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GRAN TIERRA ENERGY INC. - Quarter Report: 2019 September (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 September 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 October 30, 2019, 366,981,556 shares of the registrant’s Common Stock, $0.001 par value, were issued.

 



Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended September 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; volatility or declines in the trading price of our common stock; and 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." 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 September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
OIL AND NATURAL GAS SALES
(Note 6)
$
132,491

 
$
175,118

 
$
443,049

 
$
476,792

 


 


 


 


EXPENSES
 
 
 
 
 
 
 
Operating
35,603

 
29,511

 
104,119

 
78,019

Workover
10,979

 
13,106

 
30,025

 
25,922

Transportation
3,179

 
7,505

 
16,167

 
21,024

Depletion, depreciation and accretion
49,812

 
51,630

 
164,430

 
137,698

General and administrative
7,637

 
13,811

 
25,874

 
37,173

Severance
140

 
1,004

 
1,082

 
2,015

Foreign exchange loss (gain)
6,840

 
(888
)
 
5,581

 
386

Financial instruments loss (gain) (Note 9)
12,285

 
(4,874
)
 
(2,890
)
 
6,840

Loss on redemption of Convertible Notes (Note 4)
11,305

 

 
11,305

 

Interest expense (Note 4)
12,153

 
7,404

 
30,655

 
20,274

 
149,933

 
118,209

 
386,348

 
329,351

 
 
 
 
 
 
 
 
INTEREST INCOME
130

 
725

 
660

 
2,121

(LOSS) INCOME BEFORE INCOME TAXES
(17,312
)
 
57,634

 
57,361

 
149,562

 
 
 
 
 
 
 
 
INCOME TAX EXPENSE (RECOVERY)
 
 
 
 
 
 
 
Current (Note 7)
3,049

 
19,108

 
13,923

 
36,224

Deferred (Note 7)
8,472

 
(36,769
)
 
31,752

 
(118
)

11,521

 
(17,661
)
 
45,675

 
36,106

NET AND COMPREHENSIVE (LOSS) INCOME
$
(28,833
)
 
$
75,295

 
$
11,686

 
$
113,456

 
 
 
 
 
 
 
 
NET (LOSS) INCOME PER SHARE
 
 
 
 
 
 
 
  - BASIC
$
(0.08
)
 
$
0.19

 
$
0.03

 
$
0.29

  - DILUTED
$
(0.08
)
 
$
0.18

 
$
0.03

 
$
0.28

WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)
372,195,176

 
391,209,589

 
379,701,405

 
391,185,636

WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)
372,195,176

 
427,947,959

 
379,701,664

 
427,416,964


(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 September 30, 2019
 
As at December 31, 2018
 
 
 
 
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents (Note 10)
$
13,959

 
$
51,040

Restricted cash and cash equivalents (Note 10)
676

 
1,269

Accounts receivable
27,334

 
26,177

Investment (Note 9)
41,979

 
32,724

Taxes receivable
100,205

 
78,259

Other assets
16,824

 
13,056

Total Current Assets
200,977

 
202,525

 
 
 
 
Oil and Gas Properties
 

 
 

Proved
1,063,386

 
853,428

Unproved
504,779

 
456,598

Total Oil and Gas Properties
1,568,165

 
1,310,026

Other capital assets
5,139

 
2,751

Total Property, Plant and Equipment
1,573,304

 
1,312,777

 
 
 
 
Other Long-Term Assets
 

 
 

Deferred tax assets
44,886

 
45,437

Investment (Note 9)
4,868

 
8,711

Taxes receivable
29,036

 

Other
4,209

 
4,553

Goodwill
102,581

 
102,581

Total Other Long-Term Assets
185,580

 
161,282

Total Assets
$
1,959,861

 
$
1,676,584

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 

 
 

Current Liabilities
 

 
 

Accounts payable and accrued liabilities
$
201,569

 
$
154,670

Derivatives (Note 9)
747

 
1,017

Taxes payable

 
4,149

  Equity compensation award liability (Note 5 and 9)
3,661

 
9,544

Total Current Liabilities
205,977

 
169,380

 
 
 
 
Long-Term Liabilities
 

 
 

Long-term debt (Notes 4 and 9)
637,601

 
399,415

Deferred tax liabilities
53,930

 
23,419

Asset retirement obligation
48,411

 
43,676

  Equity compensation award liability (Note 5 and 9)
4,544

 
8,139

Other
4,346

 
2,805

Total Long-Term Liabilities
748,832

 
477,454

 
 
 
 
Contingencies (Note 8)


 


 
 
 
 
Shareholders’ Equity
 

 
 

Common Stock (Note 5) (366,981,556 and 387,079,027 shares issued and outstanding of Common Stock, par value $0.001 per share, as at September 30, 2019, and December 31, 2018, respectively)
10,270

 
10,290

Additional paid in capital
1,282,074

 
1,318,048

Deficit
(287,292
)
 
(298,588
)
Total Shareholders’ Equity
1,005,052

 
1,029,750

Total Liabilities and Shareholders’ Equity
$
1,959,861

 
$
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)
 
Nine Months Ended September 30,
 
2019
 
2018
Operating Activities
 
 
 
Net income
$
11,686

 
$
113,456

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

Depletion, depreciation and accretion
164,430

 
137,698

Deferred tax expense (recovery)
31,752

 
(118
)
Stock-based compensation (Note 5)
1,092

 
20,477

Amortization of debt issuance costs (Note 4)
2,574

 
2,329

Unrealized foreign exchange loss
5,303

 
159

Financial instruments (gain) loss (Note 9)
(2,890
)
 
6,840

Cash settlement of financial instruments
(2,275
)
 
(26,169
)
Loss on redemption of Convertible Notes (Note 4)
11,305

 

Cash settlement of asset retirement obligation
(707
)
 
(456
)
Non-cash lease expenses
1,366

 

Lease payments
(1,603
)
 

Cash settlement of restricted share units

 
(360
)
Net change in assets and liabilities from operating activities (Note 10)
(83,606
)
 
(40,652
)
Net cash provided by operating activities
138,427

 
213,204

 
 
 
 
Investing Activities
 

 
 

Additions to property, plant and equipment
(310,579
)
 
(258,551
)
Property acquisitions, net of cash acquired (Note 3)
(77,772
)
 
(20,100
)
Changes in non-cash investing working capital
20,138

 
32,638

Net cash used in investing activities
(368,213
)
 
(246,013
)
 
 
 
 
Financing Activities
 

 
 

Proceeds from bank debt, net of issuance costs
246,000

 
4,988

Repayment of debt
(304,000
)
 
(153,000
)
  Repurchase of shares of Common Stock (Note 5)
(37,560
)
 
(1,314
)
Proceeds from exercise of stock options

 
1,408

Proceeds from issuance of Senior Notes, net of issuance costs
289,298

 
288,087

Net cash provided by financing activities
193,738

 
140,169

 
 
 
 
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents
(1,506
)
 
(402
)
 
 
 
 
Net (decrease) increase in cash, cash equivalents and restricted cash and cash equivalents
(37,554
)
 
106,958

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)
$
16,754

 
$
133,636

 
 
 
 
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 September 30,
 
Nine Months Ended September 30,
 
2019
2018
 
2019
2018
Share Capital
 
 
 
 
 
Balance, beginning of period
$
10,285

$
10,295

 
$
10,290

$
10,295

Issuance of Common Stock

1

 

1

Repurchase and cancellation of Common Stock (Note 5)
(15
)
(1
)
 
(20
)
(1
)
Balance, end of period
10,270

10,295

 
10,270

10,295

 
 
 
 
 
 
Additional Paid in Capital
 
 
 
 

 

Balance, beginning of period
1,295,106

1,328,037

 
1,318,048

1,327,244

Exercise of stock options

562

 

1,407

Stock-based compensation (Note 5)
563

489

 
1,566

1,645

Repurchase and cancellation of Common Stock (Note 5)
(13,595
)
(105
)
 
(37,540
)
(1,313
)
Balance, end of period
1,282,074

1,328,983

 
1,282,074

1,328,983

 
 
 
 
 
 
Deficit
 
 
 
 

 

Balance, beginning of period
(258,459
)
(363,043
)
 
(298,588
)
(401,204
)
Net (loss) income
(28,833
)
75,295

 
11,686

113,456

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


 
(390
)

Balance, end of period
(287,292
)
(287,748
)
 
(287,292
)
(287,748
)
 
 
 
 
 
 
Total Shareholders’ Equity
$
1,005,052

$
1,051,530

 
$
1,005,052

$
1,051,530


(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 as part of the transition 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
$
52,960

  Unproved
45,132

 
98,092

Net working capital (including cash acquired of $5.3 million)
(17,492
)
 
$
80,600




4. Debt and Debt Issuance Costs

The Company's debt at September 30, 2019 and December 31, 2018 was as follows:
(Thousands of U.S. Dollars)
As at September 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

Revolving credit facility
57,000

 

Unamortized debt issuance costs
(21,454
)
 
(15,585
)
Long-term debt
635,546

 
399,415

Long-term lease obligation(1)
2,055

 

 
$
637,601

 
$
399,415



(1) The current portion of the lease obligation has been included in accounts payable and accrued liabilities on the Company's balance sheet and totaled $1.8 million as at September 30, 2019 (December 31, 2018 - nil).

Senior Notes

On May 20, 2019, the Company, issued $300.0 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 $289.1 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

8



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%.

Convertible Notes

During the quarter, the Company purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes, including 114,997,000 aggregate principal amount purchased and canceled pursuant to a previously announced offer to purchase for cash all outstanding 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. The Company recorded $11.3 million loss on redemption including premium paid, transaction costs and $2.3 million of deferred financing fees write-off.

Interest Expense

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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Contractual interest and other financing expenses
$
11,364

$
6,588

 
$
28,081

$
17,945

Amortization of debt issuance costs
789

816

 
2,574

2,329

 
$
12,153

$
7,404

 
$
30,655

$
20,274



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

Shares repurchased and canceled
(20,097,471
)
Balance, September 30, 2019
366,981,556



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 had an expiry date of March 12, 2020, or earlier if the 5.00% share maximum was reached. The 2019 Program expired when the 5.00% share maximum was reached in September 2019.

During the three and nine months ended September 30, 2019, the Company repurchased 9,654,751 and 20,097,471 shares at a weighted average prices of $1.41 and $1.87, respectively. Of the shares repurchased, 743,520 shares at a weighted average price of $2.34 were repurchased under 2018 share repurchase program with similar terms to that of the 2019 Program.

Equity Compensation Awards
 
The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), and stock option activity for the nine months ended September 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
5,179,906

352,810

 
2,391,253

2.26

Exercised
(2,725,877
)

 


Forfeited
(574,010
)

 
(943,846
)
3.94

Expired


 
(129,730
)
5.41

Balance, September 30, 2019
10,884,680

1,037,703

 
10,352,089

2.87



For the three and nine months ended September 30, 2019, stock-based compensation expense was nil and $1.1 million, respectively (three and nine months ended September 30, 2018 - $10.3 million and $20.5 million, respectively).

At September 30, 2019, there was $8.8 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 1.8 years. During the nine months ended September 30, 2019, the Company paid out $10.2 million (nine months ended September 30, 2018 - nil) for PSUs 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 September 30,
 
Nine Months Ended September 30,
 
2019
2018
 
2019
2018
Weighted average number of common and exchangeable shares outstanding
372,195,176

391,209,589

 
379,701,405

391,185,636

Shares issuable pursuant to stock options

6,509,385

 
14,315

4,295,964

Shares assumed to be purchased from proceeds of stock options

(5,585,408
)
 
(14,056
)
(3,879,029
)
Shares issuable pursuant to convertible notes

35,814,393

 

35,814,393

Weighted average number of diluted common and exchangeable shares outstanding
372,195,176

427,947,959

 
379,701,664

427,416,964

Common shares outstanding, as at period end
366,981,556

391,339,489

 
366,981,556

391,339,489


 
For the three and nine months ended September 30, 2019, 10,316,496 and 10,247,016 options, respectively (three and nine months ended September 30, 2018 - 3,198,865 and 5,436,667, respectively), on a weighted average basis, were excluded from the diluted income per share calculation as the options were anti-dilutive.

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 nine months ended September 30, 2019, 100%

10



(three and nine months ended September 30, 2018 - 100%) of the Company's revenue resulted from oil sales. During the three and nine months ended September 30, 2019, quality and transportation discounts were 16% and 15%, respectively, of the average ICE Brent price (three and nine months ended September 30, 2018 - 13% and 14%, respectively). During the three and nine months ended September 30, 2019, the Company's production was sold primarily to three major customers in Colombia (three and nine months ended September 30, 2018 - two).

As at September 30, 2019, accounts receivable included $0.1 million of accrued sales revenue related to September 2019 production (December 31, 2018 - $4.2 million related to December 31, 2018 production).

7. Taxes

The Company's effective tax rate was 79% for the nine months ended September 30, 2019, compared to 24% in the comparative period of 2018. Current income tax expense was lower in the nine months ended September 30, 2019, compared with the corresponding period of 2018, primarily as a result of lower income and higher tax depreciation in Colombia. The deferred income tax expense of $31.8 million was higher in the nine months ended September 30, 2019, compared to the corresponding period of 2018 primarily due to the impact of the release of a portion of the valuation allowance in Colombia during 2018 and excess tax depreciation compared with accounting depreciation in Colombia during 2019.

For the nine months ended September 30, 2019, the difference between the effective tax rate of 79% and the 33% Colombian tax rate was primarily due to foreign currency translation adjustments, an increase in the valuation allowance and the impact of foreign tax rates.

For the comparative period of 2018, the 24% effective tax rate differed from the Colombian tax rate of 37% primarily due to a decrease in the valuation allowance and other permanent differences, which was partially offset by the impact of foreign tax rates.

On October 16, 2019, the Colombian Constitutional Court overturned the 2018 tax reform effective January 1, 2020. If a new tax reform law is not approved by the Congress of Colombia by December 31, 2019, the tax regime in force before the 2018 tax reform will apply beginning January 1, 2020. On October 23, 2019, the Congress of Colombia filed a tax bill proposing the same amendments that were approved by the Congress of Colombia in 2018 and which would become effective on January 1, 2020. Based on the Company’s review and analysis of the impact of the court decision and the bill proposed by the Congress of Colombia, the Company believes that both should not have a material effect on its financial statements.

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 $56.2 million as at September 30, 2019 (December 31, 2018 - $56.3 million). At this time no amount has been accrued 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 September 30, 2019, the Company had provided letters of credit and other credit support totaling $123.9 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.



11



9. Financial Instruments and Fair Value Measurement

Financial Instruments

At September 30, 2019, the Company’s financial instruments recognized on 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 September 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 through a subsidiary 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 September 30, 2019, and December 31, 2018, was as follows:
(Thousands of U.S. Dollars)
As at September 30, 2019
 
As at December 31, 2018
Investment - current and long-term
$
46,847

 
$
41,435

Derivative asset1
1,807

 

 
48,654

 
41,435

 
 
 
 
Derivative liability
$
747

 
$
1,017

PSU and DSU liability
8,205

 
17,683

 
$
8,952

 
$
18,700


1Included in other current assets on the Company's balance sheet

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


12



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Commodity price derivative loss (gain)
$
(24
)
$
929

 
$
464

$
20,384

Foreign currency derivatives loss (gain)
337

525

 
392

(1,499
)
Investment loss (gain)
11,972

(6,328
)
 
(3,746
)
(12,045
)
Financial instruments loss (gain)
$
12,285

$
(4,874
)
 
$
(2,890
)
$
6,840



Investment loss (gain) for the three and nine months ended September 30, 2019, was related to the fair value loss (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 nine months ended September 30, 2019 and 2018, this investment loss (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 due 2027. At September 30, 2019, the carrying amounts of the 6.25% Senior Notes and the 7.75% Senior Notes were $290.3 million and $289.6 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $268.6 million and $285.0 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 September 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:
 
Nine Months Ended
 
Year Ended
(Thousands of U.S. Dollars)
September 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
148

 
846

Unrealized foreign exchange gain (loss)
361

 
(760
)
Closing balance, investment - long-term
$
4,868

 
$
8,711



With all other variables held constant, a $0.01 change in the CAD price of PetroTal shares would result in a $1.8 million change in the total investment in PetroTal as at September 30, 2019.

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 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 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.

13




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 September 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: October 1, to December 31, 2019
5,000

ICE Brent
60.00

n/a

2.39

Collars: October 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. At September 30, 2019, the Company had outstanding 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: October 1, to December 31, 2019
67,500

19,497

COP
3,019

3,446


(1) At September 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:

(Thousands of U.S. Dollars)
As at September 30,
 
As at December 31,
 
2019
2018
 
2018
2017
Cash and cash equivalents
$
13,959

$
130,158

 
$
51,040

$
12,326

Restricted cash and cash equivalents - current
676

1,228

 
1,269

11,787

Restricted cash and cash equivalents -
long-term (included in other long-term assets)
2,119

2,250

 
1,999

2,565

 
$
16,754

$
133,636

 
$
54,308

$
26,678



Net changes in assets and liabilities from operating activities were as follows:

14



 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
 
2018
Accounts receivable and other long-term assets
$
3,476

 
$
(35,934
)
Derivatives
(658
)
 
21,645

Inventory
(3,403
)
 
(3,375
)
Prepaids
353

 
489

Accounts payable and accrued and other long-term liabilities
(21,687
)
 
5,380

Taxes receivable and payable
(61,687
)
 
(28,857
)
Net changes in assets and liabilities from operating activities
$
(83,606
)
 
$
(40,652
)


The following table provides additional supplemental cash flow disclosures:

 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
 
2018
Cash paid for income taxes
$
38,022

 
$
38,202

Cash paid for interest
$
25,850

 
$
14,137

 
 
 
 
Non-cash investing activities:
 
 
 
Net liabilities related to property, plant and equipment, end of period
$
105,342

 
$
100,790




15



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 third quarter of 2019

We purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes
Returned $13.6 million to shareholders through the repurchase of 9,654,751 common shares
Net after royalties production ("NAR") was 27,763 BOEPD, 3% lower than the third quarter of 2018. Production decreased as a result of unplanned downtime caused by electrical submersible pump ("ESP") failures at the Acordionero field, the shut-in of several wells in Acordionero due to high gas production and temporary suspension of Suroriente production due to community issues at the beginning of the quarter, partially offset by a decrease in royalties driven by lower oil prices
Oil and natural gas sales volumes(1) were 27,705 BOEPD, 3% lower than the third quarter of 2018. The quarter's decrease in oil and gas sales volumes was commensurate lower production
Net loss was $28.8 million compared with net income of $75.3 million in the third quarter of 2018 primarily due to non-cash items including loss on revaluation of investment and loss on the redemption of the Convertible Notes
Funds flow from operations(2) decreased by 31% to $59.0 million compared with the third quarter of 2018, as a result of lower production and 18% decrease in the price of Brent
Adjusted EBITDA(2) was $67.9 million compared with $110.3 million in the third quarter of 2018
Q3 2019 was an active quarter with capital expenditures of $116.5 million
Oil and gas sales per BOE were $51.98, 22% lower than the third quarter of 2018
Operating netback(2) per BOE was $32.45 for the third quarter of 2019
Operating expenses per BOE were $13.97, 25% higher than the third quarter of 2018 as a result of higher power generation, field operations maintenance and freight and logistics costs and lower production volumes. A significant portion of the Company's operating costs are fixed costs
Workover expenses per BOE were $4.31 during the third quarter of 2019, 13% lower compared to the third quarter of 2018 as a result of lower frequency of ESP failures
Quality and transportation discount per BOE was $10.05 compared with $9.55 in the third quarter of 2018. The increase was due to higher sales at wellhead during the third quarter of 2019 which resulted in a higher transportation discount but lower transportation expenses
Transportation expenses per BOE were $1.25, compared to $2.85 per BOE for the third quarter of 2018





16



(Thousands of U.S. Dollars, unless otherwise indicated)
Three Months Ended September 30,
 
Three Months Ended June 30,
 
Nine Months Ended September 30,
 
2019
2018
% Change
 
2019
 
2019
2018
% Change
Average Daily Volumes (BOEPD)
 
 
 
 
 
 
 
 
 
Consolidated
 
 
 
 
 
 
 
 
 
Working Interest Production Before Royalties
32,918

36,170

(9
)
 
35,340

 
35,454

35,553


Royalties
(5,155
)
(7,571
)
(32
)
 
(6,147
)
 
(5,929
)
(7,222
)
(18
)
Production NAR
27,763

28,599

(3
)
 
29,193

 
29,525

28,331

4

(Increase) Decrease in Inventory
(58
)
60

(197
)
 
84

 
65

(403
)
116

Sales(1)
27,705

28,659

(3
)
 
29,277

 
29,590

27,928

6

 
 
 
 
 
 
 
 
 


 
 
 
 
 
 
 
 
 
 
Net (Loss) Income
$
(28,833
)
$
75,295

(138
)
 
$
38,540

 
$
11,686

$
113,456

(90
)
 
 
 
 
 
 
 
 
 


Operating Netback
 
 
 
 
 
 
 
 
 
Oil and Natural Gas Sales
$
132,491

$
175,118

(24
)
 
$
157,993

 
$
443,049

$
476,792

(7
)
Operating Expenses
(35,603
)
(29,511
)
21

 
(33,733
)
 
(104,119
)
(78,019
)
33

Workover Expenses
(10,979
)
(13,106
)
(16
)
 
(12,757
)
 
(30,025
)
(25,922
)
16

Transportation Expenses
(3,179
)
(7,505
)
(58
)
 
(4,885
)
 
(16,167
)
(21,024
)
(23
)
Operating Netback(2)
$
82,730

$
124,996

(34
)
 
$
106,618

 
$
292,738

$
351,827

(17
)
 
 
 
 
 
 
 
 
 
 
G&A Expenses Before Stock-Based Compensation
$
7,645

$
3,679

108

 
$
9,268

 
$
24,782

$
17,254

44

G&A Stock-Based Compensation (Recovery) Expense
(8
)
10,132

(100
)
 
(627
)
 
1,092

19,919

(95
)
G&A Expenses, Including Stock-Based Compensation
$
7,637

$
13,811

(45
)
 
$
8,641

 
$
25,874

$
37,173

(30
)
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA(2)
$
67,930

$
110,340

(38
)
 
$
97,580

 
$
260,005

$
295,489

(12
)
 
 
 
 
 
 
 
 
 
 
Funds Flow From Operations(2)
$
59,021

$
85,015

(31
)
 
$
88,269

 
$
222,740

$
254,312

(12
)
 
 
 
 
 
 
 
 
 


Capital Expenditures
$
116,495

$
101,463

15

 
$
99,595

 
$
310,579

$
258,551

20



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

(2) Non-GAAP measures

Operating netback, EBITDA, Adjusted 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 (loss) 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.


17



EBITDA, as presented, is defined as net (loss) income adjusted for depletion, depreciation and accretion ("DD&A") expenses, interest expense and income tax expense. Adjusted EBITDA is defined as EBITDA adjusted for loss on redemption of Convertible Notes and loss or gain on investment. Management uses these supplemental measures 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 and Adjusted EBITDA is as follows:
 
Three Months Ended September 30,
 
Three Months Ended June 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
 
2019
2018
Net (loss) income
$
(28,833
)
$
75,295

 
$
38,540

 
$
11,686

$
113,456

Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA
 
 
 
 
 
 
 
DD&A expenses
49,812

51,630

 
51,697

 
164,430

137,698

Interest expense
12,153

7,404

 
10,564

 
30,655

20,274

Income tax expense (recovery)
11,521

(17,661
)
 
14,468

 
45,675

36,106

EBITDA (non-GAAP)
44,653

116,668

 
115,269

 
252,446

307,534

Loss on redemption of Convertible Notes
11,305


 

 
11,305


   Investment loss (gain)
11,972

(6,328
)
 
(17,689
)
 
(3,746
)
(12,045
)
Adjusted EBITDA (non-GAAP)
67,930

110,340

 
97,580

 
260,005

295,489


Funds flow from operations, as presented, is defined as net (loss) income adjusted for DD&A expenses, deferred tax expense (recovery), stock-based compensation (recovery) 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, loss on redemption of Convertible Notes 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 September 30,
 
Three Months Ended June 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
 
2019
2018
Net (loss) income
$
(28,833
)
$
75,295

 
$
38,540

 
$
11,686

$
113,456

Adjustments to reconcile net (loss) income to funds flow from operations
 
 
 
 
 
 
 
DD&A expenses
49,812

51,630

 
51,697

 
164,430

137,698

Deferred tax expense (recovery)
8,472

(36,769
)
 
14,957

 
31,752

(118
)
Stock-based compensation (recovery) expense
(8
)
10,275

 
(627
)
 
1,092

20,477

Amortization of debt issuance costs
789

816

 
947

 
2,574

2,329

Cash settlement of RSUs


 

 

(360
)
Non-cash lease expense
472


 
894

 
1,366


Lease payments
(755
)

 
(848
)
 
(1,603
)

Unrealized foreign exchange loss (gain)
6,412

(672
)
 
2,174

 
5,303

159

Financial instruments loss (gain)
12,285

(4,874
)
 
(18,340
)
 
(2,890
)
6,840

Loss on redemption of Convertible Notes
11,305


 

 
11,305


Cash settlement of financial instruments
(930
)
(10,686
)
 
(1,125
)
 
(2,275
)
(26,169
)
Funds flow from operations (non-GAAP)
$
59,021

$
85,015

 
$
88,269

 
$
222,740

$
254,312



18



Additional Operational Results

 
Three Months Ended September 30,
 
Three Months Ended June 30,
 
Nine Months Ended September 30,
 
2019
2018
% Change
 
2019
 
2019
2018
% Change
(Thousands of U.S. Dollars)
 
 
 
 
 
 
 
 
 
Oil and natural gas sales
$
132,491

$
175,118

(24
)
 
$
157,993

 
$
443,049

$
476,792

(7
)
Operating expenses
35,603

29,511

21

 
33,733

 
104,119

78,019

33

Workover expenses
10,979

13,106

(16
)
 
12,757

 
30,025

25,922

16

Transportation expenses
3,179

7,505

(58
)
 
4,885

 
16,167

21,024

(23
)
Operating netback(1)
82,730

124,996

(34
)
 
106,618

 
292,738

351,827

(17
)
 
 
 
 
 
 
 
 
 
 
DD&A expenses
49,812

51,630

(4
)
 
51,697

 
164,430

137,698

19

G&A expenses before stock-based compensation
7,645

3,679

108

 
9,268

 
24,782

17,254

44

G&A stock-based compensation (recovery) expense
(8
)
10,132

(100
)
 
(627
)
 
1,092

19,919

(95
)
Severance expenses
140

1,004

(86
)
 
270

 
1,082

2,015

(46
)
Foreign exchange loss (gain)
6,840

(888
)
870

 
1,175

 
5,581

386

1,346

Financial instruments loss (gain)
12,285

(4,874
)
352

 
(18,340
)
 
(2,890
)
6,840

(142
)
Loss on redemption of Convertible Notes
11,305


100

 

 
11,305


100

Interest expense
12,153

7,404

64

 
10,564

 
30,655

20,274

51

 
100,172

68,087

47

 
54,007

 
236,037

204,386

15

 
 
 
 
 
 
 
 
 
 
Interest income
130

725

(82
)
 
397

 
660

2,121

(69
)
 
 
 
 
 
 
 
 
 

(Loss) Income before income taxes
(17,312
)
57,634

(130
)
 
53,008

 
57,361

149,562

(62
)
 
 
 
 
 
 
 
 
 
 
Current income tax expense (recovery)
3,049

19,108

(84
)
 
(489
)
 
13,923

36,224

(62
)
Deferred income tax expense (recovery)
8,472

(36,769
)
123

 
14,957

 
31,752

(118
)
27,008

 
11,521

(17,661
)
165

 
14,468

 
45,675

36,106

27

Net (loss) income
$
(28,833
)
$
75,295

(138
)
 
$
38,540


$
11,686

$
113,456

(90
)
 
 
 
 
 
 
 
 
 

Sales Volumes (NAR)
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
Total sales volumes, BOEPD
27,705

28,659

(3
)
 
29,277

 
29,590

27,928

6

 
 
 
 
 
 
 
 
 

Brent Price per bbl
$
62.03

$
75.97

(18
)
 
$
68.32

 
$
64.75

$
72.68

(11
)
 
 
 
 
 
 
 
 
 
 
Consolidated Results of Operations per BOE Sales Volumes NAR
 
 
 
 
 
 
 
 


Oil and natural gas sales
$
51.98

$
66.42

(22
)
 
$
59.30

 
$
54.85

$
62.54

(12
)
Operating expenses
13.97

11.19

25

 
12.66

 
12.89

10.23

26

Workover expenses
4.31

4.97

(13
)
 
4.79

 
3.72

3.40

9

Transportation expenses
1.25

2.85

(56
)
 
1.83

 
2.00

2.76

(28
)

19



Operating netback(1)
32.45

47.41

(32
)
 
40.02


36.24

46.15

(21
)
 
 
 
 
 
 
 
 
 
 
DD&A expenses
19.54

19.58


 
19.40

 
20.35

18.06

13

G&A expenses before stock-based compensation
3.00

1.40

114

 
3.48

 
3.07

2.26

36

G&A stock-based compensation (recovery) expense

3.84

(100
)
 
(0.24
)
 
0.14

2.61

(95
)
Severance expenses
0.05

0.38

(87
)
 
0.10

 
0.13

0.26

(50
)
Foreign exchange loss (gain)
2.68

(0.34
)
888

 
0.44

 
0.69

0.05

1,280

Financial instruments loss (gain)
4.82

(1.85
)
361

 
(6.88
)
 
(0.36
)
0.90

(140
)
Loss on redemption of Convertible Notes
4.44


100

 

 
1.40


100

Interest expense
4.77

2.81

70

 
3.97

 
3.79

2.66

42

 
39.30

25.82

52

 
20.27

 
29.21

26.80

9

 
 
 
 
 
 
 
 
 
 
Interest income
0.05

0.27

(81
)
 
0.15

 
0.08

0.28

(71
)
 
 
 
 
 
 
 
 
 


(Loss) Income before income taxes
(6.80
)
21.86

(131
)
 
19.90

 
7.11

19.63

(64
)
 
 
 
 
 
 
 
 
 
 
Current income tax expense (recovery)
1.20

7.25

(83
)
 
(0.18
)
 
1.72

4.75

(64
)
Deferred income tax expense (recovery)
3.32

(13.95
)
124

 
5.61

 
3.93

(0.02
)
19,750

 
4.52

(6.70
)
167

 
5.43

 
5.65

4.73

19

Net (loss) income
$
(11.32
)
$
28.56

(140
)
 
$
14.47

 
$
1.46

$
14.90

(90
)
 
(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 September 30,
 
Nine Months Ended September 30,
 
2019
2018
 
2019
2018
Average Daily Volumes (BOEPD)
 
 
 
 
 
Working Interest Production Before Royalties
32,918

36,170

 
35,454

35,553

Royalties
(5,155
)
(7,571
)
 
(5,929
)
(7,222
)
Production NAR
27,763

28,599

 
29,525

28,331

(Increase) Decrease in Inventory
(58
)
60

 
65

(403
)
Sales
27,705

28,659

 
29,590

27,928

 
 
 
 
 
 
Royalties, % of Working Interest Production Before Royalties
16
%
21
%
 
17
%
20
%

Oil and gas production NAR for the three months ended September 30, 2019 decreased by 3%, compared with the corresponding period of 2018. The decrease in production was a result of unplanned downtime from ESP failures in the Acordionero field, the shut-in of several wells in Acordionero due to high gas production and temporary suspension of Suroriente production due to community issues at the beginning of the quarter. During the quarter we successfully commissioned water injection and gas-to-power facilities in the Acordionero field which is expected to increase production beginning in the fourth quarter of 2019. We have increased water injection to over 30,000 barrels of water per day and have recently restored production from the several wells previously shut-in.


20



For the nine months ended September 30, 2019 oil and gas production NAR increased by 4% , compared with the corresponding period of 2018 due to a successful drilling campaign in the Acordionero field and lower royalties in 2019.

Royalties as a percentage of production for the three and nine months ended September 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.

Operating Netbacks

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Oil and Natural Gas Sales
$
132,491

$
175,118

 
$
443,049

$
476,792

Transportation Expenses
(3,179
)
(7,505
)
 
(16,167
)
(21,024
)
 
129,312

167,613

 
426,882

455,768

Operating Expenses
(35,603
)
(29,511
)
 
(104,119
)
(78,019
)
Workover Expenses
(10,979
)
(13,106
)
 
(30,025
)
(25,922
)
Operating Netback(1)
$
82,730

$
124,996

 
$
292,738

$
351,827

 
 
 
 
 
 
U.S. Dollars Per BOE Sales Volumes NAR
 
 
 
 
 
Brent
$
62.03

$
75.97

 
$
64.75

$
72.68

Quality and Transportation Discounts
(10.05
)
(9.55
)
 
(9.90
)
(10.14
)
Average Realized Price
51.98

66.42

 
54.85

62.54

Transportation Expenses
(1.25
)
(2.85
)
 
(2.00
)
(2.76
)
Average Realized Price Net of Transportation Expenses
50.73

63.57

 
52.85

59.78

Operating Expenses
(13.97
)
(11.19
)
 
(12.89
)
(10.23
)
Workover Expenses
(4.31
)
(4.97
)
 
(3.72
)
(3.40
)
Operating Netback(1)
$
32.45

$
47.41

 
$
36.24

$
46.15


(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 and nine months ended September 30, 2019 decreased 24% and 7% to $132.5 and $443.0 million, respectively. The decrease for the three months ended September 30, 2019 was a result of 18% decrease in Brent, 3 % lower sales volumes and higher quality and transportation discounts, compared with the corresponding period of 2018. The decrease for the nine months ended September 30, 2019 was a result of 11% decrease in Brent, partially offset by 6 % higher sales volumes and lower quality and transportation discounts, compared with the corresponding period of 2018. Compared with the prior quarter, oil and gas sales decreased 16% as a result of 9% decrease in Brent, 5% lower sales volumes and higher quality and transportation discount.

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


21



(Thousands of U.S. Dollars)

Third Quarter 2019 Compared with Second Quarter 2019
 
Third Quarter 2019 Compared with Third Quarter 2018
 
Nine Months Ended September 30, 2019 Compared with Nine Months Ended September 30, 2018
Oil and natural gas sales for the comparative period
$
157,993

 
$
175,118

 
$
476,792

Realized sales price decrease effect
(18,658
)
 
(36,801
)
 
(62,143
)
Sales volumes (decrease) increase effect
(6,844
)
 
(5,826
)
 
28,400

Oil and natural gas sales for the three and nine months ended September 30, 2019
$
132,491

 
$
132,491

 
$
443,049


Average realized price for the three and nine months ended September 30, 2019 decreased 22% and 12%, respectively, compared with the corresponding periods of 2018. The decrease was commensurate with the decrease in benchmark oil prices. Compared with the prior quarter, the average realized price decreased 12%.

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

 
Three Months Ended September 30,
Three Months Ended June 30,
Nine Months Ended September 30,
 
2019
2018
2019
2019
2018
Volume transported through pipeline
%
9
%
1
%
2
%
9
%
Volume sold at wellhead
54
%
37
%
51
%
48
%
39
%
Volume transported via truck to sales point
46
%
54
%
48
%
50
%
52
%
 
100
%
100
%
100
%
100
%
100
%

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

Transportation expenses for the three and nine months ended September 30, 2019 decreased 58% and 23% to $3.2 and $16.2 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, transportation expenses decreased 56% and 28% to $1.25 and $2.00, respectively, compared with the corresponding periods of 2018. Lower transportation expenses were a result of higher volumes sold at the wellhead during the three and nine months ended September 30, 2019 and a change in sales point for a portion of the Acordionero production.

For the three months ended September 30, 2019, transportation expenses decreased 35% compared with $4.9 million in the prior quarter. On a per BOE basis, transportation expenses decreased 32% from $1.83 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 nine months ended September 30, 2019 increased 21% and 33% to $35.6 and $104.1 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, operating expenses increased by $2.78 and $2.66, respectively, compared to the corresponding periods of 2018, primarily as a result of higher power generation, field operations maintenance and freight and logistics costs and lower production volumes. The Acordionero expansion and gas-to-power facilities were fully commissioned during the third quarter of 2019. These projects will allow expanded water injection and delivery of enhanced power reliability, 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, we are expecting 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. The cost reductions are expected to begin November of this year with the full benefit being realized in 2020.

22




Operating expenses for the three months ended September 30, 2019 increased by 6% compared with the prior quarter. On a per BOE basis, operating expenses for the three months ended September 30, 2019 increased by 10%, or $1.31, primarily as a result of higher power generation costs during the current quarter.

Workover expenses on per BOE basis, decreased to $4.31 for the three months ended September 30, 2019 compared to $4.97 in the corresponding period of 2018 due to lower frequency of ESP failures during the current quarter. Workover expenses increased to $3.72 for the nine months ended September 30, 2019 compared to $3.40 in the corresponding period of 2018 due to more workover activities performed during the nine months ended September 30, 2019. Workover expenses decreased by $0.48 per BOE compared to the prior quarter as a result of lower frequency of ESP failures during the third quarter of 2019.

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

$
49,812

$
51,630

 
$
164,430

$
137,698

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

19.54

19.58

 
20.35

18.06


DD&A expenses for the three months ended September 30, 2019 decreased 4% or $0.04 per BOE, compared to the corresponding period of 2018 due to allocation of proved reserves related to the Acordionero field. DD&A expenses for the nine months ended September 30, 2019 increased 19% or $2.29 per BOE, compared to the corresponding period of 2018. The increase in DD&A expenses was due to higher costs in the depletable base, partially offset by higher proved reserves related to Acordionero field and Suroriente Block, and lower production.

For the three months ended September 30, 2019 DD&A expenses decreased 4% from the prior quarter primarily due to higher proved reserves. On per BOE bases, DD&A expenses and increased $0.14 from the prior quarter due to lower sales volumes during the current quarter.

G&A Expenses

 
 
Three Months Ended September 30,
 
Three Months Ended June 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
 
2019
2018
% Change
 
2019
 
2019
2018
% Change
G&A Expenses Before Stock-Based Compensation
 
$
7,645

$
3,679

108

 
$
9,268

 
$
24,782

$
17,254

44

G&A Stock-Based Compensation (Recovery) Expense
 
(8
)
10,132

(100
)
 
(627
)
 
1,092

19,919

(95
)
G&A Expenses, Including Stock-Based Compensation
 
$
7,637

$
13,811

(45
)
 
$
8,641

 
$
25,874

$
37,173

(30
)
U.S. Dollars Per BOE Sales Volumes NAR
 
 
 
 
 
 
 
 
 
 
G&A Expenses Before Stock-Based Compensation
 
$
3.00

$
1.40

114

 
$
3.48

 
$
3.07

$
2.26

36

G&A Stock-Based Compensation (Recovery) Expense
 

3.84

(100
)
 
(0.24
)
 
0.14

2.61

(95
)
G&A Expenses, Including Stock-Based Compensation
 
$
3.00

$
5.24

(43
)
 
$
3.24

 
$
3.21

$
4.87

(34
)

For the three and nine months ended September 30, 2019, G&A expenses before stock-based compensation increased 108% and 44%, respectively, from the corresponding periods of 2018 due to lower recoveries and capitalization during 2019 periods. On a per BOE basis, G&A expenses before stock-based compensation increased 114% and 36%, from the corresponding periods of 2018. The increase was mainly a result of lower recoveries and capitalization. For the three months ended September 30, 2019,

23



G&A expenses before stock-based compensation decreased 18% (14% per BOE) from the prior quarter primarily due to higher recoveries and capitalization during the current quarter.

G&A expenses after stock-based compensation for the three and nine months ended September 30, 2019 decreased 45% and 30% (43% and 34% 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 September 30, 2019 decreased by 12% (7% 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.

Foreign Exchange Gains and Losses

For the three and nine months ended September 30, 2019, we had a $6.8 million and $5.6 million, respectively, loss on foreign exchange, compared with $0.9 million gain and $0.4 million loss, respectively, 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 nine months ended September 30, 2019 and 2018:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
2018
 
2019
2018
Change in the U.S. dollar against the Colombian peso
strengthened by
strengthened by
 
strengthened by
no change
8%
1%
 
7%
—%
Change in the U.S. dollar against the Canadian dollar
strengthened by
weakened by
 
weakened by
strengthened by
1%
2%
 
3%
3%

Financial Instrument Gains and Losses

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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
2018
 
2019
2018
Commodity price derivative loss (gain)
$
(24
)
$
929

 
$
464

$
20,384

Foreign currency derivatives loss (gain)
337

525

 
392

(1,499
)
Investment loss (gain)
11,972

(6,328
)
 
(3,746
)
(12,045
)
Financial instruments loss (gain)
$
12,285

$
(4,874
)
 
$
(2,890
)
$
6,840



24



Income Tax Expense
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)
2019
 
2018
 
2019
 
2018
Income (loss) before income tax
$
(17,312
)
 
$
57,634

 
$
57,361

 
$
149,562

 
 
 
 
 
 
 
 
Current income tax expense
$
3,049

 
$
19,108

 
$
13,923

 
$
36,224

Deferred income tax expense (recovery)
8,472

 
(36,769
)
 
31,752

 
(118
)
Total income tax expense (recovery)
$
11,521

 
$
(17,661
)
 
$
45,675

 
$
36,106

 
 
 
 
 
 
 
 
Effective tax rate
(67
)%
 
(31
)%
 
79
%
 
24
%

Current income tax expense was lower for the nine months ended September 30, 2019, compared with the corresponding period of 2018 primarily as a result of lower income and higher tax depreciation in Colombia. The deferred income tax expense of $31.8 million for the nine months ended September 30, 2019, was higher compared with the corresponding period of 2018 primarily due to the impact of the release of a portion of the valuation allowance in Colombia during 2018 and excess tax depreciation compared with accounting depreciation in Colombia during 2019.

For the nine months ended September 30, 2019, the difference between the effective tax rate of 79% and the 33% Colombian tax rate was primarily due to foreign currency translation adjustments, an increase in the valuation allowance and the impact of foreign tax rates.
 
For the nine months ended September 30, 2018, the difference between the effective tax rate of 24% and the 37% Colombian tax rate was primarily due to a decrease in the valuation allowance and other permanent differences, which was partially offset by the impact of foreign tax rates.






25



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

(Thousands of U.S. Dollars)
Third Quarter 2019 Compared with Second Quarter 2019
% change
Third Quarter 2019 Compared with Third Quarter 2018
% change
Nine Months Ended, September 30, 2019 Compared with Nine Months Ended September 30, 2018
% change
Net income for the comparative period
$
38,540

 
$
75,295

 
113,456

 
Increase (decrease) due to:
 
 
 
 
 
 
Prices
(18,658
)
 
(36,801
)
 
(62,143
)
 
Sales volumes
(6,844
)
 
(5,826
)
 
28,400

 
Expenses:
 
 
 
 
 
 
   Operating
(1,870
)
 
(6,092
)
 
(26,100
)
 
   Workover
1,778

 
2,127

 
(4,103
)
 
   Transportation
1,706

 
4,326

 
4,857

 
   Cash G&A, RSU settlements and lease payments

1,294

 
(4,392
)
 
(7,963
)
 
   Severance
130

 
864

 
933

 
   Interest, net of amortization of debt
   issuance costs
(1,747
)
 
(4,776
)
 
(10,136
)
 
   Realized foreign exchange
(1,427
)
 
(644
)
 
(51
)
 
   Settlement of financial instruments
195

 
9,756

 
23,894

 
   Current taxes
(3,538
)
 
16,059

 
22,301

 
   Interest Income
(267
)
 
(595
)
 
(1,461
)
 
Net change in funds flow from operations(1) from comparative period
(29,248
)
 
(25,994
)
 
(31,572
)
 
Expenses:


 
 
 
 
   Depletion, depreciation and accretion
1,885

 
1,818

 
(26,732
)
 
   Deferred tax
6,485

 
(45,241
)
 
(31,870
)
 
   Amortization of debt issuance costs
158

 
27

 
(245
)
 
   Non-cash lease expenses net of lease payments
329

 
283

 
237

 
   Stock-based compensation, net of
   RSU settlement
(619
)
 
10,283

 
19,025

 
   Financial instruments gain or loss, net of
   financial instruments settlements
(30,820
)
 
(26,915
)
 
(14,164
)
 
   Unrealized foreign exchange
(4,238
)
 
(7,084
)
 
(5,144
)
 
   Loss on redemption of convertible debt
(11,305
)
 
(11,305
)
 
(11,305
)
 
Net change in net income
(67,373
)
 
(104,128
)
 
(101,770
)
 
Net (loss) income for the current period
$
(28,833
)
(175
)%
$
(28,833
)
(138
)%
$
11,686

(90
)%

(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.


26



Capital expenditures during the three months ended September 30, 2019 were $116.5 million:

(Millions of U.S. Dollars)
 
Colombia:
 
Exploration
$
12.2

Development:
 
  Drilling and Completions
60.0

  Facilities
25.8

Other
17.3

 
115.3

Corporate
1.2

 
$
116.5


During the three months ended September 30, 2019, we commenced drilling the following wells in Colombia:
 
Number of wells (Gross)
Number of wells (Net)
Development
8

8

Other
6

6

Total
14

14


We spud 8 development and 6 service wells, of which ten were in the Midas Block, three were in the VMM-2 Block and one was in the Chaza Block. Of the wells spud during the quarter, 12 wells were completed, and 2 were in-progress as of September 30, 2019.

We commissioned facilities in the Acordionero Field on the Midas Block and continued facilities work in the Moqueta Field on the Chaza Block.

On February 20, 2019, we 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)
September 30, 2019
 
% Change
 
December 31, 2018
Cash and Cash Equivalents
$
13,959

 
(73
)
 
$
51,040

 
 
 
 
 
 
Current Restricted Cash and Cash Equivalents
$
676

 
(47
)
 
$
1,269

 
 
 
 
 
 
Working Capital (Deficiency), Including Cash and Cash Equivalents
$
(5,000
)
 
(115
)
 
$
33,145

 
 
 
 
 
 
Revolving Credit Facility
$
57,000

 
100

 
$

 
 
 
 
 
 
6.25% Senior Notes

$
300,000

 

 
$
300,000

 
 
 
 
 
 
7.75% Senior Notes

$
300,000

 
100

 
$

 
 
 
 
 
 
Convertible Notes
$

 
(100
)
 
$
115,000



27



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 over the next 12 months given current oil price trends and production levels. We have no near term maturities and $243.0 million available under our credit facility.

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. 

At September 30, 2019, we had $57.0 million drawn on the revolving credit facility with a syndicate of lenders with a borrowing base of $300.0 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 September 30, 2019, we had $300.0 million aggregate principal amount of 6.25% Senior Notes due 2025, and $300.0 million aggregate principal amount of 7.75% Senior Notes due 2027 outstanding.

During the quarter, we purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes, including $114,997,000 aggregate principal amount pursuant to a previously announced offer to purchase for cash all outstanding 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. We recorded $11.3 million loss on redemption including premium paid, transaction costs and $2.3 million of deferred financing fees write-off.

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 September 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.

Derivative Positions

At September 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: October 1, to December 31, 2019
5,000

ICE Brent
$
60.00

n/a

$
2.39

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

ICE Brent
$
60.00

$
71.53

n/a


Foreign Currency Derivatives

At September 30, 2019, we had outstanding 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: October 1, to December 31, 2019
67,500

19,497

COP
3,019

3,446


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


28



At September 30, 2019, our balance sheet included $1.8 million of current assets and $0.7 million of current liabilities related to the above outstanding commodity price and foreign currency derivative positions.

Cash Flows

The following table presents our primary sources and uses of cash and cash equivalents for the periods presented:
 
Nine Months Ended September 30,
(Thousands of U.S. Dollars)

2019
2018
Sources of cash and cash equivalents:
 
 
Net income
$
11,686

$
113,456

Adjustments to reconcile net income to Adjusted EBITDA(1)
 and funds flow from operations(1)
 
 
DD&A expenses
164,430

137,698

Interest expense
30,655

20,274

Income tax expense
45,675

36,106

Loss on redemption of convertible notes
11,305


Gain on investment
(3,746
)
(12,045
)
 Adjusted EBITDA
260,005

295,489

Current income tax expense
(13,923
)
(36,224
)
Contractual interest and other financing expenses
(28,081
)
(17,945
)
Stock-based compensation expense
1,092

20,477

Cash settlement of RSUs

(360
)
Unrealized foreign exchange loss
5,303

159

Financial instruments loss excluding gain on investment
856

18,885

Non-cash lease expenses
1,366


Lease payments
(1,603
)

Cash settlement of financial instruments
(2,275
)
(26,169
)
Funds flow from operations
222,740

254,312

Proceeds from bank debt, net of issuance costs
246,000

4,988

Proceeds from issuance of Senior Notes, net of issuance costs
289,298

288,087

Proceeds from issuance of shares

1,408

Changes in non-cash investing working capital
20,138

32,638

 
778,176

581,433

 
 
 
Uses of cash and cash equivalents:
 
 
Additions to property, plant and equipment
(310,579
)
(258,551
)
Additions to property, plant and equipment - property acquisitions
(77,772
)
(20,100
)
Repayment of bank debt
(304,000
)
(153,000
)
Repurchase of shares of Common Stock
(37,560
)
(1,314
)
Net changes in assets and liabilities from operating activities
(83,606
)
(40,652
)
Settlement of asset retirement obligations
(707
)
(456
)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents
(1,506
)
(402
)
 
(815,730
)
(474,475
)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents
$
(37,554
)
$
106,958

 
(1) Adjusted 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.


29



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 September 30, 2019, we had no off-balance sheet arrangements.

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 quarter, we purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes, including $114,997,000 aggregate principal amount pursuant to a previously announced offer to purchase for cash all outstanding 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.

At September 30, 2019, we had $57 million drawn under our revolving credit facility.

Except for noted above, as at September 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.




30



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.

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 September 30, 2019, our outstanding balance under revolving credit facility was $57 million (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 September 30, 2019.


31



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




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 and Part II, Item 1A Risk Factors of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019. Other than the risk factors set forth therein, there have been no material changes to our risk factors.




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
 
July 1-31, 2019
1,842,750

1.60

1,842,750

7,812,001

(3) 
August 1-31, 2019
6,401,675

1.35

6,401,675

1,410,326

(3) 
September 1-30, 2019
1,410,326

1.41

1,410,326


(3) 
 
9,654,751

1.41

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 were 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.

The 2019 Program was scheduled to expire on March 12, 2020, or earlier if the 5.00% share maximum is reached. During the three months ended September 30, 2019, we reached the maximum share repurchase limit of 19,353,951 shares and the 2019 Program expired.

32




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).
 
 
 
 
10.1*


 
Filed herewith.

 
 
 
 
31.1
 
Filed herewith.
 
 
 
 
31.2
 
Filed herewith.
 
 
 
 
32.1
 
Furnished herewith.
* Management contract or compensatory plan or arrangement.
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  Inline XBRL Taxonomy Extension Schema Document
101.CAL  Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB  Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE  Inline XBRL Taxonomy Extension Presentation Linkbase Document
104.The cover page from Gran Tierra Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, formatted in Inline XBRL (included within the Exhibit 101 attachments).



33




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: November 5, 2019
 
/s/ Gary S. Guidry
 
 
By: Gary S. Guidry
 
 
President and Chief Executive Officer
 
 
(Principal Executive Officer)
  
Date: November 5, 2019
 
/s/ Ryan Ellson
 
 
By: Ryan Ellson
 
 
Chief Financial Officer
 
 
(Principal Financial and Accounting Officer)


34