 2019

or
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from __________ to __________
 
Commission file number 001-34018
 
GRAN TIERRA ENERGY INC.
(Exact name of registrant as specified in its charter)
 
Delaware
 
98-0479924
(State or other jurisdiction of incorporation or organization)

 
(I.R.S. Employer Identification No.)

900, 520 - 3 Avenue SW

Calgary,
Alberta
Canada
T2P 0R3
 
 (Address of principal executive offices, including zip code)

(403) 265-3221
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock, par value $0.001 per share
GTE
NYSE American
Toronto Stock Exchange

London Stock Exchange


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.          Yes   No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   
Yes     No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of large accelerated filer, accelerated filer, smaller reporting company, and emerging growth company in Rule 12b-2 of the Exchange Act.  
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
 
 
Emerging growth company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.                                                 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).      Yes No

On August 5, 2019, 380,974,707 shares of the registrant’s Common Stock, $0.001 par value, were issued with 6,516,200 of shares owned by Gran Tierra Energy Inc.

 



Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended June 30, 2019

Table of contents
 
 
 
Page
PART I
Financial Information
 
Item 1.
Financial Statements
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
 
 
 
PART II
Other Information
 
Item 1.
Legal Proceedings
Item 1A.
Risk Factors
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.
Exhibits
SIGNATURES

1



 CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS
 
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “budget”, “objective”, “could”, “should”, or similar expressions or variations on these expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct or that, even if correct, intervening circumstances will not occur to cause actual results to be different than expected. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, sustained or future declines in commodity prices; potential future impairments and reductions in proved reserve quantities and value; our operations are located in South America, and unexpected problems can arise due to guerilla activity and other local conditions; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to raise capital; our ability to identify and complete successful acquisitions; our ability to execute business plans; unexpected delays and difficulties in developing currently owned properties may occur; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; current global economic and credit market conditions may impact oil prices and oil consumption differently than we currently predict, which could cause us to further modify our strategy and capital spending program; those factors set out in Part I, Item 1A “Risk Factors” in our 2018 Annual Report on Form 10-K, as amended (the "2018 Annual Report on Form 10-K"), and in our other filings with the Securities and Exchange Commission (“SEC”). The information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the SEC and, except as otherwise required by the federal securities laws, we disclaim any obligation or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS
 
In this document, the abbreviations set forth below have the following meanings:
 
bbl
barrel
BOE
barrels of oil equivalent
bopd
barrels of oil per day
BOEPD
barrels of oil equivalent per day
Mcf
thousand cubic feet
NAR
net after royalty
 
Sales volumes represent production NAR adjusted for inventory changes. Our oil and gas reserves are reported NAR. Our production is also reported NAR, except as otherwise specifically noted as "working interest production before royalties." Natural gas liquids ("NGLs") volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.





2



PART I - Financial Information

Item 1. Financial Statements
 
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Operations (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
 
2018
 
2019
 
2018
OIL AND NATURAL GAS SALES
(Note 6)
$
157,993

 
$
163,446

 
$
310,558

 
$
301,674

 


 


 


 


EXPENSES
 
 
 
 
 
 
 
Operating
33,733

 
26,732

 
68,516

 
48,508

Workover
12,757

 
8,327

 
19,046

 
12,816

Transportation
4,885

 
6,522

 
12,988

 
13,519

Depletion, depreciation and accretion
51,697

 
46,607

 
114,618

 
86,068

General and administrative
8,641

 
12,202

 
18,237

 
23,362

Severance
270

 
1,011

 
942

 
1,011

Foreign exchange loss (gain)
1,175

 
2,216

 
(1,259
)
 
1,274

Financial instruments (gain) loss (Note 9)
(18,340
)
 
4,768

 
(15,175
)
 
11,714

Interest expense (Note 4)
10,564

 
7,375

 
18,502

 
12,870

 
105,382

 
115,760

 
236,415

 
211,142

 
 
 
 
 
 
 
 
INTEREST INCOME
397

 
610

 
530

 
1,396

INCOME BEFORE INCOME TAXES
53,008

 
48,296

 
74,673

 
91,928

 
 
 
 
 
 
 
 
INCOME TAX EXPENSE
 
 
 
 
 
 
 
Current (Note 7)
(489
)
 
4,827

 
10,874

 
17,116

Deferred (Note 7)
14,957

 
23,169

 
23,280

 
36,651


14,468

 
27,996

 
34,154

 
53,767

NET AND COMPREHENSIVE INCOME
$
38,540

 
$
20,300

 
$
40,519

 
$
38,161

 
 
 
 
 
 
 
 
NET INCOME PER SHARE
 
 
 
 
 
 
 
  - BASIC
$
0.10

 
$
0.05

 
$
0.11

 
$
0.10

  - DILUTED
$
0.10

 
$
0.05

 
$
0.10

 
$
0.10

WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)
379,942,355

 
391,054,204

 
383,491,798

 
391,173,460

WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)
415,756,748

 
427,455,092

 
419,306,907

 
427,242,014


(See notes to the condensed consolidated financial statements)

3



Gran Tierra Energy Inc.
Condensed Consolidated Balance Sheets (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
 
As at June 30, 2019
 
As at December 31, 2018
 
 
 
 
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents (Note 10)
$
147,712

 
$
51,040

Restricted cash and cash equivalents (Note 10)
699

 
1,269

Accounts receivable
38,286

 
26,177

Investment (Note 9)
53,308

 
32,724

Taxes receivable
87,297

 
78,259

Other assets
13,268

 
13,056

Total Current Assets
340,570

 
202,525

 
 
 
 
Oil and Gas Properties
 

 
 

Proved
992,187

 
853,428

Unproved
502,770

 
456,598

Total Oil and Gas Properties
1,494,957

 
1,310,026

Other capital assets
5,931

 
2,751

Total Property, Plant and Equipment
1,500,888

 
1,312,777

 
 
 
 
Other Long-Term Assets
 

 
 

Deferred tax assets
46,213

 
45,437

Investment (Note 9)
6,181

 
8,711

Taxes receivable
30,814

 

Other
4,581

 
4,553

Goodwill
102,581

 
102,581

Total Other Long-Term Assets
190,370

 
161,282

Total Assets
$
2,031,828

 
$
1,676,584

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 

 
 

Current Liabilities
 

 
 

Accounts payable and accrued liabilities
$
184,525

 
$
154,670

Derivatives (Note 9)
413

 
1,017

Taxes payable
59

 
4,149

  Equity compensation award liability (Note 5)
4,189

 
9,544

Total Current Liabilities
189,186

 
169,380

 
 
 
 
Long-Term Liabilities
 

 
 

Long-term debt (Notes 4 and 9)
692,558

 
399,415

Deferred tax liabilities
47,053

 
23,419

Asset retirement obligation
43,974

 
43,676

  Equity compensation award liability (Note 5)
4,397

 
8,139

Other
7,728

 
2,805

Total Long-Term Liabilities
795,710

 
477,454

 
 
 
 
Contingencies (Note 8)


 


 
 
 
 
Shareholders’ Equity
 

 
 

Common Stock (Note 5) (380,974,707 and 387,079,027 shares issued; 376,636,307 and 387,079,027 shares outstanding of Common Stock par value $0.001 per share, as at June 30, 2019, and December 31, 2018, respectively)
10,285

 
10,290

Additional paid in capital
1,295,106

 
1,318,048

Deficit
(258,459
)
 
(298,588
)
Total Shareholders’ Equity
1,046,932

 
1,029,750

Total Liabilities and Shareholders’ Equity
$
2,031,828

 
$
1,676,584

(See notes to the condensed consolidated financial statements)


4



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)
 
Six Months Ended June 30,
 
2019
 
2018
Operating Activities
 
 
 
Net income
$
40,519

 
$
38,161

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 

Depletion, depreciation and accretion
114,618

 
86,068

Deferred tax expense
23,280

 
36,651

Stock-based compensation (Note 5)
1,100

 
10,202

Amortization of debt issuance costs (Note 4)
1,785

 
1,513

Unrealized foreign exchange (gain) loss
(1,109
)
 
831

Financial instruments (gain) loss (Note 9)
(15,175
)
 
11,714

Cash settlement of financial instruments
(1,345
)
 
(15,483
)
Cash settlement of asset retirement obligation
(510
)
 
(369
)
Non-cash lease expenses
894

 

Lease payments
(848
)
 

Cash settlement of restricted share units

 
(360
)
Net change in assets and liabilities from operating activities (Note 10)
(70,194
)
 
(37,994
)
Net cash provided by operating activities
93,015

 
130,934

 
 
 
 
Investing Activities
 

 
 

Additions to property, plant and equipment
(194,084
)
 
(157,088
)
Property acquisitions, net of cash acquired (Note 3)
(77,772
)
 
(3,100
)
Changes in non-cash investing working capital
11,116

 
(6,142
)
Net cash used in investing activities
(260,740
)
 
(166,330
)
 
 
 
 
Financing Activities
 

 
 

Proceeds from bank debt, net of issuance costs
163,000

 
4,988

Repayment of bank debt
(163,000
)
 
(153,000
)
  Repurchase of shares of Common Stock (Note 5)
(23,951
)
 
(1,208
)
Proceeds from exercise of stock options

 
845

Proceeds from issuance of Senior Notes, net of issuance costs
289,117

 
288,087

Net cash provided by financing activities
265,166

 
139,712

 
 
 
 
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents
(1,073
)
 
(69
)
 
 
 
 
Net increase in cash, cash equivalents and restricted cash and cash equivalents
96,368

 
104,247

Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 10)
54,308

 
26,678

Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 10)
$
150,676

 
$
130,925

 
 
 
 
Supplemental cash flow disclosures (Note 10)
 

 
 


(See notes to the condensed consolidated financial statements)

5



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands of U.S. Dollars)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
2018
 
2019
2018
Share Capital
 
 
 
 
 
Balance, beginning of period
$
10,287

$
10,295

 
$
10,290

$
10,295

Issuance of Common Stock


 


Repurchase and cancellation of Common Stock (Note 5)
(2
)

 
(5
)

Balance, end of period
10,285

10,295

 
10,285

10,295

 
 
 
 
 
 
Additional Paid in Capital
 
 
 
 

 

Balance, beginning of period
1,312,371

1,326,687

 
1,318,048

1,327,244

Exercise of stock options

771

 

845

Treasury Stock, at cost (Note 5)
(9,267
)

 
(9,267
)

Stock-based compensation (Note 5)
529

593

 
1,003

1,156

Repurchase and cancellation of Common Stock (Note 5)
(8,527
)
(14
)
 
(14,678
)
(1,208
)
Balance, end of period
1,295,106

1,328,037

 
1,295,106

1,328,037

 
 
 
 
 
 
Deficit
 
 
 
 

 

Balance, beginning of period
(296,999
)
(383,343
)
 
(298,588
)
(401,204
)
Net income
38,540

20,300

 
40,519

38,161

  Cumulative adjustment for accounting change related to leases (Note 2)


 
(390
)

Balance, end of period
(258,459
)
(363,043
)
 
(258,459
)
(363,043
)
 
 
 
 
 
 
Total Shareholders’ Equity
$
1,046,932

$
975,289

 
$
1,046,932

$
975,289


(See notes to the condensed consolidated financial statements)


6



Gran Tierra Energy Inc.
Notes to the Condensed Consolidated Financial Statements (Unaudited)
(Expressed in U.S. Dollars, unless otherwise indicated)
 
1. Description of Business
 
Gran Tierra Energy Inc., a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on oil and natural gas exploration and production in Colombia and Ecuador.

2. Significant Accounting Policies
 
These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2018, included in the Company’s 2018 Annual Report on Form 10-K.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2018 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as noted below. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

Recently Adopted Accounting Pronouncements

Leases

The Company adopted Accounting Standard Codification ("ASC") 842 Leases with a date of initial application on January 1, 2019 in accordance with the modified retrospective transition approach using the practical expedients available for land easements and short-term leases. The Company did not elect the "suite" of practical expedients or use the hindsight expedient in its adoption.

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At inception of a contract that contains a lease component, the Company allocates the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, and subsequently at cost less any accumulated depreciation and impairment losses, and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.

The Company has applied judgment to determine the lease term for contracts which include renewal or termination options. The assessment of whether the Company is reasonably certain to exercise such options impacts the lease term, which significantly affects the amount of lease liabilities and right-of-use assets recognized.

All leases identified relate to office leases.

The transition resulted in the recognition of a right-of-use asset presented in other capital assets of $3.8 million at January 1, 2019, the recognition of lease liabilities of $4.2 million and a $0.4 million impact on retained earnings. When measuring the lease liabilities, the Company's incremental borrowing rate was used. At January 1, 2019 the rates applied ranged between 5.6% and 9.1%.


7



3. Property, Plant and Equipment

On February 20, 2019, the Company acquired 36.2% working interest ("WI") in the Suroriente Block and a 100% WI of the Llanos-5 Block for cash consideration of $79.1 million and a promissory note of $1.5 million included in current accounts payable on the Company's condensed consolidated balance sheet. The cost of the assets was allocated to proved properties using relative fair values. The entire consideration of $0.3 million for Llanos-5 was allocated to unproved properties.

(Thousands of U.S. Dollars)
 
Cost of asset acquisition:
 
Cash
$
79,100

Promissory note
1,500

 
$
80,600

 
 
Allocation of Consideration Paid:
 
Oil and gas properties
 
  Proved
$
52,496

  Unproved
44,739

 
97,235

Net working capital (including cash acquired of $5.3 million)
(16,635
)
 
$
80,600




4. Debt and Debt Issuance Costs

The Company's debt at June 30, 2019 and December 31, 2018 was as follows:
(Thousands of U.S. Dollars)
As at June 30, 2019
 
As at December 31, 2018
6.25% Senior notes
$
300,000

 
$
300,000

7.75% Senior notes
300,000

 

Convertible notes
115,000

 
115,000

Unamortized debt issuance costs
(24,683
)
 
(15,585
)
Long-term debt
690,317

 
399,415

Long-term lease obligation(1)
2,241

 

 
$
692,558

 
$
399,415



(1) The current portion of the lease obligation has been included in accounts payable and totaled $2.2 million as at June 30, 2019 (December 31, 2018 - nil).

Senior Notes

On May 20, 2019, the Company, issued $300 million of 7.75% Senior Notes due 2027 (the "7.75% Senior Notes"). The 7.75% Senior Notes are fully and unconditionally guaranteed by certain subsidiaries of the Company that guarantee its revolving credit facility. Net proceeds from the issue of the 7.75% Senior Notes were $289 million, after deducting the initial purchasers' discounts and commission and the offering expenses payable by the Company.

The 7.75% Senior Notes bear interest at a rate of 7.75% per year, payable semi-annually in arrears on May 23 and November 23 of each year, beginning on November 23, 2019. The Senior Notes will mature on May 23, 2027, unless earlier redeemed or repurchased.

Before May 23, 2023, the Company may, at its option, redeem all or a portion of the 7.75% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a “make-whole” premium. Thereafter, the Company may redeem all or a portion of the 7.75% Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2023 - 103.875%; 2024 - 101.938%; 2025 and thereafter - 100%.

8




Convertible Notes

On July 17, 2019, pursuant to a previously announced offer to purchase for cash all outstanding Convertible Notes, the Company purchased and canceled $114,997,000 aggregate principal amount of Convertible Notes at a purchase price of $1,075 in cash per $1,000 principal amount of Convertible Notes plus $1.6 million of accrued and unpaid interest outstanding on such Convertible Notes up to, but not excluding the date of purchase. After giving effect to the purchase and cancellation of the Convertible Notes, $3,000 aggregate principal amount of Convertible Notes remain outstanding.

Interest Expense

The following table presents total interest expense recognized in the accompanying interim unaudited condensed consolidated statements of operations:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Contractual interest and other financing expenses
$
9,617

$
6,532

 
$
16,717

$
11,357

Amortization of debt issuance costs
947

843

 
1,785

1,513

 
$
10,564

$
7,375

 
$
18,502

$
12,870



5. Share Capital
 
 
Shares of Common Stock
Balance, December 31, 2018
387,079,027

Shares repurchased and canceled
(6,104,320
)
Balance, June 30, 2019
380,974,707



In Q1 2019, the Company implemented a share repurchase program (the “2019 Program”) through the facilities of the Toronto Stock Exchange ("TSX") and eligible alternative trading platforms in Canada. Under the 2019 Program, the Company is able to purchase at prevailing market prices up to 19,353,951 shares of Common Stock, representing approximately 5.00% of the issued and outstanding shares of Common Stock as of March 1, 2019. The 2019 Program will expire on March 12, 2020, or earlier if the 5.00% share maximum is reached.

During the three and six months ended June 30, 2019, the Company repurchased 7,856,425 and 10,442,720 shares at a weighted average prices of $2.27 and $2.29, respectively. Of the shares repurchased, 743,520 shares at a weighted average price of $2.34 were repurchased under 2018 share repurchase program and 4,338,400 shares at a weighted average price of $2.14 have not been canceled by the Company and were designated as treasury stock as at June 30, 2019.

Equity Compensation Awards
 
The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), and stock option activity for the six months ended June 30, 2019:

9



 
PSUs
DSUs
 
Stock Options
 
Number of Outstanding Share Units
Number of Outstanding Share Units
 
Number of Outstanding Stock Options
Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2018
9,004,661

684,893

 
9,034,412

3.18

Granted
5,039,365

189,188

 
2,315,006

2.29

Exercised
(2,725,877
)

 


Forfeited
(574,010
)

 
(885,956
)
3.89

Expired


 
(89,940
)
4.94

Balance, June 30, 2019
10,744,139

874,081

 
10,373,522

2.90



For the three and six months ended June 30, 2019, stock-based compensation recovery and expense was $0.6 million and $1.1 million, respectively (three and six months ended June 30, 2018 - $6.9 million and $10.2 million, respectively, of expense).

At June 30, 2019, there was $12.3 million (December 31, 2018 - $9.2 million) of unrecognized compensation cost related to unvested PSUs and stock options which is expected to be recognized over a weighted average period of 1.7 years. During the six months ended June 30, 2019, the Company paid out $10.2 million (six months ended June 30, 2018 - nil) for performance share units which were vested December 31, 2018.

Net Income per Share

Basic net income per share is calculated by dividing net income by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income per share is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock awards were vested at the end of the applicable period plus potentially issuable shares on conversion of the convertible notes. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

Weighted Average Shares Outstanding
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
2018
 
2019
2018
Weighted average number of common and exchangeable shares outstanding
379,942,355

391,054,204

 
383,491,798

391,173,460

Shares issuable pursuant to stock options

4,894,633

 
126,325

2,420,509

Shares assumed to be purchased from proceeds of stock options

(4,308,138
)
 
(125,609
)
(2,166,348
)
Shares issuable pursuant to convertible notes
35,814,393

35,814,393

 
35,814,393

35,814,393

Weighted average number of diluted common and exchangeable shares outstanding
415,756,748

427,455,092

 
419,306,907

427,242,014


 
For the three and six months ended June 30, 2019, 10,373,522 and 9,945,406 options, respectively (three and six months ended June 30, 2018 - 5,240,018 and 7,385,714, respectively), on a weighted average basis, were excluded from the diluted income per share calculation as the options were anti-dilutive. Subsequent to period end, the Convertible Notes were purchased and subsequently canceled.

6. Revenue

The Company's revenues are generated from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to ICE Brent and adjusted for Vasconia or Castilla crude differentials, quality, and transportation discounts each month. For the three and six months ended June 30, 2019, 100% (three and six months ended June 30, 2018 - 100%) of the Company's revenue resulted from oil sales. During the three and six months

10



ended June 30, 2019, quality and transportation discounts were 13% and 15%, respectively, of the average ICE Brent price (three and six months ended June 30, 2018 - 14% and 15%, respectively). During the three and six months ended June 30, 2019, the Company's production was sold primarily to three major customers in Colombia (three and six months ended June 30, 2018 - three).

As at June 30, 2019, accounts receivable included $3.0 million of accrued sales revenue related to June 2019 production (December 31, 2018 - $4.2 million related to December 31, 2018 production).

7. Taxes

The Company's effective tax rate was 46% for the six months ended June 30, 2019, compared to 58% in the comparative period of 2018. Current income tax expense was lower in the six months ended June 30, 2019, compared with the corresponding period of 2018, primarily as a result of lower Colombian income and higher tax depreciation in Colombia. The deferred income tax expense of $23.3 million was lower in the six months ended June 30, 2019, compared to the corresponding period of 2018 primarily due to lower excess tax depreciation compared with accounting depreciation in Colombia, a reduction in the Colombian tax rate and a reduction to the valuation allowance in Colombia.

For the six months ended June 30, 2019, the difference between the effective tax rate of 46% and the 33% Colombian tax rate was primarily due to foreign currency translation adjustments and an increase in the valuation allowance.

For the comparative period in 2018, the 58% effective tax rate differed from the Colombian tax rate of 37% primarily due to the impact of foreign tax rates, stock based compensation, foreign currency translation adjustments and an increase in the valuation allowance.



11



8. Contingencies

Legal Proceedings
 
The Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) ("ANH") and Gran Tierra are engaged in ongoing discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of an additional royalty (the "HPR royalty"). Based on the Company's understanding of the ANH's position, the estimated compensation, which would be payable if the ANH’s interpretation is correct, could be up to $55.6 million as at June 30, 2019 (December 31, 2018 - $56.3 million). At this time no amount has been accrued in the interim unaudited condensed consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

In addition to the above, the Company has a number of other lawsuits and claims pending. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, the Company believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Gran Tierra records costs associated with these lawsuits and claims as they are incurred or become probable and determinable.

Letters of credit and other credit support

At June 30, 2019, the Company had provided letters of credit and other credit support totaling $122.5 million (December 31, 2018 - $76.7 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts and other capital or operating requirements.

9. Financial Instruments and Fair Value Measurement

Financial Instruments

At June 30, 2019, the Company’s financial instruments recognized in the balance sheet consisted of: cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; investment; accounts payable and accrued liabilities, derivatives, long-term debt, equity compensation award liability and other long-term liabilities.

Fair Value Measurement

The fair value of investment, derivatives and PSU liability is remeasured at the estimated fair value at the end of each reporting period.

The fair value of the short-term portion of the Company's investment in PetroTal Corp. ("PetroTal"), which was received on the sale of the Company's Peru business unit, was estimated using quoted prices at June 30, 2019, and the foreign exchange rate at that date. PetroTal is a publicly-traded energy company incorporated and domiciled in Canada engaged in exploration, appraisal and development of crude oil and natural gas in Peru, South America. PetroTal's shares are listed on the Toronto Stock Exchange Venture under the trading symbol 'TAL' and on the London Stock Exchange under the trading symbol 'PTAL'. Gran Tierra directly and indirectly holds approximately 246 million common shares representing approximately 37% of PetroTal's issued and outstanding common shares. Gran Tierra has the right to nominate two directors to the board of PetroTal. The fair value of the long-term portion of the investment restricted by escrow conditions was estimated using observable and unobservable inputs; factors that were evaluated included quoted market prices, precedent comparable transactions, risk free rate, measures of market risk volatility, estimates of the Company's and PetroTal’s cost of capital and quotes from third parties.

The fair value of commodity price and foreign currency derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

The fair value of the PSU liability was estimated based on option pricing model using inputs such as quoted market prices in an active market, and PSU performance factor.

The fair value of investment, derivatives and equity compensation award liability (PSU and DSU) at June 30, 2019, and December 31, 2018, was as follows:

12



(Thousands of U.S. Dollars)
As at June 30, 2019
 
As at December 31, 2018
Investment - current and long-term
$
59,489

 
$
41,435

Derivative asset
857

 

 
60,346

 
41,435

 
 
 
 
Derivative liability
$
413

 
$
1,017

PSU and DSU liability
8,586

 
17,683

 
$
8,999

 
$
18,700



The following table presents gains or losses on financial instruments recognized in the accompanying interim unaudited condensed consolidated statements of operations:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Commodity price derivative (gain) loss
$
(706
)
$
14,461

 
$
488

$
19,455

Foreign currency derivatives loss (gain)
55

1,945

 
55

(2,024
)
Investment gain
(17,689
)
(11,638
)
 
(15,718
)
(5,717
)
Financial instruments (gain) loss
$
(18,340
)
$
4,768

 
$
(15,175
)
$
11,714



Investment gain for the three and six months ended June 30, 2019, was related to the fair value gain on the PetroTal shares Gran Tierra received in connection with the sale of its Peru business unit in December 2017. For the three and six months ended June 30, 2019 and 2018, this investment gain was unrealized.

Financial instruments not recorded at fair value include the Company's 6.25% Senior Notes due 2025 (the "6.25% Senior Notes") and 7.75% Senior Notes and the Convertible Notes. At June 30, 2019, the carrying amounts of the 6.25% Senior Notes, the 7.75% Senior Notes and the Convertible Notes were $290.0 million, $289.2 million and $112.7 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $280.5 million, $294.8 million and $123.6 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.

At June 30, 2019, the fair value of the current portion of the investment and DSU liability was determined using Level 1 inputs, the fair value of derivatives and PSUs was determined using Level 2 inputs and the fair value of the long-term portion of the investment restricted by escrow conditions was determined using Level 3 inputs. The table below presents the fair value of the long-term portion of the investment:
 
Six Months Ended
 
Year Ended
(Thousands of U.S. Dollars)
June 30, 2019
 
December 31, 2018
Opening balance, investment - long-term
$
8,711

 
$
19,147

Transfer from long-term (Level 3) to current (Level 1)
(4,352
)
 
(10,522
)
Unrealized valuation gain
1,394

 
846

Unrealized foreign exchange gain (loss)
428

 
(760
)
Closing balance, investment - long-term
$
6,181

 
$
8,711



With all other variables held constant, a $0.01 change in the CAD price of PetroTal shares would result in a $1.9 million change in the total investment in PetroTal as at June 30, 2019.

13




The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s Senior Notes, Convertible Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure above regarding the fair value of the Convertible Notes was determined using Level 2 inputs based on the indicative pricing published by certain third-party services or trading levels of the Convertible Notes, which are not listed on any securities exchange or quoted on an inter-dealer automated quotation system. The disclosure in the paragraph above regarding the fair value of cash and restricted cash and cash equivalents, revolving credit facility and Senior Notes was based on Level 1 inputs.

The Company’s non-recurring fair value measurements include asset retirement obligations. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. The significant level 3 inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free interest rate, inflation rates and estimated dates of abandonment. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets.

Commodity Price Derivatives

The Company utilizes commodity price derivatives to manage the variability in cash flows associated with the forecasted sale of its oil production, reduce commodity price risk and provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.

At June 30, 2019, the Company had outstanding commodity price derivative positions as follows:
Period and type of instrument
Volume,
bopd
Reference
Purchased Put ($/bbl, Weighted Average)
Sold Call ($/bbl, Weighted Average)
Premium ($/bbl, Weighted Average)
Purchased Puts: July 1, to December 31, 2019
5,000

ICE Brent
$
60.00

n/a

$
2.39

Collars: July 1, to December 31, 2019
5,000

ICE Brent
$
60.00

$
71.53

n/a



Foreign Currency Derivatives

The Company utilizes foreign currency derivatives to manage the variability in cash flows associated with the Company's forecasted Colombian peso ("COP") denominated expenses. Subsequent to June 30, 2019, the Company entered into foreign currency derivative positions as follows:
Period and type of instrument
Amount Hedged
(Millions COP)
U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)
Reference
Floor Price
(COP, Weighted Average)
Cap Price (COP, Weighted Average)
Collars: July 1, to December 31, 2019
135,000

42,109

COP
3,019

3,446


(1) At June 30, 2019 foreign exchange rate.


10. Supplemental Cash Flow Information

The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company's interim unaudited condensed consolidated balance sheet that sum to the total of the same such amounts shown in the interim unaudited condensed consolidated statements of cash flows:


14



(Thousands of U.S. Dollars)
As at June 30,
 
As at December 31,
 
2019
2018
 
2018
2017
Cash and cash equivalents
$
147,712

$
125,807

 
$
51,040

$
12,326

Restricted cash and cash equivalents - current
699

2,836

 
1,269

11,787

Restricted cash and cash equivalents -
long-term (included in other long-term assets)
2,265

2,282

 
1,999

2,565

 
$
150,676

$
130,925

 
$
54,308

$
26,678



Net changes in assets and liabilities from operating activities were as follows:
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
 
2018
Accounts receivable and other long-term assets
$
(7,465
)
 
$
(11,723
)
Derivatives
(659
)
 
3,431

Inventory
(1,387
)
 
(3,054
)
Prepaids
870

 
(301
)
Accounts payable and accrued and other long-term liabilities
(18,841
)
 
971

Taxes receivable and payable
(42,712
)
 
(27,318
)
Net changes in assets and liabilities from operating activities
$
(70,194
)
 
$
(37,994
)


The following table provides additional supplemental cash flow disclosures:

 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
 
2018
Cash paid for income taxes
$
29,339

 
$
21,032

Cash paid for interest
$
13,545

 
$
3,788

 
 
 
 
Non-cash investing activities:
 
 
 
Net liabilities related to property, plant and equipment, end of period
$
96,320

 
$
62,009



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion of our financial condition and results of operations should be read in conjunction with the "Financial Statements" as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q as well as the "Financial Statements and Supplementary Data" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in Part II, Items 8 and 7, respectively, of our 2018 Annual Report on Form 10-K. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements, as well as Part I, Item 1A “Risk Factors” in our 2018 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the second quarter of 2019

Net after royalties production ("NAR") was 29,193 BOEPD, 4% higher than the second quarter of 2018. Production increased largely due to production from development activities in the Acordionero Field, a decrease in royalties driven by lower oil prices and the acquisition of additional working interest ("WI") in Suroriente Block
The production increases were partially offset by the temporary suspension of Suroriente production due to community blockades from June17 through July 9, 2019, and, starting late May 2019, downtime from ESP failures in Acordionero and the temporary shut-in of two large producers in Acordionero with high gas oil ratio ("GOR"). The successful commissioning of water injection facilities in Acordionero in July 2019 and associated increase in water injection is

15



expected to reduce the GOR in the field and the planned transition to gas to power in August 2019 is expected to reduce ESP failures due to unreliable power. Both activities in Acordionero are expected to allow us to restore production in the coming months
Oil and natural gas sales volumes were 29,277 BOEPD, 5% higher than the second quarter of 2018. The quarter's increase in oil and gas sales volumes was due to the reduction of inventory
Net income was $38.5 million compared with $20.3 million in the second quarter of 2018
Funds flow from operations(2) decreased by 7% to $88.3 million compared with the second quarter of 2018, while Brent price decreased 9% from the second quarter of 2018
EBITDA(2) was $115.3 million compared with $102.3 million in the second quarter of 2018
Q2 2019 was an active quarter with capital expenditures of $99.6 million
Oil and gas sales per BOE were $59.30, 8% lower than the second quarter of 2018
Operating netback(2) per BOE was $40.02 for the second quarter 2019
Operating expenses per BOE were $12.66, 20% higher than the second quarter of 2018 as a result of higher power generation, field operations maintenance and equipment rental costs
Workover expenses per BOE were $4.79, 46% higher compared to the second quarter of 2018 as a result of submersible pump failures during the second quarter of 2019
Quality and transportation discount per BOE was $9.02 compared with $10.53 in the second quarter of 2018; this $1.51 per BOE reduction resulted from renegotiation of several sales agreements which use Castilla differential and smaller fixed discount during the second quarter of 2019 opposed to using Vasconia and higher fixed discount in the sales agreements during the second quarter of 2018
Transportation expenses per BOE were $1.83, compared to $2.57 per BOE for the second quarter of 2018





16



(Thousands of U.S. Dollars, unless otherwise indicated)
Three Months Ended June 30,
 
Three Months Ended March, 31
 
Six Months Ended June 30,
 
2019
2018
% Change
 
2019
 
2019
2018
% Change
Average Daily Volumes (BOEPD)
 
 
 
 
 
 
 
 
 
Consolidated
 
 
 
 
 
 
 
 
 
Working Interest Production Before Royalties
35,340

35,400


 
38,163

 
36,744

35,239

4

Royalties
(6,147
)
(7,202
)
15

 
(6,499
)
 
(6,322
)
(7,045
)
10

Production NAR
29,193

28,198

4

 
31,664

 
30,422

28,194

8

Decrease (Increase) in Inventory
84

(296
)
128

 
169

 
127

(639
)
120

Sales(1)
29,277

27,902

5

 
31,833

 
30,549

27,555

11

 
 
 
 
 
 
 
 
 


 
 
 
 
 
 
 
 
 
 
Net Income
$
38,540

$
20,300

90

 
$
1,979

 
$
40,519

$
38,161

6

 
 
 
 
 
 
 
 
 


Operating Netback
 
 
 
 
 
 
 
 
 
Oil and Natural Gas Sales
$
157,993

$
163,446

(3
)
 
$
152,565

 
$
310,558

$
301,674

3

Operating Expenses
(33,733
)
(26,732
)
26

 
(34,783
)
 
(68,516
)
(48,508
)
41

Workover Expenses
(12,757
)
(8,327
)
53

 
(6,289
)
 
(19,046
)
(12,816
)
49

Transportation Expenses
(4,885
)
(6,522
)
(25
)
 
(8,103
)
 
(12,988
)
(13,519
)
(4
)
Operating Netback(2)
$
106,618

$
121,865

(13
)
 
$
103,390

 
$
210,008

$
226,831

(7
)
 
 
 
 
 
 
 
 
 
 
G&A Expenses Before Stock-Based Compensation
$
9,268

$
5,593

66

 
$
7,869

 
$
17,137

$
13,575

26

G&A Stock-Based Compensation (Recovery)
(627
)
6,609

(109
)
 
1,727

 
1,100

9,787

(89
)
G&A Expenses, Including Stock-Based Compensation
$
8,641

$
12,202

(29
)
 
$
9,596

 
$
18,237

$
23,362

(22
)
 
 
 
 
 
 
 
 
 
 
EBITDA(2)
$
115,269

$
102,278

13

 
$
92,524

 
$
207,793

$
190,866

9

 
 
 
 
 
 
 
 
 
 
Funds Flow From Operations(2)
$
88,269

$
94,549

(7
)
 
$
75,450

 
$
163,719

$
169,297

(3
)
 
 
 
 
 
 
 
 
 


Capital Expenditures
$
99,595

$
84,394

18

 
$
94,489

 
$
194,084

$
157,088

24


 
As at
(Thousands of U.S. Dollars)
June 30, 2019
December 31, 2018
% Change
Cash and Cash Equivalents and Current Restricted Cash and Cash Equivalents
$
148,411

$
52,309

184
 
 
 
 
Working Capital, Including Cash and Cash Equivalents
$
151,384

$
33,145

357
 
 
 
 
7.75% Senior notes
$
300,000

$

100
 
 
 
 
6.25% Senior notes
$
300,000

$
300,000

 
 
 
 
Convertible Notes
$
115,000

$
115,000


17




(1) Sales volumes represent production NAR adjusted for inventory changes.

(2) Non-GAAP measures

Operating netback, EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as oil and natural gas sales less operating, workover and transportation expenses. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil and natural gas sales to operating netback is provided in the table above.

EBITDA, as presented, is defined as net income adjusted for depletion, depreciation and accretion ("DD&A") expenses, interest expense and income tax expense. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income to EBITDA is as follows:
 
Three Months Ended June 30,
 
Three Months Ended March, 31
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
 
2019
2018
Net income
$
38,540

$
20,300

 
$
1,979

 
$
40,519

$
38,161

Adjustments to reconcile net income to EBITDA
 
 
 
 
 
 
 
DD&A expenses
51,697

46,607

 
62,921

 
114,618

86,068

Interest expense
10,564

7,375

 
7,938

 
18,502

12,870

Income tax expense
14,468

27,996

 
19,686

 
34,154

53,767

EBITDA (non-GAAP)
115,269

102,278

 
92,524

 
207,793

190,866


Funds flow from operations, as presented, is defined as net income adjusted for DD&A expenses, deferred tax expense, stock-based compensation expense, amortization of debt issuance costs, cash settlement of RSUs, non-cash lease expense, lease payments, unrealized foreign exchange gains and losses, financial instruments gains or losses and cash settlement of financial instruments. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income to funds flow from operations is as follows:
 
Three Months Ended June 30,
 
Three Months Ended March, 31
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
 
2019
2018
Net income
$
38,540

$
20,300

 
$
1,979

 
$
40,519

$
38,161

Adjustments to reconcile net income to funds flow from operations
 
 
 
 
 
 
 
DD&A expenses
51,697

46,607

 
62,921

 
114,618

86,068

Deferred tax expense
14,957

23,169

 
8,323

 
23,280

36,651

Stock-based compensation expense (recovery)
(627
)
6,893

 
1,727

 
1,100

10,202

Amortization of debt issuance costs
947

843

 
838

 
1,785

1,513

Cash settlement of RSUs

(240
)
 

 

(360
)
Non-cash lease expense
894


 

 
894


Lease payments
(848
)

 

 
(848
)

Unrealized foreign exchange (gain) loss
2,174

1,875

 
(3,283
)
 
(1,109
)
831

Financial instruments (gain) loss
(18,340
)
4,768

 
3,165

 
(15,175
)
11,714

Cash settlement of financial instruments
(1,125
)
(9,666
)
 
(220
)
 
(1,345
)
(15,483
)
Funds flow from operations (non-GAAP)
$
88,269

$
94,549

 
$
75,450

 
$
163,719

$
169,297



18



Additional Operational Results

 
Three Months Ended June 30,
 
Three Months Ended March, 31
 
Six Months Ended June 30,
 
2019
2018
% Change
 
2019
 
2019
2018
% Change
(Thousands of U.S. Dollars)
 
 
 
 
 
 
 
 
 
Oil and natural gas sales
$
157,993

$
163,446

(3
)
 
$
152,565

 
$
310,558

$
301,674

3

Operating expenses
33,733

26,732

26

 
34,783

 
68,516

48,508

41

Workover expenses
12,757

8,327

53

 
6,289

 
19,046

12,816

49

Transportation expenses
4,885

6,522

(25
)
 
8,103

 
12,988

13,519

(4
)
Operating netback(1)
106,618

121,865

(13
)
 
103,390

 
210,008

226,831

(7
)
 
 
 
 
 
 
 
 
 
 
DD&A expenses
51,697

46,607

11

 
62,921

 
114,618

86,068

33

G&A expenses before stock-based compensation
9,268

5,593

66

 
7,869

 
17,137

13,575

26

G&A stock-based compensation expense (recovery)
(627
)
6,609

(109
)
 
1,727

 
1,100

9,787

(89
)
Severance expenses
270

1,011

(73
)
 
672

 
942

1,011

(7
)
Foreign exchange (gain) loss
1,175

2,216

47

 
(2,434
)
 
(1,259
)
1,274

(199
)
Financial instruments (gain) loss
(18,340
)
4,768

(485
)
 
3,165

 
(15,175
)
11,714

(230
)
Interest expense
10,564

7,375

43

 
7,938

 
18,502

12,870

44

 
54,007

74,179

(27
)
 
81,858

 
135,865

136,299


 
 
 
 
 
 
 
 
 
 
Interest income
397

610

(35
)
 
133

 
530

1,396

(62
)
 
 
 
 
 
 
 
 
 

Income before income taxes
53,008

48,296

10

 
21,665

 
74,673

91,928

(19
)
 
 
 
 
 
 
 
 
 
 
Current income tax expense (recovery)
(489
)
4,827

(110
)
 
11,363

 
10,874

17,116

(36
)
Deferred income tax expense
14,957

23,169

(35
)
 
8,323

 
23,280

36,651

(36
)
 
14,468

27,996

(48
)
 
19,686

 
34,154

53,767

(36
)
Net income
$
38,540

$
20,300

90

 
$
1,979


$
40,519

$
38,161

6

 
 
 
 
 
 
 
 
 

Sales Volumes (NAR)
 
 
 
 
 
 
 
 

Total sales volumes, BOE
2,664,257
2,539,089
5

 
2,865,040

5,529,297
4,987,456
11

 
 
 
 
 
 
 
 
 
 
Total sales volumes, BOEPD
29,277

27,902

5

 
31,833

 
30,549

27,555

11

 
 
 
 
 
 
 
 
 

Brent Price per bbl
$
68.32

$
74.90

(9
)
 
$
63.90

 
$
66.11

$
71.04

(7
)
 
 
 
 
 
 
 
 
 
 
Consolidated Results of Operations per BOE Sales Volumes NAR
 
 
 
 
 
 
 
 


Oil and natural gas sales
$
59.30

$
64.37

(8
)
 
$
53.25

 
$
56.17

$
60.49

(7
)
Operating expenses
12.66

10.52

20

 
12.14

 
12.39

9.73

27

Workover expenses
4.79

3.29

46

 
2.20

 
3.44

2.57

34

Transportation expenses
1.83

2.57

(29
)
 
2.83

 
2.35

2.71

(13
)
Operating netback(1)
40.02

47.99

(17
)
 
36.08


37.99

45.48

(16
)

19



 
 
 
 
 
 
 
 
 
 
DD&A expenses
19.40

18.36

6

 
21.96

 
20.73

17.26

20

G&A expenses before stock-based compensation
3.48

2.20

58

 
2.75

 
3.10

2.72

14

G&A stock-based compensation expense (recovery)
(0.24
)
2.60

(109
)
 
0.60

 
0.20

1.96

(90
)
Severance expenses
0.10

0.40

(75
)
 
0.23

 
0.17

0.20

(15
)
Foreign exchange (gain) loss
0.44

0.88

50

 
(0.85
)
 
(0.23
)
0.26

188

Financial instruments (gain) loss
(6.88
)
1.88

466

 
1.10

 
(2.74
)
2.35

217

Interest expense
3.97

2.90

37

 
2.77

 
3.35

2.58

30

 
20.27

29.22

(31
)
 
28.56

 
24.58

27.33

(10
)
 
 
 
 
 
 
 
 
 
 
Interest income
0.15

0.24

(38
)
 
0.05

 
0.10

0.28

(64
)
 
 
 
 
 
 
 
 
 


Income before income taxes
19.90

19.01

5

 
7.57

 
13.50

18.43

(27
)
Current income tax expense (recovery)
(0.18
)
1.90

(109
)
 
3.97

 
1.97

3.43

(43
)
Deferred income tax expense
5.61

9.12

(38
)
 
2.91

 
4.21

7.35

(43
)
 
5.43

11.02

(51
)
 
6.88

 
6.18

10.78

(43
)
Net income
$
14.47

$
7.99

81

 
$
0.69

 
$
7.32

$
7.65

(4
)
 
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures" for a definition of this measure.

Oil and Gas Production and Sales Volumes, BOEPD

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
2018
 
2019
2018
Average Daily Volumes (BOEPD)
 
 
 
 
 
Working Interest Production Before Royalties
35,340

35,400

 
36,744

35,239

Royalties
(6,147
)
(7,202
)
 
(6,322
)
(7,045
)
Production NAR
29,193

28,198

 
30,422

28,194

Decrease (Increase) in Inventory
84

(296
)
 
127

(639
)
Sales
29,277

27,902

 
30,549

27,555

 
 
 
 
 
 
Royalties, % of Working Interest Production Before Royalties
17
%
20
%
 
17
%
20
%

Oil and gas production NAR for the three and six months ended June 30, 2019 increased by 4% and 8% respectively, compared with the corresponding periods of 2018. The increase in production was a result of successful drilling and workover campaign in the Acordionero Field and acquisition of additional WI in Suroriente Block during the first quarter of 2019. These increases were partially offset by the temporary suspension of Suroriente production due to community blockades from June 17 through July 9, 2019, and, starting late May 2019, downtime from ESP failures in Acordionero and the temporary shut-in of two large producers in Acordionero with high GOR. The successful commissioning of water injection facilities in Acordionero in July 2019 and associated increase in water injection is expected to reduce the GOR in the field and the planned transition to gas to power in August 2019 is expected to reduce ESP failures due to unreliable power. Both activities in Acordionero are expected to allow us to restore production in the coming months.

Royalties as a percentage of production for the three and six months ended June 30, 2019 decreased compared with the corresponding periods of 2018 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia.

20




Operating Netbacks

 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Oil and Natural Gas Sales
$
157,993

$
163,446

 
$
310,558

$
301,674

Transportation Expenses
(4,885
)
(6,522
)
 
(12,988
)
(13,519
)
 
153,108

156,924

 
297,570

288,155

Operating Expenses
(33,733
)
(26,732
)
 
(68,516
)
(48,508
)
Workover Expenses
(12,757
)
(8,327
)
 
(19,046
)
(12,816
)
Operating Netback(1)
$
106,618

$
121,865

 
$
210,008

$
226,831

 
 
 
 
 
 
U.S. Dollars Per BOE Sales Volumes NAR
 
 
 
 
 
Brent
$
68.32

$
74.90

 
$
66.11

$
71.04

Quality and Transportation Discounts
(9.02
)
(10.53
)
 
(9.94
)
(10.55
)
Average Realized Price
59.30

64.37

 
56.17

60.49

Transportation Expenses
(1.83
)
(2.57
)
 
(2.35
)
(2.71
)
Average Realized Price Net of Transportation Expenses
57.47

61.80

 
53.82

57.78

Operating Expenses
(12.66
)
(10.53
)
 
(12.39
)
(9.73
)
Workover Expenses
(4.79
)
(3.28
)
 
(3.44
)
(2.57
)
Operating Netback(1)
$
40.02

$
47.99

 
$
37.99

$
45.48


(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures" for a definition of this measure.

Oil and gas sales for the three months ended June 30, 2019 decreased 3% to $158.0 million as a result of 9% decrease in Brent partially offset by higher sales volumes, compared with the corresponding period of 2018. Oil and gas sales for the six months ended June 30, 2019 increased 3% to $310.6 million as a result of higher sales volumes and lower quality and transportation discounts partially offset by lower realized prices as a result of 7% decrease in Brent, compared with the corresponding period of 2018. Compared with the prior quarter, oil and gas sales increased 4% as a result of higher realized prices as a result of 7% increase in Brent partially offset by lower sales volumes.

The following table shows the effect of changes in realized prices and sales volumes on our oil and gas sales for the three and six months ended June 30, 2019 compared with the prior quarter and the corresponding periods of 2018:

(Thousands of U.S. Dollars)

Second Quarter 2019 Compared with First Quarter 2019
 
Second Quarter 2019 Compared with Second Quarter 2018
 
Six Months Ended, June 30, 2019 Compared with Six Months Ended June 30, 2018
Oil and natural gas sales for the comparative period
$
152,565

 
$
163,446

 
$
301,674

Realized sales prices increase (decrease) effect
16,120

 
(13,510
)
 
(23,890
)
Sales volumes (decrease) increase effect
(10,692
)
 
8,057

 
32,774

Oil and natural gas sales for the three and six months ended June 30, 2019
$
157,993

 
$
157,993

 
$
310,558


Average realized prices for the three and six months ended June 30, 2019 decreased 8% and 7%, respectively, compared with the corresponding periods of 2018. The decrease was commensurate with decreases in benchmark oil prices partially offset by lower quality and transportation discounts. Compared with the prior quarter, average realized prices increased 11%.


21



We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized sales prices and transportation expenses and we primarily focus on maximizing operating netback. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for the three and six months ended June 30, 2019 and 2018, and the prior quarter:

 
Three Months Ended June 30,
Three Months Ended March, 31
Six Months Ended June 30,
 
2019
2018
2019
2019
2018
Volume transported through pipeline
1
%
9
%
3
%
2
%
9
%
Volume sold at wellhead
51
%
41
%
43
%
47
%
42
%
Volume transported via truck
48
%
50
%
54
%
51
%
49
%
 
100
%
100
%
100
%
100
%
100
%

Volumes transported through pipeline or via truck receive higher realized prices, but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized prices, offset by lower transportation expenses.

Transportation expenses for the three and six months ended June 30, 2019 decreased 25% and 4% to $4.9 and $13.0 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, transportation expenses decreased 29% and 13% to $1.83 and $2.35, respectively, compared with the corresponding periods of 2018. Lower transportation expenses were a result of higher volumes sold at wellhead during the three and six months ended June 30, 2019.

For the three months ended June 30, 2019, transportation expenses decreased 40% compared with $8.1 million in the prior quarter. On a per BOE basis, transportation expenses decreased 35% from $2.83 in the prior quarter. Lower transportation expenses were a result of higher volumes sold at wellhead, which had lower costs per BOE.

Operating expenses for the three and six months ended June 30, 2019 increased 26% and 41% to $33.7 and $68.5 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, operating expenses increased by $2.14 and $2.66, respectively, compared to the corresponding periods of 2018, primarily as a result of higher power generation, field operations maintenance and equipment rental costs. The Acordionero facilities expansion was fully commissioned at the beginning of the third quarter of 2019 and the gas-to-power will be commissioned in mid-August 2019. These projects will allow expanded water injection and delivery of enhanced power reliability by the end of third quarter, which are expected to reduce operating costs and enhance ultimate recovery of oil and gas in the Acordionero field. With the commissioning of the permanent facilities and gas-to-power projects, the Company expects to reduce operating costs by terminating contracts related to rental facilities in the field and generating power through natural gas produced in the field instead of purchased diesel.

Operating expenses for the three months ended June 30, 2019 decreased by 3% compared with the prior quarter. On a per BOE basis, operating expenses for the three months ended June 30, 2019 increased by 4%, or $0.52, as a result of lower sales volumes during the second quarter of 2019.

Workover expenses increased to $4.79 and $3.44 per BOE, respectively, during the three and six months ended June 30, 2019, compared to $3.29 and $2.57 in the corresponding periods of 2018 due to submersible pump failures during the second quarter of 2019 as a result of unstable power. Workover expenses increased by $2.59 per BOE compared to the prior quarter as a result of higher frequency of pump failures during the second quarter of 2019.

DD&A Expenses
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
2018
 
2019
2018
DD&A Expenses, thousands of U.S. Dollars

$
51,697

$
46,607

 
$
114,618

$
86,068

DD&A Expenses, U.S. Dollars per BOE

19.40

18.36

 
20.73

17.26


DD&A expenses for the three and six months ended June 30, 2019 increased 11% and 33% or $1.04 and $3.47 per BOE, respectively, compared to the corresponding periods of 2018. The increase in DD&A expenses was due to higher costs in the depletable base, partially offset by an allocation to proved reserves related to Acordionero field and Suroriente Block.

22



For the three months ended June 30, 2019, DD&A expenses decreased 18% or $2.56 per BOE from the prior quarter primarily due to lower DD&A rate resulting from increased allocation to proved reserves.

G&A Expenses

 
Three Months Ended June 30,
 
Three Months Ended March, 31
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
2018
% Change
 
2019
 
2019
2018
% Change
G&A Expenses Before Stock-Based Compensation
$
9,268

$
5,593

66

 
$
7,869

 
$
17,137

$
13,575

26

G&A Stock-Based Compensation (Recovery)
(627
)
6,609

(109
)
 
1,727

 
1,100

9,787

(89
)
G&A Expenses, Including Stock-Based Compensation
$
8,641

$
12,202

(29
)
 
$
9,596

 
$
18,237

$
23,362

(22
)
U.S. Dollars Per BOE Sales Volumes NAR
 
 
 
 
 
 
 
 
 
G&A Expenses Before Stock-Based Compensation
$
3.48

$
2.20

58

 
$
2.75

 
$
3.10

$
2.72

14

G&A Stock-Based Compensation (Recovery)
(0.24
)
2.60

(109
)
 
0.60

 
0.20

1.96

(90
)
G&A Expenses, Including Stock-Based Compensation
$
3.24

$
4.80

(33
)
 
$
3.35

 
$
3.30

$
4.68

(29
)

For the three and six months ended June 30, 2019, G&A expenses before stock-based compensation increased 66% and 26%, respectively, from the corresponding periods of 2018. On a per BOE basis, G&A expenses before stock-based compensation increased 58% and 14%, from the corresponding periods of 2018. The increase was mainly a result of lower recoveries and capitalization.

For the three months ended June 30, 2019, G&A expenses before stock-based compensation increased 18% (27% per BOE) from the prior quarter primarily due to lower recoveries and capitalization during current quarter.

After stock-based compensation, G&A expenses for the three and six months ended June 30, 2019 decreased 29% and 22% (33% and 29% per BOE), respectively, compared to the corresponding periods of 2018, mainly due to lower G&A stock-based compensation resulting from a lower share price compared to the corresponding periods of 2018.

G&A expenses after stock-based compensation for the three months ended June 30, 2019 decreased by 10% (3% per BOE) compared with the prior quarter primarily due to lower G&A stock-based compensation resulting from lower share price in the current period.

Severance

For the three and six months ended June 30, 2019, severance costs decreased 73% and 7% to $0.3 and $0.9 million, compared with the corresponding periods in 2018 and decreased 60% compared with the prior quarter. The decrease is a result of head-count optimization during comparative periods of 2018 and first quarter of 2019.

Foreign Exchange Gains and Losses

For the three and six months ended June 30, 2019, we had a $1.2 million loss and $1.3 million gain on foreign exchange, compared with $2.2 million and $1.3 million losses in the corresponding periods of 2018. Taxes receivable, deferred income taxes and investment are considered monetary assets, and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation was the main source of the foreign exchange losses and gains in the periods.

The following table presents the change in the U.S. dollar against the Colombian peso for the three and six months ended June 30, 2019 and 2018:


23



 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
2018
 
2019
2018
Change in the U.S. dollar against the Colombian peso
strengthened by
strengthened by
 
weakened by
weakened by
1%
5%
 
1%
2%
Change in the U.S. dollar against the Canadian dollar
weakened by
strengthened by
 
weakened by
strengthened by
2%
2%
 
4%
5%

Financial Instrument Gains and Losses

The following table presents the nature of our financial instruments gains and losses for the three and six months ended June 30, 2019, and 2018:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Commodity price derivative (gain) loss
$
(706
)
$
14,461

 
$
488

$
19,455

Foreign currency derivatives loss (gain)
55

1,945

 
55

(2,024
)
Investment gain
(17,689
)
(11,638
)
 
(15,718
)
(5,717
)
Financial instruments (gain) loss
$
(18,340
)
$
4,768

 
$
(15,175
)
$
11,714


Income Tax Expense
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2019
 
2018
 
2019
 
2018
Income before income tax
$
53,008

 
$
48,296

 
$
74,673

 
$
91,928

 
 
 
 
 
 
 
 
Current income tax expense (recovery)
$
(489
)
 
$
4,827

 
$
10,874

 
$
17,116

Deferred income tax expense
14,957

 
23,169

 
23,280

 
36,651

Total income tax expense
$
14,468

 
$
27,996

 
$
34,154

 
$
53,767

 
 
 
 
 
 
 
 
Effective tax rate
27
%
 
58
%
 
46
%
 
58
%

Current income tax expense was lower for the six months ended June 30, 2019, compared with the corresponding period of 2018 primarily as a result of lower Colombian taxable income and higher tax depreciation in Colombia. The deferred income tax expense of $23.3 million for the six months ended June 30, 2019, was lower compared with the corresponding period of 2018 primarily due to lower excess tax depreciation compared with accounting depreciation in Colombia, a reduction in the Colombian tax rate and a reduction to the valuation allowance in Colombia.

For the six months ended June 30, 2019, the difference between the effective tax rate of 46% and the 33% Colombian tax rate was primarily due to foreign currency translation adjustments and an increase in the valuation allowance.
 
For the six months ended June 30, 2018, the difference between the effective tax rate of 58% and the 37% Colombian tax rate was primarily due to the impact of foreign tax rates, stock based compensation, foreign currency translation adjustments and an increase in the valuation allowance.





24



Net Income and Funds Flow from Operations (a Non-GAAP Measure)

(Thousands of U.S. Dollars)
Second Quarter 2019 Compared with First Quarter 2019
% change
Second Quarter 2019 Compared with Second Quarter 2018
% change
Six Months Ended, June 30, 2019 Compared with Six Months Ended June 30, 2018
% change
Net income for the comparative period
$
1,979

 
$
20,300

 
38,161

 
Increase (decrease) due to:
 
 
 
 
 
 
Prices
16,120

 
(13,510
)
 
(23,890
)
 
Sales volumes
(10,692
)
 
8,057

 
32,774

 
Expenses:
 
 
 
 
 
 
   Operating
1,050

 
(7,001
)
 
(20,008
)
 
   Workover
(6,468
)
 
(4,430
)
 
(6,230
)
 
   Transportation
3,218

 
1,637

 
531

 
   Cash G&A, RSU settlements and lease payments,
   excluding stock-based compensation expense
(1,353
)
 
(3,673
)
 
(3,571
)
 
   Severance
402

 
741

 
69

 
   Interest, net of amortization of debt issuance costs
(2,517
)
 
(3,085
)
 
(5,360
)
 
   Realized foreign exchange
1,848

 
1,340

 
593

 
   Settlement of financial instruments
(905
)
 
8,541

 
14,138

 
   Current taxes
11,852

 
5,316

 
6,242

 
   Other
264

 
(213
)
 
(866
)
 
Net change in funds flow from operations(1) from comparative period
12,819

 
(6,280
)
 
(5,578
)
 
Expenses:


 
 
 
 
   Depletion, depreciation and accretion
11,224

 
(5,090
)
 
(28,550
)
 
   Deferred tax
(6,634
)
 
8,212

 
13,371

 
   Amortization of debt issuance costs
(109
)
 
(104
)
 
(272
)
 
   Non-cash lease expenses net of lease payments
(46
)
 
(46
)
 
(46
)
 
   Stock-based compensation, net of RSU settlement
2,354

 
7,280

 
8,742

 
   Financial instruments gain or loss, net of financial
   instruments settlements
22,410

 
14,567

 
12,751

 
   Unrealized foreign exchange
(5,457
)
 
(299
)
 
1,940

 
Net change in net income
36,561

 
18,240

 
2,358

 
Net income for the current period
$
38,540

1,847
%
$
38,540

90
%
$
40,519

6
%

(1)Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures" for a definition and reconciliation of this measure.


25



Capital expenditures during the three months ended June 30, 2019 were $99.6 million:

(Millions of U.S. Dollars)
 
Colombia:
 
Exploration
$
36.2

Development:
 
  Drilling and Completions
28.3

  Facilities
18.6

Other
16.5

 
99.6

Corporate

 
$
99.6


During the three months ended June 30, 2019, we drilled the following wells in Colombia:
 
Number of wells (Gross)
Number of wells (Net)
Development
6

6

Total
6

6


We spud 6 development wells, five in Midas and one in Chaza Blocks. Of the wells spud during the quarter, two development wells were completed as of June 30, 2019.

We also continued facilities work at the Acordionero Field on the Midas Block and the Moqueta Field on the Chaza Block.

On February 20, 2019, the Company acquired 36.2% working interest ("WI") in the Suroriente Block and a 100% WI of the Llanos-5 Block for cash consideration of $79.1 million and a promissory note of $1.5 million.

Liquidity and Capital Resources
 
 
As at
(Thousands of U.S. Dollars)
June 30, 2019
 
% Change
 
December 31, 2018
Cash and Cash Equivalents
$
147,712

 
189

 
$
51,040

 
 
 
 
 
 
Current Restricted Cash and Cash Equivalents
$
699

 
(45
)
 
$
1,269

 
 
 
 
 
 
Working Capital, Including Cash and Cash Equivalents
$
151,384

 
357

 
$
33,145

 
 
 
 
 
 
6.25% Senior notes

$
300,000

 

 
$
300,000

 
 
 
 
 
 
7.75% Senior notes

$
300,000

 

 
$

 
 
 
 
 
 
Convertible Notes
$
115,000

 

 
$
115,000


We believe that our capital resources, including cash on hand, cash generated from operations and available capacity on our credit facility, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for 2019, given current oil price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions. 


26



At June 30, 2019, we had an undrawn revolving credit facility with a syndicate of lenders with a borrowing base of $300 million. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. The next re-determination of the borrowing base is due to occur no later than November 2019.

At June 30, 2019, we had $115 million aggregate principal amount of 5.00% Convertible Senior Notes due 2021, $300 million aggregate principal amount of 6.25% Senior Notes due 2025, and $300 million aggregate principal amount of 7.75% Senior Notes due 2027 outstanding.

On July 17, 2019, pursuant to a previously announced offer to purchase for cash all outstanding Convertible Notes, the Company purchased and canceled $114,997,000 aggregate principal amount of Convertible Notes at a purchase price of $1,075 in cash per $1,000 principal amount of Convertible Notes plus $1.6 million of accrued and unpaid interest outstanding on such Convertible Notes up to, but not excluding the date of purchase. After giving effect to the purchase and cancellation of the Convertible Notes, 3,000 aggregate principal amount of Convertible Notes remain outstanding.

Under the terms of our credit facility and Senior Notes, we are required to maintain compliance with certain financial and operating covenants which include: limitations on our ratio of debt to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income ("EBITDAX") to a maximum of 4.0 to 1.0 (under the credit facility) and 3.5 to 1.0 (under the Senior Notes); the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0 (definitions of debt, EBITDAX and other relevant terms are per the credit agreement or the indenture governing the Senior Notes and may differ between these agreements). As at June 30, 2019, we were in compliance with all financial and operating covenants in these agreements. Under the terms of the credit facility and Senior Notes, we are also limited in our ability to make distributions to our shareholders.

At June 30, 2019, net debt to EBITDA was 1.4 times on a trailing twelve month basis and 1.2 times on the basis of the Quarter's annualized results

Derivative Positions

At June 30, 2019, we had outstanding commodity price derivative positions as follows:

Period and type of instrument
Volume,
bopd
Reference
Purchased Put ($/bbl, Weighted Average)
Sold Call
($/bbl, Weighted Average)
Premium
($/bbl, Weighted Average)
Purchased Puts: July 1, to December 31, 2019
5,000

ICE Brent
$
60.00

n/a

$
2.39

Collars: July 1, to December 31, 2019
5,000

ICE Brent
$
60.00

$
71.53

n/a


At June 30, 2019, current liabilities on our balance sheet included $0.4 million and current assets on our balance sheet included $0.9 million in relation to the above outstanding commodity price derivative positions.

Foreign Currency Derivatives

At June 30, 2019, the Company entered into foreign currency derivative positions as follows:
Period and type of instrument
Amount Hedged
(Millions COP)
U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)
Reference
Floor Price
(COP, Weighted Average)
Cap Price (COP, Weighted Average)
Collars: July 1, to December 31, 2019
135,000

42,109

COP
3,019

3,446


(1) At June 30, 2019 foreign exchange rate.


Cash Flows

The following table presents our primary sources and uses of cash and cash equivalents for the periods presented:

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Six Months Ended June 30,
(Thousands of U.S. Dollars)

2019
2018
Sources of cash and cash equivalents:
 
 
Net income
$
40,519

$
38,161

Adjustments to reconcile net income to EBITDA(1)
 and funds flow from operations(1)
 
 
DD&A expenses
114,618

86,068

Interest expense
18,502

12,870

Income tax expense
34,154

53,767

 EBITDA
207,793

190,866

Current income tax expense
(10,874
)
(17,116
)
Contractual interest and other financing expenses
(16,717
)
(11,357
)
Stock-based compensation expense
1,100

10,202

Cash settlement of RSUs

(360
)
Unrealized foreign exchange (gain) loss
(1,109
)
831

Financial instruments (gain) loss
(15,175
)
11,714

Non-cash lease expenses
894


Lease payments
(848
)

Cash settlement of financial instruments
(1,345
)
(15,483
)
Funds flow from operations
163,719

169,297

Proceeds from bank debt, net of issuance costs
163,000

4,988

Proceeds from issuance of Senior Notes, net of issuance costs
289,117

288,087

Proceeds from issuance of shares

845

 
615,836

463,217

 
 
 
Uses of cash and cash equivalents:
 
 
Additions to property, plant and equipment
(194,084
)
(157,088
)
Additions to property, plant and equipment - property acquisitions
(77,772
)
(3,100
)
Repayment of bank debt
(163,000
)
(153,000
)
Repurchase of shares of Common Stock
(23,951
)
(1,208
)
Net changes in assets and liabilities from operating activities
(70,194
)
(37,994
)
Changes in non-cash investing working capital
11,116

(6,142
)
Settlement of asset retirement obligations
(510
)
(369
)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents
(1,073
)
(69
)
 
(519,468
)
(358,970
)
Net increase in cash and cash equivalents and restricted cash and cash equivalents
$
96,368

$
104,247

 
(1) EBITDA and funds flow from operations are a non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operational Highlights - non-GAAP measures” for a definition and reconciliation of this measure.

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices, the impact of which we partially mitigate by entering into commodity derivatives. Sales volume changes and costs related to operations and debt service also impact cash flow. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes, the impact of which we partially mitigate by entering into foreign currency derivatives.


Off-Balance Sheet Arrangements
 
As at June 30, 2019, we had no off-balance sheet arrangements.

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Contractual Obligations

On May 20, 2019, we issued $300 million aggregate principal amount of the 7.75% Senior Notes. Refer to Note 4 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Form 10-Q.

During the six months ended June 30, 2019, we re-paid a balance of $163 million outstanding under our revolving credit facility, which was undrawn as at June 30, 2019.

Subsequent to June 30, 2019, we purchased and canceled $114,997,000 aggregate principal amount of Convertible Notes at a purchase price of $1,075 in cash per $1,000 principal amount of Convertible Notes plus $1.6 million of accrued and unpaid interest outstanding on such Convertible Notes up to, but not excluding the date of purchase

Except for noted above, as at June 30, 2019, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at December 31, 2018.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2018 Annual Report on Form 10-K, and have not changed materially since the filing of that document, other than as follows:

Leases

We adopted Accounting Standard Codification ("ASC") 842 Leases with a date of initial application on January 1, 2019 in accordance with the modified retrospective transition approach using the practical expedients available for land easements and short-term leases. We did not elect the "suite" of practical expedients or use the hindsight expedient in its adoption.

The transition resulted in the recognition of a right-of-use asset presented in other capital assets of $3.8 million, the recognition of lease liabilities in other long-term liabilities of $4.2 million and a $0.4 million impact on retained earnings. When measuring the lease liabilities, the Company's incremental borrowing rate was used. At January 1, 2019 the average rates applied were between 5.6% and 9.1%.

At inception of a contract, we assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At inception of a contract that contains a lease component, we allocate the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. We recognize a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, and subsequently at cost less any accumulated depreciation and impairment losses, and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, our incremental borrowing rate. Generally, we use the Company's incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.


Item 3. Quantitative and Qualitative Disclosures About Market Risk
 
Commodity price risk

Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Most of our revenues are from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to ICE Brent and adjusted for quality each month.


29



We have entered into commodity price derivative contracts to manage the variability in cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending.

Foreign currency risk

Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 100% of our revenues are related to the U.S. dollar price of Brent or WTI oil. We receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures is in U.S. dollars or is based on U.S. dollar prices. The majority of income and value added taxes and G&A expenses in Colombia are in local currency. Certain G&A expenses incurred at our head office in Canada are denominated in Canadian dollars. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.

We have entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our current and deferred tax liabilities, which are monetary liabilities, denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency.

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our revolving credit facility, which bears floating rates of interest. At June 30, 2019, our outstanding balance under revolving credit facility was nil (December 31, 2018 - nil).

Further Information

See Note 9 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for further information regarding our derivative contracts, including the notional amounts and call and put prices by expected (contractual) maturity dates. Expected cash flows from the derivatives equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. We do not hold any of these derivative contracts for trading purposes.

Item 4. Controls and Procedures
 
Disclosure Controls and Procedures
 
We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as of June 30, 2019.

Changes in Internal Control over Financial Reporting
 
There were no changes in our internal control over financial reporting during the quarter ended June 30, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 





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PART II - Other Information


Item 1. Legal Proceedings
 
See Note 8 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for any material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2018, and any material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

See Part I, Item 1A Risk Factors of our 2018 Annual Report on Form 10-K. Other than the risk factor set forth below, there have been no material changes to the risks set forth in Part I, Item 1A Risk Factors of our 2018 Annual Report on Form 10-K.

We have recently been awarded exploration rights on blocks in Ecuador.

We have recently been awarded exploration rights on blocks in Ecuador. We have not previously operated in Ecuador, and it is difficult to predict the results and to project the costs of implementing an exploratory drilling program in Ecuador due to the inherent uncertainties of drilling and the fact that exploration and production operations there are subject to legal, social, political and economic uncertainties that may be different from what we have experienced in Colombia. Ecuador has experienced and may in the future experience political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including but not limited to: the imposition of additional taxes; nationalization; changes in energy or environmental policies or the personnel administering them; and changes in oil and natural gas pricing policies. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets or renegotiation or nullification of existing concessions and contracts. Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Ecuador are beyond our control and may significantly hamper our ability to expand our operations or operate our business in this country at a profit. Wells that are drilled may not achieve the results expected.


Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

 
(a)
Total Number of Shares Purchased
(1)
(b)
Average Price Paid per Share
 (2)
(c) Total Number of Shares Purchased as Part of Publicly Announced  Plans or Programs
(d)
Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
 
April 1-30, 2019
3,518,025

2.42

3,518,025

13,993,151

(3) 
May 1-31, 2019
3,668,300

2.17

3,668,300

10,324,851

(3) 
June 1-30, 2019
670,100

1.98

670,100

9,654,751

(3) 
 
7,856,425

2.27

7,856,425

9,654,751

 

(1) Based on settlement date.

(2) Exclusive of commissions paid to the broker to repurchase the Common Stock.

(3) On March 11, 2019, we announced that we intended to implement a share repurchase program (the “2019 Program”) through the facilities of the TSX and eligible alternative trading platforms in Canada. We received regulatory approval from the TSX to commence the 2019 Program on March 13, 2019. We are able to purchase at prevailing market prices up to 19,353,951 shares of Common Stock, representing approximately 5% of our issued and outstanding shares of Common Stock as of March 31, 2019.


31



The 2019 Program will expire on March 12, 2020, or earlier if the 5.00% share maximum is reached. The 2019 Program could be terminated by us at any time, subject to compliance with regulatory requirements. As such, there can be no assurance regarding the total number of shares that may be repurchased under the 2019 Program. Of the shares repurchased, 4,338,400 shares have not been cancelled by the Company and are designated as treasury stock as at June 30, 2019.

Item 6. Exhibits
Exhibit No.
Description
 
Reference
 
 
 
 
3.1
 
Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
 
 
 
 
3.2
 
Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
 
 
 
 
3.3
 
Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the SEC on July 9, 2018 (SEC File No. 001-34018).
 
 
 
 
4.1

 
Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on May 23, 2019 (SEC File No. 001-34018).

 
 
 
 
4.2

 
Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the SEC on May 23, 2019 (SEC File No. 001-34018).

 
 
 
 
10.1

 
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on May 15, 2019 (SEC File No. 001-34018).

 
 
 
 
10.2

 
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on May 23, 2019 (SEC File No. 001-34018).


 
 
 
 
10.3

 
Filed herewith.
 
 
 
 
10.4

 
Filed herewith.
 
 
 
 
31.1
 
Filed herewith.
 
 
 
 
31.2
 
Filed herewith.
 
 
 
 
32.1
 
Furnished herewith.
101.INS  XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH  XBRL Taxonomy Extension Schema Document
101.CAL  XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document

32



101.LAB  XBRL Taxonomy Extension Label Linkbase Document
101.PRE  XBRL Taxonomy Extension Presentation Linkbase Document104    The cover page from Gran Tierra Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in Inline XBRL (included within the Exhibit 101 attachments).


SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
GRAN TIERRA ENERGY INC.

Date: August 7, 2019
 
/s/ Gary S. Guidry
 
 
By: Gary S. Guidry
 
 
President and Chief Executive Officer
 
 
(Principal Executive Officer)
  
Date: August 7, 2019
 
/s/ Ryan Ellson
 
 
By: Ryan Ellson
 
 
Chief Financial Officer
 
 
(Principal Financial and Accounting Officer)


33